**3. The Combined Gas-Steam Turbine Cycle (GTCC)**

#### **3.1. The GTCC overview**

The exhaust gases leaving the GT can have high temperature (up to 600 ο C) and use a heat recovery steam generator (HRSG) to generate steam. This steam can operate thermally driven desalting units such as multistage flash (MSF) (Figures 15a, b)) or multi-effect thermal vapor compression (ME-TVC) desalting systems or can operate steam turbine (ST). Combination of GT, HRSG, and ST cycle forms GTCC (Figure 15c) of much higher efficiency than single-cycle PP using GT or ST. A schematic diagram of steam turbine (Rankine) cycle components that can be combined with GT is shown in Figure 16a. Large steam turbine is usually divided into high-pressure (HP), intermediate-pressure (IP), and low-pressure (LP) cylinders (Figure 16b). In GTCC, the GT cycle is called the upper cycle, the steam turbine is called the bottom cycle, and both cycles are shown on T-s diagram in Figure 17a. Modern ST power generation, as shown in Figure 16a, is based on the Rankine cycle which includes the ideal basic cycle processes of (a) isentropic expansion in the steam turbine (ST) from 3-4 and from 5-6; (b) condensation of the steam discharged from the ST in the condenser from 6-1; (c) reversible adiabatic pumping process of condensate from condensing to the HRSG pressures, 1-2; and (d) heat addition at constant pressure in the steam generator (SG) to raise feedwater to saturation temperature, evaporate it, and superheat it from 2-3. In reheat steam cycle, the steam leaving the HP section returns to the SG from 4-5 for further heating before being admitted to the IP cylinder. Reheat is sometimes necessary to raise the steam dryness fraction at the turbine exit than the minimum of 0.88 required by the industry to avoid the blades pitting and raise the efficiency of the LP cylinder.

The use of GTCC to produce both EP gives high-energy utilization factor (UF), up to 80 %, where

$$\text{UF} = \left( \text{Work output} + \text{process heat} \right) / \text{fuel heat supplied}$$

The GTCC is usually used for baseload operations because of its high efficiency. The HRSG can have single-, double-, or triple-pressure stages. The HRSG of single and double-pressure stages and their temperature distribution are shown in Figure 17b. A bottoming steam cycle using double-pressure steam HRSG is shown in Figure 18a. A triple-pressure stage HRSG is shown in Figure 18b. Several differences exist between the steam PP cycle using conventional steam generator (SG) (Figure 19a) and steam cycle in the GTCC (Figure 19b) using HRSG of the GT. The ST plant in Figure 19a has 300 MW electric power (EP) output capacity, using reheat cycle where steam leaving the HP cylinder is reheated in the SG before its introduction to the IP cylinder. This cycle has five closed feed heaters and one open feed heater (deaerator), and the steam flow rate leaving the condenser is 197.86 kg/s, about 76 % that of throttling condition (261.1 kg/s).

*2.3.4. GT turbine*

146 Desalination Updates

the GT are high enough to generate steam.

**3.1. The GTCC overview**

the efficiency of the LP cylinder.

where

**3. The Combined Gas-Steam Turbine Cycle (GTCC)**

The exhaust gases leaving the GT can have high temperature (up to 600 ο

recovery steam generator (HRSG) to generate steam. This steam can operate thermally driven desalting units such as multistage flash (MSF) (Figures 15a, b)) or multi-effect thermal vapor compression (ME-TVC) desalting systems or can operate steam turbine (ST). Combination of GT, HRSG, and ST cycle forms GTCC (Figure 15c) of much higher efficiency than single-cycle PP using GT or ST. A schematic diagram of steam turbine (Rankine) cycle components that can be combined with GT is shown in Figure 16a. Large steam turbine is usually divided into high-pressure (HP), intermediate-pressure (IP), and low-pressure (LP) cylinders (Figure 16b). In GTCC, the GT cycle is called the upper cycle, the steam turbine is called the bottom cycle, and both cycles are shown on T-s diagram in Figure 17a. Modern ST power generation, as shown in Figure 16a, is based on the Rankine cycle which includes the ideal basic cycle processes of (a) isentropic expansion in the steam turbine (ST) from 3-4 and from 5-6; (b) condensation of the steam discharged from the ST in the condenser from 6-1; (c) reversible adiabatic pumping process of condensate from condensing to the HRSG pressures, 1-2; and (d) heat addition at constant pressure in the steam generator (SG) to raise feedwater to saturation temperature, evaporate it, and superheat it from 2-3. In reheat steam cycle, the steam leaving the HP section returns to the SG from 4-5 for further heating before being admitted to the IP cylinder. Reheat is sometimes necessary to raise the steam dryness fraction at the turbine exit than the minimum of 0.88 required by the industry to avoid the blades pitting and raise

The use of GTCC to produce both EP gives high-energy utilization factor (UF), up to 80 %,

UF = Work output + process heat /fuel heat supplied ( )

C) and use a heat

The hot gases produced in the combustor are expanded in the turbine (Figures 14a–d) to give mechanical energy that operates the compressor, and the balance produces the electric power (EP). The turbine, similar to the compressor, can be axial or centrifugal type. The axial type is easier to cool, as the turbine is exposed to high thermal stresses by the hot gases entering the turbine. The turbine cooling is crucial as it provides the potential of raising the TIT and thus the efficiency. Gas turbines can be particularly efficient when heat content of the hot gases from the turbine is recovered in HRSG to power a conventional ST in GTCC. The hot gases from the GT can also be used for space or water heating or drive an absorption chiller for cooling the inlet air and increase the power output. Figure 14d shows that the hot gases leaving

**Figure 15.** a: Two GTs conned to two HRSGs generating steam to operate two MSFs and using standby boiler [21] b: Three GTs conned to two HRSGs generating steam to operate three MSFs and using auxiliary burners to operate the HRSG [21] c: GTCC with GT, HRSG, and steam turbine (ST)

(d)

(c) (d) **Figure 16.** a: Schematic steam turbine (Rankine) using high-pressure (HP), intermediate-pressure (IP), and low-pres‐ sure (LP) cylinders b: Steam turbine with HP, IP, and LP cylinders

(d) **Figure 17.** a: Upper GT turbine cycle (Brayton) and bottom Rankine steam cycle. b: HRSG of dual pressure in the mid‐ dle and single pressure at the bottom steam stages and their temperature distribution [20]

Cogeneration Power-Desalting Plants Using Gas Turbine Combined Cycle http://dx.doi.org/10.5772/60209 149

(a)

T

1

a

2

sure (LP) cylinders b: Steam turbine with HP, IP, and LP cylinders

148 Desalination Updates

(c) (d)

**Figure 16.** a: Schematic steam turbine (Rankine) using high-pressure (HP), intermediate-pressure (IP), and low-pres‐

Brayton Cycle

> b b'

> > (a)

Rankine Cycle

f e

c d

3

S

4

(b) (d)

**Figure 17.** a: Upper GT turbine cycle (Brayton) and bottom Rankine steam cycle. b: HRSG of dual pressure in the mid‐

dle and single pressure at the bottom steam stages and their temperature distribution [20]

(b)

**Figure 18.** a: Bottom steam cycle with dual-pressure steam stages HRSG [ (d) 1] b: GTCC using triple-pressure steam HRSG [23]

The ST cycle shown in Figure 19b and with data given in Table 3 is also a reheat cycle of 275 MW output capacity. It utilizes the hot gases leaving three GTs of 164 MW of EP output each. Contrary to the cycle in Figure 19a, the cycle using the HRSG has no feed heaters as all feedwater heating is done in the HRSG, and thus, the steam flow rate leaving the condenser is 438.8 kg/s, about 123.3 % that of throttling condition (355.3 kg/s), and the steam to the ST is admitted from the three stages HRSG to the ST at three points (pressures); see Figures 19a,b .

(d) **Figure 19.** a: Conventional steam power plant operated by fuel-operated steam generator. b: Combined GTCC using 3 GT, 3 HRSG, and one steam turbine [5]

**Table 3.** Data of the GTCC given in Figure 19b [5]

#### **3.2. Steam turbines in GTCC**

The ST cycle shown in Figure 19b and with data given in Table 3 is also a reheat cycle of 275 MW output capacity. It utilizes the hot gases leaving three GTs of 164 MW of EP output each. Contrary to the cycle in Figure 19a, the cycle using the HRSG has no feed heaters as all feedwater heating is done in the HRSG, and thus, the steam flow rate leaving the condenser is 438.8 kg/s, about 123.3 % that of throttling condition (355.3 kg/s), and the steam to the ST is admitted from the three stages HRSG to the ST at three points (pressures); see Figures 19a,b .

(a)

(b)

(d) **Figure 19.** a: Conventional steam power plant operated by fuel-operated steam generator. b: Combined GTCC using 3

GT, 3 HRSG, and one steam turbine [5]

150 Desalination Updates

The steam turbine in the GTCC can be extraction-condensing steam turbine (ECST) (Figure 20a) or back pressure steam turbine (BPST) (Figure 20b). In the ECST, steam is expanded from inlet pressure (say at 100 bar) and high temperature (up to 538 ο C) to the condenser pressure (about 10 kPa) below atmospheric pressure. As steam expands, its pressure and temperature decrease, while its specific volume and its volumetric flow rate increase. This requires increasing the blade length of the turbine as steam expands to accommodate the increased volumetric steam flow (Figure 20c). In large-scale steam turbines, the steam volumetric flow is limited by the size of the turbine last stages (see Figure 16b), and this can enforce the use of double-flow condensing steam turbine where the last stage flow is divided between two rows of blades.

In BPST, the steam exits the turbine at the pressure required by the process to be heated as desalination, say 2–3 bar and is higher than that in the end condenser of the ECST cycle, say at 10 kPa. Condensation of discharged steam in industrial processes provides process heat needed for desalination, heating, absorption cooling, or any other processes.

The steam expansion in the ST is usually represented on the enthalpy-entropy (called Mollier chart) as turbine line shown in Figure 21a. For an adiabatic process, the change in enthalpy *Δh* is equal to the specific work, w per kg of flowing steam. The steam line on the *h-s* diagram would be a vertical line in reversible (ideal) expansion. The entropy increases during expansion in actual adiabatic process on a Mollier chart. The end point of the irreversible process still lies on that constant-pressure line corresponding to the exhaust pressure. Figure 21a shows that an increase in entropy during expansion decreases the work output, since the change *Δh(actual)*  is less than *Δh(isentropic)* as the isentropic efficiency defined by: η(isentropic) = Δh(actual)/ Δh(isentropic) <1.

**Figure 20.** a: GTCC with GT, HRSG, and using extraction condensing steam turbine (ECST) [21] b: GTCC with GT, HRSG, and using back pressure steam turbine (BPST) and standby boiler [21] c: The new last stage buckets come in two sizes – 85 cm and 1.21 m [24]

One of the main concerns in the design of the ST is its exhaust size selection discharging to the condenser. Lowering the condenser pressure allows more expansion of the steam in the ST, i.e., more decrease in the enthalpy *∆h* that is transferred to work. However, decreasing the pressure increases the steam specific volume, thus increasing the steam velocity and increasing the kinetic energy loss of the steam as it leaves the turbine to condenser at almost zero velocity. Figure 21a shows that for the turbine line ABC on the h-s diagram, the exit steam dryness fraction is about 0.84, which is less than 0.88 and not acceptable. Once reheating is done, line ED, the dryness fraction increases to 0.92, which is acceptable. Figure 21b illustrates the exhaust loss curve for a condensing steam turbine. The exhaust area for a particular application should provide a balance between exhaust loss and capital investment in turbine equipment.

Some of the GTCC mount the GT and ST on the same shaft (Figures 22a, b). Since the steam turbine comes to operation after heating up the whole steam cycle, a freewheel clutch is installed between the steam turbine and the generator to prevent the GT from spinning up the steam turbine in a cold steam cycle. Due to the freewheel clutch, the shafts of the gas turbine Cogeneration Power-Desalting Plants Using Gas Turbine Combined Cycle http://dx.doi.org/10.5772/60209 153

(c) **Figure 21.** a: Enthalpy-entropy diagram for a steam turbine [25] b: Illustrative exhaust loss curve [25]

is less than *Δh(isentropic)* as the isentropic efficiency defined by: η(isentropic) = Δh(actual)/

(c)

**Figure 20.** a: GTCC with GT, HRSG, and using extraction condensing steam turbine (ECST) [21] b: GTCC with GT, HRSG, and using back pressure steam turbine (BPST) and standby boiler [21] c: The new last stage buckets come in

One of the main concerns in the design of the ST is its exhaust size selection discharging to the condenser. Lowering the condenser pressure allows more expansion of the steam in the ST, i.e., more decrease in the enthalpy *∆h* that is transferred to work. However, decreasing the pressure increases the steam specific volume, thus increasing the steam velocity and increasing the kinetic energy loss of the steam as it leaves the turbine to condenser at almost zero velocity. Figure 21a shows that for the turbine line ABC on the h-s diagram, the exit steam dryness fraction is about 0.84, which is less than 0.88 and not acceptable. Once reheating is done, line ED, the dryness fraction increases to 0.92, which is acceptable. Figure 21b illustrates the exhaust loss curve for a condensing steam turbine. The exhaust area for a particular application should

provide a balance between exhaust loss and capital investment in turbine equipment.

Some of the GTCC mount the GT and ST on the same shaft (Figures 22a, b). Since the steam turbine comes to operation after heating up the whole steam cycle, a freewheel clutch is installed between the steam turbine and the generator to prevent the GT from spinning up the steam turbine in a cold steam cycle. Due to the freewheel clutch, the shafts of the gas turbine

(b)

Δh(isentropic) <1.

152 Desalination Updates

(a)

two sizes – 85 cm and 1.21 m [24]

and the steam turbine are spinning up separately, which prevents them from reaching speed ranges that would cause dangerous resonance frequencies. As soon as the boiler is heated up to operation temperature, the control valve is opened and the steam turbine provides its part of power to drive the generator [23].

Figure 22a shows the ST mounted on the same shaft of the GT and both use the same generator, one GT and one ST of single- and double-flow LP cylinders as developed by GE. In addition, the steam turbine can be combined with single GT but with separate shafts or several gas turbines and one ST and several shafts as shown in Figures 22a, b.

**Figure 22.** a: S107H and S109H single-shaft steam turbine and GT (STAG) equipment configuration [26] b: STAG 107H/ 109H cycle diagram [26]

(c)

#### **3.3. Cogeneration steam turbine**

Steam can be extracted from ST for processing heat by using a nonautomatic extraction ST that has openings in the turbine casing for steam extraction, with no means for controlling the pressure of the extracted steam. Steam can also be extracted from an automatic extraction steam turbine with openings in the turbine casing for extraction and means for directly regulating the steam flow to the next turbine stages after extraction opening. Automatic extraction turbines are used when there is a need for process steam at specific pressure between turbine inlet and outlet pressures, as in the case of desalination. There is simultaneous control of the desired extraction steam pressure and turbine speed, even though the demand for extraction steam and the power requirements of the driven load may vary over a wide range. Also an induction-extraction ST that can admit and exhaust steam. In extraction condensing steam turbine (ECST), the steam or part of it exits the turbine at a given pressure and may further be used. The 300 MW steam turbine operating in Kuwait provides full steam demand to two MSF desalting units of 7.2 MIGD each when the turbine EP load varies between 300 and 75 MW.

In Kuwait CPDP, the MSF unit gain ratio defined by desalted water (DW) output to heating supply S (i.e., D/S) has a typical value of 8, and the steam pressure at extraction point to the MSF at full load is 3.5 bar and is throttled to the pressure required by the MSF of 2 bar. When the turbine load is lowered, the steam pressure throughout the turbine is also lowered and reaches about 2 bar at the MSF extraction point when the turbine load is 25 % of the 300 MW nominal load. So, a throttling valve between the extraction point and the MSF is installed to keep the pressure to the MSF plant at 2 bar (Figure 19a). If the steam at the extraction point is less than 2 bar, extraction to the MSF is stopped. In this case, if the MSF can work directly from the high pressure steam supply to the turbine after being throttled and desuperheated (Figures 23a, b).

Steam condensation in the DP provides the steam latent heat as the heating source to the DP. The specific work produced by expanding steam from throttling condition of P1 and T1 to the condenser pressure Po and To is represented by the area encircled by ABCDA in Figure 24a and the area BEFC, represents the specific rejected heat. When steam is extracted at P3 to the DP, the specific work per kg of steam is represented by AGHD in Figure 23b, and the area GBCH is the work loss for each kg extracted to the DP. In the Kuwaiti plant, the steam to the MSF unit is extracted from crossover pipe between the intermediate-pressure (IP) and the LP cylinders (Figure 23b). So, the ratio of power to water outputs in CPDP varies as the EP load is always variable and cannot be stored, while water depends on the demand and available storage capacity. So, the EP and DW production ratio is not always constant or matched together.

(c) **Figure 23.** a: Case 1. HP-LP cylinder features for steam extraction from turbine casing [28] b: Case 2. HP-LP cylinder features for steam extraction from crossover pipe between IP and LP cylinders [28]

Steam condensation in the DP provides the steam latent heat as the heating source to the DP. The specific work produced by expanding steam from throttling condition of P1 and T1 to the condenser pressure Po and To is represented by the area encircled by ABCDA in Figure 24a and the area BEFC, the rejected heat. When steam is extracted at P3 as in Figure 24b to the DP, the specific work per kg of steam is represented by AGHD in Figure 24b, and the area GBCH is the work loss for each kg extracted to the DP.

It is noticed here that in BPST, the steam flow to the turbine depends on the turbine load, and thus, the steam discharged to the DP is slave to the turbine load. So, BPST is usually used in baseload operation, and steam to the DP can be supplied from HP steam line, which is very expensive.

(c) **Figure 24.** Enthalpy-entropy diagram for a steam cycle of (a) power-only plant and (b) dual-purpose plant [23]

#### **3.4. Heat Recovery System Generator (HRSG)**

**3.3. Cogeneration steam turbine**

154 Desalination Updates

together.

(a)

features for steam extraction from crossover pipe between IP and LP cylinders [28]

Steam can be extracted from ST for processing heat by using a nonautomatic extraction ST that has openings in the turbine casing for steam extraction, with no means for controlling the pressure of the extracted steam. Steam can also be extracted from an automatic extraction steam turbine with openings in the turbine casing for extraction and means for directly regulating the steam flow to the next turbine stages after extraction opening. Automatic extraction turbines are used when there is a need for process steam at specific pressure between turbine inlet and outlet pressures, as in the case of desalination. There is simultaneous control of the desired extraction steam pressure and turbine speed, even though the demand for extraction steam and the power requirements of the driven load may vary over a wide range. Also an induction-extraction ST that can admit and exhaust steam. In extraction condensing steam turbine (ECST), the steam or part of it exits the turbine at a given pressure and may further be used. The 300 MW steam turbine operating in Kuwait provides full steam demand to two MSF desalting units of 7.2 MIGD each when the turbine EP load varies between 300 and 75 MW.

In Kuwait CPDP, the MSF unit gain ratio defined by desalted water (DW) output to heating supply S (i.e., D/S) has a typical value of 8, and the steam pressure at extraction point to the MSF at full load is 3.5 bar and is throttled to the pressure required by the MSF of 2 bar. When the turbine load is lowered, the steam pressure throughout the turbine is also lowered and reaches about 2 bar at the MSF extraction point when the turbine load is 25 % of the 300 MW nominal load. So, a throttling valve between the extraction point and the MSF is installed to keep the pressure to the MSF plant at 2 bar (Figure 19a). If the steam at the extraction point is less than 2 bar, extraction to the MSF is stopped. In this case, if the MSF can work directly from the high pressure steam supply to the turbine after being throttled and desuperheated (Figures 23a, b). Steam condensation in the DP provides the steam latent heat as the heating source to the DP. The specific work produced by expanding steam from throttling condition of P1 and T1 to the condenser pressure Po and To is represented by the area encircled by ABCDA in Figure 24a and the area BEFC, represents the specific rejected heat. When steam is extracted at P3 to the DP, the specific work per kg of steam is represented by AGHD in Figure 23b, and the area GBCH is the work loss for each kg extracted to the DP. In the Kuwaiti plant, the steam to the MSF unit is extracted from crossover pipe between the intermediate-pressure (IP) and the LP cylinders (Figure 23b). So, the ratio of power to water outputs in CPDP varies as the EP load is always variable and cannot be stored, while water depends on the demand and available storage capacity. So, the EP and DW production ratio is not always constant or matched

(c)

**Figure 23.** a: Case 1. HP-LP cylinder features for steam extraction from turbine casing [28] b: Case 2. HP-LP cylinder

(b)

The HRSGs utilize the hot gases leaving the GT to generate steam that can be used to operate thermally driven desalting plants or steam turbines bottoming power cycle. The HRSG can be unfired, supplementary fired or called post-fired (PF), and fully fired. The HRSG can be horizontal or vertical (Figures 25a–d). As given before, the HRSG can have single-, dual-, or triple-pressure level type. The single-pressure stage HRSG has low efficiency, compared to dual-pressure HRSG. In single-pressure HRSG, high efficiency is attained by lowering the stack temperature, and this requires lowering the steam pressure. Lowering the steam pressure lowers the steam cycle efficiency. In dual-pressure designs, lowering stack temperatures would only decrease the first (low)-stage pressure while leaving the second state conditions approximately unchanged. A design parameter of the HRSG is the pinch point (pp), which is the temperature difference between the gas leaving the boiling section and generated steam saturation (or boiling) temperature. The choice of high pp increases the mean temperature difference between the hot gases and water and reduces the heat transfer area but decreases to a certain extent the HRSG efficiency. The low-pressure (LP) generated steam in dualpressure HRSG can feed the steam turbine at a suitable point or it may be used as process steam for industrial applications (drying, desalination, absorption refrigeration, etc.).

In CPDP, electricity and process heat for desalination are simultaneously produced regardless of gas turbine load; supplementary firing or post-firing (PF) is usually used. In Ras Laffan B CPDP, a very flexible plant design was developed with PF to allow very high thermal power input (maximum 280 MWth) to cope with a wide operational range of GT electrical power and steam production for electricity or desalinated water production. The power island having a total capacity of 1025 MW is equipped with three V943A gas turbines with bypass stack to allow open-cycle operation, three HRSGSs equipped with double PF firing, and two 200 MW range backpressure steam turbines; steam from the power island is fed to four desalination units supplied by Doosan for a total water production of 273,000 m3 per day. Each GT has 310 MW power output at generator terminals, 39.8 % efficiency, and 750 kg/s exhaust gas mass flow rate at 576 °C exhaust gas temperature.

The HRSGs are of the horizontal gas flow, top supported, natural circulation type, with singlepressure stages, and two-staged supplementary firing. The HRSG steam parameters at full GT load are pressure = 85.4 bar and temperature = 563 °C, 636 t/h nominal, and 703 maximum steam flow.

The post-firing modified the steam flow as follows: first firing increased the steam flow to nominal 110 t/h and maximum 145 t/h, and second firing increased the steam flow rate to nominal 150 t/h and 170 t/h.


**5. Conclusions**

Within a relatively short period of emergence the implantation of left ventricular assist devices have made a huge impact in treatment of end-stage heart failure patients. The development of a new treatment method inevitably brings with it new challenges that limit its spectrum of utilisation. LVAD specific challenges which represent the limiting factors are mainly driveline infections, anticoagulation balances, cerebral incidents and right ventricular dysfunction. We can be optimistic that current research will lead to progress in tackling of these challenges so that we will be able to claim that this therapy method represents a first line management plan for HF patients. Notwithstanding the recent encouraging attempts of widening the donor pool to donation after circulatory death, the number of heart transplantation worldwide has reached a plateau and is only available to very few select types of patients. The prospect of much improved mechanical support methods for the circulation with better manageability represents a real hope for patients in wider age spectrum as well as in earlier phases of disease progression. Sooner or later MCS Systems that are available off the shelf and adaptable to each patients needs have the potential to replace heart transplantation for end-stage heart failure. However we may want to mention here that in parallel there are endeavours in bioengineering and gene-manipulation which could allow speculations into the 'off-the-shelf' availability of authentic spare organs for each person.


*3.5. Domain Analysis and Physio-Chemical Properties*

The modular structure and the functional domains of HSFs have been studied and described extensively [22]. The HSF-type DBD was highly conserved and consisted of approximately 100 amino acids (Figure 6). The locations of DBD and OD were predicted using SMART and MARCOIL (Table 5). The DBD of most maize HSFs was located at the beginning of the N-terminal. Few exceptions were *Zm*HSF-03, *Zm*HSF-10, *Zm*HSF-14, and *Zm*HSF-15. As expected, the linker length between DBD and OD of HSFBs was larger than HSFAs and HSFCs.

The physio-chemical properties of HSFs such as amino acid length, Mw, and pI were investigated using Expasy (Table 5). In addition, the amino acid composition of each group was analyzed using the online tool CoPId (Table S3). The amino acid length of class A HSF ranged from 350 (*Zm*HSF-23) to 528 (*Zm*HSF-14), for class B, 298 (*Zm*HSF-08) to 414 (*Zm*HSF-03), and in class C the amino acid length ranged from 257 (*Zm*HSF-13) to 348 (*Zm*HSF-21). The pI of class A HSFs ranged from 4.70 (*Zm*HSF-17) to 8.87 (*Zm*HSF-10). For class B it varied from 5.00 (*Zm*HSF-19) to 9.53 (*Zm*HSF-18), and for class C, pI ranged from 5.85 (*Zm*HSF-13) to 8.09 (*Zm*HSF-21). For class A, the Mw varied from 38.154 (*Zm*HSF-23) to 58.138 (*Zm*HSF-14), for class B it ranged from 33.258 (*Zm*HSF-18) to 44.381 (*Zm*HSF-03). While for class C HSFs, Mw ranged from 27.836 (*Zm*HSF-13) to 37.409 (*Zm*HSF-21). In general, the pI of class A HSFs was in acidic ranges except for *Zm*HSF-10, which was shown to be in a slightly basic range. The pI of class B was in slightly acidic and basic ranges. Finally, for class C the pI was in similar ranges as class B HSFs. The average amino acid composition of *Zm*HSFs ranged from 1.1 (cysteine) to 10.0 (alanine) (Figure 7A). The average amino acid composition of class A HSFs ranged from 0.8 (cysteine) to 8.7 (alanine) (Figure 7B). In contrast, the average amino acid composition of class B ranged from 1.3 (tryptophan) to 12.6 (alanine) (Figure 7C). Finally, the class C amino acid composition ranged from 1.1 (tryptophan) to 11.2 (alanine) (Figure 7D).

**Figure 6.** Multiple sequence alignment of maize HSFs. The highly conserved DBD consists of four antiparallel β-stranded sheets (β1, β2, β3, β4) and a bundle of three α-helices (α1, α2, α3) which form the secondary structure. Rectangular boxes represent α-helices while square boxes represent β-stranded sheets.

**Figure 7.** (**A**) The overall amino acid composition of maize HSFs, (**B**) class A HSFs, (**C**) class B HSFs, and (**D**) class C HSFs.