Integrated gasification combined cycle igcc technologies 1st edition ting wang

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Integrated Gasification Combined Cycle (IGCC) Technologies

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Clean Coal Engineering Technology (ISBN 978-1-85617-710-8)

Advanced Gas Turbine Cycles (ISBN 978-0-08-044273-0)

Integrated Gasification Combined Cycle (IGCC) Technologies

Edited By

Ting Wang

Gary Stiegel

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Typeset by MPS Limited, Chennai, India

3

Luca Mancuso and Silvio Arienti

3.1

3.2

3.3

3.4

3.5

5

Francesco

4.1

4.2

4.3

4.4

and Pietro Bartocci

Veena Subramanyam and Alex Gorodetsky

5.1

5.2

5.3

5.4

5.5

6.5

6.6

6.7

6.8

6.9

8.13

Giovanni Lozza

9.1

Herbert M. Kosstrin

Debangsu Bhattacharyya, Richard Turton and Stephen E. Zitney

Claudio Allevi and Guido Collodi

16

Arroyo Torralvo, Constantino Fernández Pereira and Oriol Font Piqueras

15.7

18

16.7 Results of the IGCC plant model

Stephen E. Zitney, Debangsu Bhattacharyya and Richard Turton

17.1 Introduction

17.2 Development of an IGCC dynamic simulator with an operator training system (OTS)

17.3 Capabilities, features, and architecture of the IGCC dynamic simulator and OTS 675

17.4 3D virtual plant and immersive training system 681

17.5 Capabilities, features, and architecture of the IGCC 3D virtual plant and ITS

17.6 Leveraging the IGCC dynamic simulator and 3D virtual plant in advanced research

17.7 Using the IGCC OTS and ITS in engineering education and industry workforce training

17.8 Conclusions

Phil Amick

18.1

19 Case study: Nuon–Buggenum, The

Loek Schoenmakers

20 Case Study: ELCOGAS Puertollano IGCC power plant, Spain

P. Casero, P. Coca, F. García-Peña and N. Hervás

20.5

21

Claudio Allevi and Guido Collodi

Diane R. Madden

23.6

24.3

List of Contributors

Claudio Allevi SARAS, Milano, Italy

Phil Amick Hard Carbon Consulting, LLC, Pearland, TX, United States

Silvio Arienti Amec Foster Wheeler, Corsico, Milano, Italy

Fátima Arroyo Torralvo ETSI-Universidad de Sevilla, Seville, Spain

Testuji Asano Joban Joint Power Co., Ltd., Iwaki-shi, Fukushima-ken, Japan

Pietro Bartocci University of Perugia, Perugia, Italy

Omar M. Basha University of Pittsburgh, Pittsburgh, PA, United States

Debangsu Bhattacharyya West Virginia University, Morgantown, WV, United States

Steven M. Carpenter Enhanced Oil Recovery Institute, Laramie, WY, United States

P. Casero ELCOGAS, Puertollano, Spain

P. Coca ELCOGAS, Puertollano, Spain

Guido Collodi Amec Foster Wheeler, Milano, Italy

Francesco Fantozzi University of Perugia, Perugia, Italy

He Fen Shell

Constantino Fernández Pereira ETSI-Universidad de Sevilla, Seville, Spain

Thomas H. Fletcher Brigham Young University, Provo, UT, United States

Oriol Font Piqueras Consejo Superior de Investigaciones Científicas (CSIC), Seville, Spain

F. García-Peña ELCOGAS, Puertollano, Spain

Alex Gorodetsky Alter NRG Corp., Calgary, AB, Canada

Dr. David Gray Noblis (Retired)

N. Hervás Universidad de Castilla-La Mancha, Ciudad Real, Spain

Herbert M. Kosstrin Leidos Engineering, L.L.C

Vijayaragavan Krishnamoorthy The Pennsylvania State University, University Park, PA, United States

Henry A. Long III University of New Orleans, New Orleans, LA, United States; Energy Conversation and Conservation Center

Giovanni Lozza Politecnico di Milano, Milano, Italy

Diane R. Madden National Energy Technology Laboratory, Pittsburgh, PA, United States

Luca Mancuso Amec Foster Wheeler, Corsico, Milano, Italy

Bernd Meyer Institute of Energy Process Engineering and Chemical Engineering (IEC), Freiberg, Germany

Badie Morsi University of Pittsburgh, Pittsburgh, PA, United States

Mustafa Ozer University of Pittsburgh, Pittsburgh, PA, United States; Istanbul Technical University, Maslak, Istanbul, Turkey

Sarma V. Pisupati The Pennsylvania State University, University Park, PA, United States

Loek Schoenmakers Nunhem, Limburg, The Netherlands

Gary Stiegel Pittsburgh, PA, United States

Veena Subramanyam Alter NRG Corp., Calgary, AB, Canada

Richard Turton West Virginia University, Morgantown, WV, United States

Rob van den Berg Shell

Ting Wang University of New Orleans, New Orleans, LA, United States

Christian Wolfersdorf Institute of Energy Process Engineering and Chemical Engineering (IEC), Freiberg, Germany

Stephen E. Zitney West Virginia University, Morgantown, WV, United States; Morgantown, WV, United States

An overview of IGCC systems

Ting Wang

University of New Orleans, New Orleans, LA, United States

1.1 Introduction of IGCC

IGCC is an acronym for Integrated Gasification Combined Cycle. The major purpose of IGCC is to use hydrocarbon fuels in solid or liquid phases to produce electrical power in a cleaner and more efficient way via gasification, compared to directly combusting the fuels. The hydrocarbon fuels typically include coal, biomass, refinery bottom residues (such as petroleum coke, asphalt, visbreaker tar, etc.), and municipal wastes. The approach to achieve a “cleaner” production of power is to convert solid/liquid fuels to gas first, so that they can be cleaned before they are burned by removing mainly particulates, sulfur, mercury, and other trace elements. The cleaned gas, called synthetic or synthesis gas (syngas), which primarily consists of carbon monoxide (CO) and hydrogen (H2), can then be sent to a conventional combined cycle to produce electricity. A simplified IGCC process diagram comprising three major “islands”—gasification, gas cleanup, and power—is shown in Fig. 1.1. The ultimate goal for IGCC is to achieve a lower cost of electricity (COE) than conventional pulverized coal (PC) power plants and/or to be competitive with natural gas-fired combined-cycle systems with comparable emissions.

While “clean” power generation is the primary driving motivation for entering the business of IGCC, “increasing plant efficiency” to a level higher than that of PC plants is the second driving motivation. To achieve higher efficiency, “integration” between sub-systems becomes necessary. Integration consists of all aspects of the operation, including mechanical, thermal, and dynamic process control. For example, mechanical integration can be achieved between the compressor of the gas turbine (GT) and the air separation unit (ASU), aiming to save some compression power.

Thermal integration can be implemented by strategically interconnecting the various grades of steam generated during the syngas cooling, gas cleanup, and/or watergas shift processes with the heat recovery steam generator (HRSG) and the steam turbine system. Full air integration does enhance the overall plant efficiency positively by about three to four percentage points, but it also increases the complexity of construction, operation, and maintenance, which may result in increased potential for construction phase delay and/or cost overrun, increased maintenance, lost availability, and degraded reliability. Thus, the concept of nonintegrated IGCC has been advocated by some developers to trade reduced efficiency for higher availability and reliability, even though the term “nonintegrated IGCC” could be confusing.

When the potential of global warming became a concern, the emission of carbon dioxide (CO2)—a greenhouse gas (GHG)—from power plants was subjected to

http://dx.doi.org/10.1016/B978-0-08-100167-7.00001-9

stringent scrutinization and regulations. Usually, there are three ways to reduce CO2 emissions: by increasing the overall system efficiency, capturing a portion of the CO2 and sequestering it, called CCS (Carbon Capture and Sequestration), or utilizing the captured CO2 multiple times. The syngas generated via the gasification process can be more readily separated into highly concentrated H2 and CO2 through the water-gas shift (WGS) process (to be explained later) before the combustion stage (i.e., precombustion) in an IGCC system, as opposed to PC power plants, which have to use a post-combustion carbon capture method. It is significantly cheaper to perform precombustion carbon capture in an IGCC system than post-combustion carbon capture in a PC power plant due to the nature of the processes involved and the reduced size of equipment. CCS imposes a severe penalty on power output, plant efficiency, and COE.

The objective of this chapter is to provide an introduction of the complete IGCC system, allowing readers quickly to obtain an overall view of the IGCC system, leaving the details in each subsequent chapters, each focusing on a specific subject. Although the gasification process can be applied to various carbon fuels, since the major developments and applications have involved coal, the descriptions and explanations in this chapter are written with coal in mind as the major feedstock unless specified

Figure 1.1 Simplified block diagram of an IGCC system.

1.2 Layouts of key IGCC components and processes

For the convenience of explaining the IGCC systems with information of some of the flow’s thermodynamic properties, the flow system diagrams obtained from an academic simulation of an IGCC plant are used. The simulation was performed using the commercial software, GT Pro, a part of the program suite, Thermoflow. The plant was designed to generate about 240 MWe of net power output, using Texas lignite as feedstock. The results of these simulated IGCC plants have been documented by Wang and Long (2012a, 2012b, and 2014). Two systems were simulated in Wang and Long’s papers. The result of the one with a lower steam turbine inlet pressure (1100 psi/76 bar) and temperature (538°C/1000°F) is used in this chapter. Fig. 1.2 shows the general layout of the baseline case with and without CCS.

The feedstock is the South Hallsville Texas Lignite with a feeding rate of 4308 tons/day. The reason of using the Texas Lignite is because the simulate plant is located in Louisiana and Texas Lignite is close by. The coal is mixed with 35% water by weight to form a slurry, which is injected into a GE entrained flow gasifier together with 95% pure oxygen provided by the air separation unit (ASU). The syngas coming out of the gasifier needs to be cooled down to meet the operating conditions of the currently available gas cleanup system. Typically, either a radiant syngas cooler or a quench cooling method can be used, followed by several traditional convective heat exchanger coolers. The gas cleanup system consists of a scrubber to remove particulates and other soluble contaminants, such as hydrogen cyanide (HCN), ammonia (NH3), and hydrochloric acid (HCl). The slight amount of carbonyl sulfide (COS) in the syngas is converted to hydrogen sulfide (H2S) through COS hydrolysis. The syngas needs to be further cooled down to near the ambient temperature before it enters the Acid Gas Removal (AGR) unit. The heat released from the cooling process between the exit of the gasifier and the inlet of the AGR unit is used to generate superheated steam and hot water at various pressures.

The cleaned syngas is sent to the GT to generate electricity. The exhaust of the GT is at about 593°C (1100°F), which has sufficient energy to generate steam through a Heat Recovery Steam Generator (HRSG). The steam generated through the HRSG is combined with steam generated through the syngas cooling process to drive a steam turbine and generate additional electricity. This is identical to a conventional combined cycle. In this example here, a GE quench-type gasifier is used. The power block consists of a single GT, modeled after the Siemens SGT6-4000F turbine, with steam injection in the combustor to reduce NOx formation, and a single ST, with a fixed steam inlet pressure and temperature of 1100 psi (76 bar) and 538°C (1000°F), respectively. The steam is reheated to 538°C (1000°F) at 174.5 psi (11.87 bar) to increase the output power and efficiency of the bottom steam cycle. The plant is designed exclusively for power generation, so no chemicals or energy gases are exported anywhere in the middle of cleanup. If carbon capture is needed in a system that was initially designed without considering carbon capture, a post-combustion carbon capture system (shown as an inset in Fig. 1.2) can be implemented at the exhaust gas side exit of the HRSG. The carbon capture system makes use of an amine-based solvent to separate the CO2 from the rest of the GT exhaust. The cost of using a post-combustion carbon capture system is

Figure 1.2 A general layout of a simulated IGCC plant without CCS with an inset showing an added post-combustion carbon capture system. The physical parameters at each nodal point is represented as pressure p (psia), temperature T(oF), enthalpy h(Btu/lb), and mass flow rate M(lb/s) (Wang and Long, 2012a).

typically higher than a corresponding pre-combustion system in terms of dollar/ton CO2, but its operation is expected to be less complicated than a pre-combustion carbon capture system because the operation of post-combustion CCS has a minimal affect on the operation of upstream power-producing devices, whereas the operation of pre-combustion CCS is tightly intertwined with the entire IGCC system.

To reduce the cost of carbon capture, IGCC is particularly cost-effective for implementing pre-combustion carbon capture. The major difference between post-combustion and pre-combustion carbon capture lies in the implementation of Water-Gas Shift (WGS) before the syngas is burned in the GT to convert carbon monoxide and steam to carbon dioxide and hydrogen. Then, the carbon dioxide is separated from the hydrogen, so carbon dioxide can be captured effectively and transported for storage.

There are two approaches for pre-combustion carbon capture: sour-shift and sweet-shift. As their names indicate, the sour-shift process installs the WGS unit upstream of the AGR unit, before the sulfur is removed from the syngas, so the WGS process occurs in an acidic environment; whereas, the sweet-shift process implements the WGS unit downstream of the AGR unit after the sulfur is removed from the syngas. Fig. 1.3 illustrates a sour-shift process with an inset to show how a sweet-shift scheme can be implemented by replacing the red dashed circle with the blue dash-dotted box.

Detailed Description of Each Process and Component

1.3 Gasification process

Gasification is different from combustion. The purpose of combustion is to produce heat, whereas the purpose of gasification is to produce fuels or chemicals. Therefore, during a combustion process, the stoichiometric (or theoretical) amount of oxidant is used to completely oxidize the feedstock and obtain the maximum thermal energy output (heat); whereas, during a gasification process, as little thermal energy as possible is intended to be used (and, thus, limited oxidant is needed) to convert the feedstock to useful fuels, preserving as much of the original fuel’s chemical energy (or heating value) as desired. Typically, a stoichiometric ratio of 0.25–0.35(i.e., 25–35% of the oxygen theoretically needed for complete combustion) is implemented in a gasification process. Since only limited oxidant is needed, the gasification process has been commonly introduced as an incomplete combustion or partial combustion process. Although it is not wrong to say so, it could be misleading because the purpose of incomplete or partial oxidation is to produce heat, which is only the first step. The resulting heat is needed to complete the rest of gasification process. The actual reactions involved with gasification are extremely complicated and vary with the properties of the feedstock. For the convenience of further explaining the gasification process, a set of simplified, major global reactions involved in a gasification process are summarized as follows:

Figure 1.3 An overall layout of a simulated IGCC plant employing sour-shift for carbon capture. For sweet-shift, the red dashed circle is replaced by the blue dash-dotted box and the CO shift is not coprocessed with COS hydrolysis (Wang and Long, 2012b).

Heterogeneous reactions:

C(s) + ½ O2 → CO ∆H° R = -110.5 MJ/kmol [R1.1]

C(s) + CO2 ↔ 2CO ∆H° R = +172.0 MJ/kmol(Gasification, Reverse Boudouard reaction)[R1.2]

C(s) + H2O(g) → CO + H2 ∆H° R = +131.4 MJ/kmol(Steam-Char Gasification)[R1.3]

C + 2H2 → CH4, ∆H° R = -87.4 MJ/kmol(Hydrogasificaiton, Direct methanation) [R1.4]

Homogeneous reactions:

+ ½ O2 → CO2 ∆H° R = -283.1 MJ/kmol [R1.5]

CO + H2O(g) ↔ CO2 + H2 ∆H° R = -41.0 MJ/kmol (Water-gas shift) [R1.6]

CO + 3H2 ↔ CH4 + H2O ∆H° R = -205.7 MJ/kmol (Methanation)[R1.7]

CHmOnNoSpClq→aCO+bH2+cCH4+dC2H2+eN2+fHCl+gH2S+hCOS (Volatile cracking)[R1.8]

CH4+ ½ O2 → CO + 2 H2 ∆H° R = -35.7MJ/kmol (Volatiles gasification via CH4)[R1.9]

C2H2 + O2 → 2 CO + H2 ∆H° R = -447.83 MJ/kmol(Volatiles gasification via C2H2)[R1.10]

H2 +½ O2→ H2O ∆H° R = -242MJ/kmol[R1.11]

where (a) all the reaction heats, ΔH°R, are based on 298K and 1 atm; (b) “+” indicates endothermic (absorbing heat), and “ ” indicates exothermic (releasing heat); (c) heterogeneous reactions are reactions between different phases (here, it represents coal particles reacting with various gases); (d) homogeneous reactions are reactions occurring entirely within the gas phase; and (e) reactions [R1.8], [R1.9], and [R1.10] consist of a simplified two-step thermal cracking gasification model proposed by the author.

The gasification of coal particles involves three major steps, as shown in Fig. 1.4: (a) thermal decomposition/pyrolysis (demoisturization and devolatilization), (b) thermal cracking of the volatiles, and (c) char gasification.

1.3.1 Pyrolysis

Coal particles undergo pyrolysis when they enter the hot combustion environment, which needs to be created by burning other gaseous or liquid fuels during the ignition process in the beginning. The hot environment needs to be sustained continuously by the heat released from exothermic processes, mainly via [R1.1] and [R1.5]. When the particle temperature reaches the water boiling point, moisture within the coal (i.e., the inherent moisture) vaporizes through a demoisturization process, and leaves the coal’s core structure by migrating to the core surface as steam. The volatiles are then released as the particle temperature continues to increase. This volatile-releasing process is called devolatilization.

The word pyrolysis was derived from the Greek: pyro means “fire” and lysis means “separating.” Theoretically, pyrolysis is defined as a thermo-chemical decomposition process of organic material at elevated temperatures in the absence of oxygen. In the

Figure 1.4 Simplified global gasification of coal particles (sulfur and minerals are not included).

gasification process, although oxygen is present, only limited oxygen is supplied and the oxygen is mostly depleted via carbon combustion ([R1.1, 1.5, 1.9, and 1.10]). Thus, the kinetics and phenomena occurring in the pyrolysis process during the gasification process are close to those observed in an environment without oxygen. The mechanics of the pyrolysis process are affected by the physical properties of the char. During the fast heating of the coal particles, the heat transfer coefficient often decreases. This reduced heat transfer rate to the particle surface results in a temperature plateau of about 400°C (752°F) and lasts throughout the devolatilization process. When fast pyrolysis occurs concurrently surrounded by a combustion flame, this is referred to as fast flaming pyrolysis.

1.3.2 Devolatilization

Devolatilization is a decomposition process that occurs when, under heating, volatiles are driven out from a hydrocarbon material (like coal). The rate of devolatilization is influenced by temperature, pressure, residence time, particle size, and coal type. The heating causes chemical bonds to rupture, and both the organic and inorganic compounds to decompose. In a typical fixed bed reactor, the process starts at a temperature of around 100°C (212°F) with desorption of gases, such as water vapor, CO2, CH4, and N2, which are stored in the coal pores. When the temperature reaches above 300°C (572°F), the released liquid hydrocarbon called tar becomes important. Gaseous compounds, such as CO, CO2, and steam are also released. When the temperature is above 500°C (932°F), the fuel particles are in a plastic state where they undergo drastic changes in size and shape. The coal particles then harden again and become char when the temperature reaches around 550°C (1022°F).

In general, the larger the particle size, the smaller the volatiles yield because, in larger particles, more volatiles may crack, condense, or polymerize, with some

carbon deposition occurring, during their migration from inside the particle to the particle surface. At high pressures, volatiles yields of bituminous coals decrease due to the low vapor pressure of tar. In contrast, low rank coals do not show decreased volatile yields with increased pressure since these coals do not have as much tar.

1.3.3 Volatiles cracking

Volatile matter usually consists of a mixture of short- and long-chain hydrocarbons, aromatic hydrocarbons, and some sulfur and chlorine. Volatile matter with longer hydrocarbon chains and higher boiling temperature usually becomes tar, which condenses easily and can cause severe operating problems by plugging the piping and fouling the surfaces of downstream components if the gas temperature decreases below the condensation point. Considering low temperatures (38–138°C/100–280°F) are required during the desulfurization and mercury removal processes downstream, long-chain volatiles need to be cracked into lighter gases. Cracking can usually be performed either catalytically at lower temperatures or thermally at higher temperatures. For IGCC applications, usually thermal cracking is employed to break heavier long-chain volatiles and hydrocarbons (such as C3H8, C6H5OH, C6H6, or substances with longer C-chains) into lighter gases such as H2, CO, C2H2, CH4, C2H6, etc. These lighter gases may react with limited O2 via partial oxidation [R1.9] and [R1.10], releasing more heat, which is needed to continue the pyrolysis, devolatilization, and thermal cracking processes.

Reaction [R1.8] models thermal cracking of volatiles in a general form (CHmOnNoSpClq) into CO, H2, CH4, C2H2, N2, HCl, H2S, and COS, followed by a partial oxidation process to convert the intermediate gases, CH4 and C2H2 (the two lightest hydrocarbons), into the desired components, CO and H2, via [R1.8] and [R1.9]. This two-step model removes the need to accurately know the real reaction mechanism (which is usually more complex than the simplified two-step model) during the thermal cracking process because eventually the modeled intermediate gases would be converted to CO and H2 as long as there is O2 available. The temperature in the gasification process is sufficiently high so that, if any hydrocarbons can survive, it would be only the lightest hydrocarbons, for example CH4, that can be present in a noticeable amount. Furthermore, this two-step model also provides a pathway for volatiles to generate heat for the gasification process via incomplete combustion (or partial oxidation).

For example, thermal cracking [R1.8] for one category of Illinois No.6 bituminous coal and West Kentucky No.11 lignite can be modeled as (Wang et. al., 2014):

1.3.4 Endothermic steam-char and carbon dioxide-char gasification processes

With only char and ash left, the char particles undergo two important endothermic, heterogeneous gasification reactions: one is the Boudouard reaction: C(s) + CO2 ↔ 2CO [R1.2] (or, more accurately, the reverse Boudouard reaction, and it is also called as carbon dioxide-char gasification), and the other one is C(s) + H2O(g) → CO + H2 [R1.3] (also called steam-char gasification). Both are endothermic.

The Boudouard reaction was discovered in 1905 by the French chemist, Octave Leopold Boudouard (1872–1923), who investigated the equilibrium behavior of the Boudouard reaction, C(s) + CO2 ↔ 2CO (Holleman et al., 2001). When temperature becomes higher than 700°C (1292°F), the reaction is endothermic and tends toward production of CO. Inside a typical gasifier of an IGCC system, in a reducing environment with temperatures higher than 900°C (1652°F), the production of CO becomes dominant (Hunt et al., 2013). The reactivity of the char during the Boudouard reaction can be affected by the catalytic effect of inherent minerals contained in the coal. Typically, the greater the alkali index, the higher the reactivity (Zhang et al., 2003). The Boudouard reaction performs a very heroic action during the gasification process because it converts the villain CO2 into CO, which is a good fuel, as well as a useful chemical feedstock for producing other chemicals, such as methanol or substitute natural gas (SNG). The Boudouard reaction can also be used for CO2 remediation or utilization, but it must be implemented in a high-temperature environment, making the process expensive.

The steam-char reaction is the major contributor to the production of both H2 and CO, which are the primary components of the syngas. To take advantage of the steamchar reaction in dry-feed applications, injection of an adequate amount of steam at the appropriate location in the gasifier becomes an important design consideration. The steam-char reaction is about an order of magnitude faster than CO2-char (the Boudouard) reaction. When these two endothermic gasification reactions complete, the major components of the syngas, H2 and CO, have been harnessed. The next important process is the water-gas shift process.

1.3.5 Water-gas shift (WGS) process inside gasifiers

The water-gas shift reaction is an equilibrium process: CO + H2O(g) ↔ CO2 + H2 [R1.6]. The forward reaction is exothermic (ΔH°R = 41.0 MJ/kmol), converting carbon monoxide and steam to hydrogen and carbon dioxide. The forward reaction is active at temperatures lower than 700°C. At higher temperatures, near 1000°C, the net reaction is slow and negligible. Beyond 1200°C, the backward reaction becomes dominant. The reaction rate of the WGS is typically slow without using catalysts; however, in the gasifier, the reaction rate is usually enhanced by the catalytic effect of metal components in the coal. Since the forward reaction occurs at relatively low temperatures, the WGS typically occurs in the region in the gasifier where the temperature is reduced due to the endothermic steam-char and carbon dioxide-char gasification processes. The WGS is an important process that will affect the final composition

of the raw syngas. Thus, for dry-feed gasifier operation, a coarse manipulation of the CO/H2 ratio can be achieved by managing the amount of steam being injected into the reduction region of the gasifier. In the gasifiers that use the quench method to cool the syngas down to near 200°C, the residence time is too short to achieve any pronounced forward WGS reaction, even though the equilibrium constant value is high at low temperatures, because the catalytic effect from metals in the coal is minimal in the quenched syngas since most of the metals have become molten slag, which is extracted during the gasification process itself, before quench occurs.

For the water-gas shift reaction, the equilibrium constant can be defined as follows:

where the brackets represent the concentrations of each chemical compound. For an ideal gas, KWGS has no pressure dependence, and KWGS can be found using the Van’t Hoff equation.

Here, R is the ideal gas constant, ΔH is the reaction enthalpy, and ΔS is the change in entropy of the reaction. Using the software program Gaseq, the value of KWGS ranging from room temperature to over 1204°C (2200°F) is calculated and shown in Fig. 1.5. A good approximation using the Arrhenius form can be derived as (Fig. 1.6):

or by fitting the data in logarithmic form

Some select values at different temperatures are shown in Table 1.1.

Figure 1.5 WGS equilibrium constant value (A) between 27°C and 1127°C (80°F and 2060°F) (B) zoom in between 238°C and 1127°C (460°F and 2060°F).

Eq. 1.3b

Liner Curve Fit Eq. 1.3c

Figure 1.6 WGS equilibrium constant value vs. 1/T in semi-log coordinates.

Table 1.1 Water-gas shift reaction equilibrium constant (KWGS)

Lu and Wang (2013a, b) conducted a numerical simulation to investigate the effect of WGS reaction rate on the resultant syngas composition. They compared the simulated result with the experimental results and stated that the available published WGS reaction rates in the open literature were too fast because most of them were obtained from the laboratory condition with different catalytic effects rather than those actually experienced in real gasifers. The WGS is an important process to manipulate the CO/H2 ratio for downstream applications, such as for producing SNG or other chemicals, or for carbon capture applications. More details of downstream WGS applications will be introduced in Section 1.4.

1.3.6 Methanation

The two methanation reactions [R1.4 and R1.7] are highly exothermic and pressurefavorable, so they are generally not active in high-temperature environments, such as in high-temperature entrained flow gasifiers. If the goal of gasification is to produce Substitute Natural Gas (SNG), it is usually produced downstream in a low-temperature, high-pressure reactor facilitated with catalysts, mainly consisting of ruthenium, cobalt, nickel, and/or ironbased metals. It would be better if methanation could be directly performed in the gasifier, but current technology has not yet reached that status. Lu and Wang (2016) conducted a review of coal-to-SNG methods and predicted that it would be difficult to produce SNG directly with a methane concentration above 18% (vol) using a once-through gasifier.

1.4 Gasifiers

With the understanding of the fundamental, global gasification process, many different gasifiers have been designed to best achieve certain target syngas compositions (predicted by the equilibrium analysis) with the goals of minimizing the gasifier’s size (thus reducing cost), maximizing output yield, enhancing gasification efficiency, lowering maintenance frequency, and increasing reliability and availability. In order to obtain the syngas composition predicted by chemical equilibrium theory, the residence time must be greater than that calculated from the reaction kinetics, which is typically implemented by making the gasifier large enough or reducing the flow rate, as seen in the design of a fixed bed gasifier. In a fixed bed gasifier, the feedstock is typically fed from the top and falls downwards by gravity. During the free-fall period, pyrolysis and devolatilization occur; any unfinished process is completed in the particle bed in the bottom of the gasifier. There is plenty of time (i.e., long residence time) for the reactions to complete in the sitting particle bed. To increase the contact surface area, the bed is moving either linearly or in a rotating motion with turbulators, or the bed is fixed and is disturbed by a stirrer. Lurgi and British Gas/Lurgi gasifiers (Fig. 1.7) are typical representatives of moving bed gasifiers. This is why fixed bed gasifiers are often also referred to as moving bed gasifiers if some agitation or stirring actions on the bed are added. Thanks to the long residence time, the demand for oxidant is low compared to other types of gasifiers. The coal feed is typically ground down to a size of about 50 mm. The difference between the Lurgi and British Gas/Lurgi (BGL) gasifiers is that the Lurgi gasifier operates in a non-slagging, dry-bottom mode, whereas the BGL gasifier operates in slagging mode. The operating temperatures of updrafting moving bed gasifiers range from 1000°C (1832°F) at the bottom to 540°C (1004°F) at the top, with pressures ranging from 20 to 30 bar (290–435 psig).

Fixed bed gasifiers are simple to build. Since the stirrer helps to increase the particle contact surface area, more agitation of the particle bed will be more desirable and appealing. This leads to the design of bubbling fluidized bed gasifiers—basically, the particle bed is agitated into a fluid-like state by injecting air or gas from the bottom of the bed. The air/gas jets travel upward against the weight of the bed particles in pockets, like bubbles in boiling water—only the body of water is replaced with packed particles. Thus, the name bubbling fluidized bed is derived. Since the agitating motion provides more effective contact surface area for heat/mass transfer and chemical reactions for the same syngas yield, the sizes of fluidized bed gasifiers are typically smaller than those of moving bed gasifiers; or, for the same size, fluidized bed gasifiers typically have higher yield. The GTI (U-Gas) gasifier is an example of a bubbling fluidized bed gasifier (Fig. 1.7).

To further increase the throughput of the gasifier, the superficial velocity of the gas is increased. The superficial flow velocity is an averaged flow velocity calculated by assuming that the interested gas or fluid phase is the only one flowing or present in a given cross-sectional area, and other phases and particles are absent. The result of the increased gas speed is a significantly increased attrition rate of unreacted chars through the free-board region of the gasifier. Thus, recapture and recycling of the unreacted chars becomes an important mechanism to achieve high carbon conversion.

A cyclone is typically installed to recapture relatively large-sized particles, such as unburned char, soot, and ash. The addition of a faster recycling path yields the name circulating fluidized bed gasifier. The High-Temperature Winkler (HTW) gasifier is an example of a circulating fluidized bed gasifier. The coal feed is typically ground down to a size of about 6 mm (1/4 inches). Fluidized bed gasifiers typically operate at pressures ranging from 35 to 60 bar (508–870 psig) and temperatures ranging from 800°C (1472°F) to1000°C (1832°F). Since the operating temperature range in fluidized bed gasifiers is lower than the ash melting temperatures, these gasifiers produce ash rather than slag.

The KBR transport gasifier (Fig. 1.7) used in the Kemper IGCC plant can be also categorized as a circulating fluidized bed. One of the advantages of the KBR

Figure 1.7 Various commercial gasifiers (Stiegel, 2009).