Coal Gasifier at The Power Systems Development Facility Wilsonville - Alabama

IGCC technology is a power generation process that integrates gasification process with combined cycle power plant. The gasification system converts coal into synthesis gas which consists primarily by hydrogen (H₂) and carbon monoxide (CO). The synthesis gas is then used as fuel on a combined cycle power plant for electricity generation^[1]. This is the second part of the article IGCC: Technology Overview. This part of article will provide further explanation of four major sections in IGCC plant.

Air Separation Unit (ASU)

The commercial technology used for oxygen production in IGCC plants is cryogenic air separation which may be defined as the separation of air into its component by distillation at low temperatures. Cryogenic air separation has a single train O₂ production capacities of 3200 tons/day and is recognized for its high reliability. Major suppliers of the technology are Air Products, Air Liquid, BOC Gases, Praxair, and Linde. Air compression consumes a significant amount of energy required for the process.

Typically, prior to ASU, air is compressed to around 5 bar. The oxygen (typically 95% O2, 3.5% Ar and 1.5% N2 by volume) and nitrogen product streams are available at around 1 bar. However, the process may also operate at elevated pressure so that the ASU air fed pressure is closer to the gas turbine compressor outlet pressure. This makes it feasible to supply part or all of the ASU air from the gas turbine compressor. In this case, the ASU product streams are at around 5 bar which reduces the re-compression work^[3].

Gasification

Figure 1. Three main types of gasifiers

The conventional coal gasification technology, as known today, has its origin from the 1934 Lurgi coal gasifier. Coal gas reactions, C + H₂O -> CO + H₂ and C + CO₂ -> 2CO, are also known as steam and dry reforming reactions, respectively. Carbon is reformed to CO and H₂ gases, called synthesis gas. For the reforming reactions to proceed, it must absorb heat energy comparable to its combustion reaction (C + O2 -> CO2)^[5].

There are 3 main types of gasifiers as shown in Figure 1. In moving-bed reactors, large particles of the fuel move slowly down through the gasifier while reacting with the gasifying medium moving up through it. Several different reaction zones are created as they accomplish the gasification process. Operating temperatures are not uniform inside the reactor with the temperature of the synthesis gas leaving the reactor being as low as 400–500°C. In fluidized-bed reactors small particles of the fuel remain suspended in the gasifying medium while the gasification process takes place. The temperature inside the reactor remains uniform in the range of 800–1000°C. In entrained flow reactors the pulverized fuel goes through the various stages of gasification flowing co-currently with the gasifying medium. The feedstock can be either in dry or in water slurry form. The temperatures achieved in the reactor are very high in the range of 1200–1600°C. Entrained flow gasifiers are considered to be the most suited type for IGCC applications^[4].

Gas Clean-up

The raw synthesis gas may contain some chemical components and particulates which must be removed prior to be used in combined cycle plant.

1. Chemical Components
   The major components of the syngas at the outlet of an entrained flow slagging gasifier are CO, H₂, CO₂ and H₂O. Some N₂, Ar, and small amounts of CH₄ will also be present. Table 2 provides a summary of the components. Up to 99.8 % of the coal sulfur can be removed in the acid gas removal process. As COS in not easily removed, a hydrolysis unit (or shift reactor in case of CO₂ capture) is required to convert the COS to H₂S prior to the acid gas removal. As for nitrogen and chlorine compounds, both compounds have very high solubility in water and may be removed in water scrubbing. For the unconverted carbon and ash, after capture in a filter or scrubber, these particles may be recycled to the gasifier to increase the carbon conversion efficiency^[3].
Table 2. Some of trace components in raw syngas^[3]

Sulfur compounds	H2S, COS
Nitrogen compounds	HCN, NH3
Chlorine compounds	HCl, NH4Cl, other MeCl
Fly ash/slag	Unconverted C and ash
Other compounds	Pb, Hg, As, Ni(CO)4, Fe(CO)5

2. Particle Removal
   Dry solids removal systems use candle filters that can remove all solids from the gas at temperatures between 300°C and 500°C. Above 500°C, alkali compounds may pass the filters in significant amounts. Below 300°C, the filters may be blinded of deposits of ammonium chloride (NH₄Cl)^[3]. Wet solids removal systems use water scrubbers operating at a temperature lower than the dewpoint of the gas so that the smallest solid particles can act as nuclei for condensation and ensure efficient operation. Even if an IGCC plant has a candle filter it usually also adds a wet scrubbing system for removal of remaining impurities such as chlorides and ammonia.
3. Shift Reaction
   This stage of clean up is optional depends on the conditions. Figure 5 shows the principle processes for gas clean up for cases with and without CO₂ capture. If CO₂ capture is not considered necessary and the syngas is used only to feed the turbine (no chemical or fuel production), then a shift would not be included. However in this case, a separate hydrolysis reactor would be required to convert COS to H₂S for easier sulfur removal. If there is a shift reaction, this conversion takes place simultaneously and no separate reactor is needed. When CO₂ capture is considered there are two alternative processes for the shift reaction: a) Sour shift and b) Clean shift. A study has concluded that the sour shift is the preferred process with respect to costs and efficiency.

Figure 2. Gas clean up processes; a) No shift conversion, b) Sour shift conversion, and c) Clean shift conversion^[3].
4. CO₂ Capture
   Removal of CO₂ from gas streams can be achieved by a number of separation techniques including absorption into a liquid solvent, adsorption onto a solid, cryogenic separation and permeation through membranes. When considering capture of CO₂ in the IGCC design, two additional process blocks are needed (besides the compression of CO₂ for transportation):
   1. A shift reactor in which the CO reacts with H₂O to H₂ and CO₂.
   2. An absorption process for capture using the Selexol process or other processes based on physical solvents, or an MDEA process based on chemical solvents.

   CO₂ separation processes with chemical solvents (alkanolamines) are industrialized since the seventies and the licensors are directed these last years toward specific solvent formulations: primary or secondary amines and anti-corrosion additives, tertiary amines with promoters or activators and with antifoaming additives. Mixing of chemical solvents, such as tertiary amines and a relatively small amount of the primary amine, aims to combine the advantages of the two solvents: the target of such mixed chemical solvents is to achieve a better absorption capacity, to avoid the solvent degradation and to limit the corrosion^[2].

   As mentioned above, the use of CCS technology will decrease the plant overall efficiency for several reasons. The amount of efficiency penalty for the IGCC plant with CCS also depends heavily on the type of gasifier used. But the efficiency often decreases in range 8-12 percent^[2].

Gas Turbines

Gas turbines were designed for natural gas and oil fuels, but are also commercially available for operation on syngas. GE, Siemens, Mitsubishi and Alstom offer gas turbines which could be applied in larger scale IGCC plants^[3].

Syngas which typically has only 25% of the volumetric heating value compared to natural gas, therefore requires roughly 4 times higher flow rate to maintain the same turbine inlet temperature (which is desirable to maintain high efficiency of the power block). Potentially, the increased mass flow of fuel and therefore the higher mass flow rate through the turbine will lead to an increased power output from the turbine.

However, depending on the gas turbine technology and fuel under consideration, there may be several limitations for the full realization of this increased power output potential:

1. Compressor surge
2. Gas turbine torque
3. Turbine inlet temperature and material lifetime

A higher mass flow rate through the turbine may increase the pressure at the compressor outlet (back pressure) too much, so that the compressor runs into surge and the air flow no longer can be maintained. The amount of pressure increase the compressor can tolerate before this occurs is referred to as the compressor surge margin which is a characteristic of the design of a given compressor. If surge becomes a problem therefore depends on the type of gas turbine, but it seems that this is an issue for the majority of available large gas turbines (Maurstad, 2005).

The mechanical ability of the gas turbine rotor to handle increased power output is another limitation for maximum GT power output. The turbine inlet temperature (TIT) is an important variable with respect to the electric efficiency of the combined cycle. It is desirable to operate with a TIT as high as possible to increase the efficiency. However, in order to protect the materials of the turbine, it is necessary to have a cooling system.

A heat recovery steam generator or HRSG is often used in the combined cycle power plant. HRSG is a heat exchanger that recovers heat from a hot gas stream. It produces steam that can be used in a process or used to drive a steam turbine. HRSG in a combined-cycle power station, exchanges hot exhaust from a gas turbine to generate steam which in turn drives a steam turbine. This combination produces electricity more efficiently than either the gas turbine or steam turbine alone. HRSGs consist of three major components. They are the Evaporator, Superheater, and Economizer. The different components are put together to meet the operating requirements of the unit.

Conclusion

IGCC technology is somehow one of the way to create more electricity to meet the world need. There are four major sections in which the electricity can be produced; air separation, gasification, gas clean up and conditioning, and combined cycle power plant. Due to the environmental problem, many future IGCC plant integrates the plant with CCS technology which will separate the CO2 from the gas stream. But this action will highly decrease the plant overall efficiency. The reduction in electrical efficiency for a plant with CO2 capture is explained by the following factors:

1. Exothermic shift reaction produces heat from syngas fuel and required coal feed rate to provide necessary rate of chemical fuel energy to the gas turbine increases. The produced heat is less efficiently converted to electricity than chemical energy (fuel heating value)
2. If the steam/carbon ratio is too low, steam must be supplied from the steam cycle and is equivalent to an electricity production loss
3. CO2 compression work

There is a continual research to reduce energy consumption for the overall process. The use of the new technologies of gas turbines operating with high turbine inlet temperature will increase the power production with similar fuel flow rate and so for the electric net efficiency which is a complimentary way to reduce fossil fuel consumption and therefore the CO2 emission. Research on the CO shift conversion could also reduce the steam consumption.

References:
^[1] Christou C., Hadjipaschalis I., Poullikkas A, J. Rser. 2007 June.
^[2] Descamps C., Boualloua C., Kanniche M., J. Energy. 2007 July.
^[3] Maurstad O. An Overview of Coal Based IGCC Technology. 2005
^[4] Higman C. and van der Burgt M, Gasification. 2003.
^[5] Yong K.H., J. Hydrogen Energy. 2007 32 5088-5093.
^[6] http://www.aiche.org/uploadedFiles/Energy_Website/Publications/051206_IGCC.pdf
^[7] http://www.netequity.biz/docs/BioChip/SiemansGasification.pdf
^[8] http://www.bv.com/Downloads/Resources/energy_brochures/goc/rsrc_gasificationIGCC.pdf
^[9] http://www.exxonmobil.com/corporate
^[10] http://www.worldenergysource.com/articles/pdf/longwell_WE_v5n3.pdf