However, beyond its use in hydrogen production, syngas has other applications. Uses like energy production, the synthesis of chemical compounds (methanol, ammonia, DME) or production of gasoline through Fischer–Tropsch, are good examples of these applications (Wender, 1996). Due to this high versatility, syngas is a key industrial product.

The use of hydrogen as an energy carrier or fuel is nowadays one of the most important issues for the energy industry. This industry is facing the challenge of establish a new energetic model based on hydrogen, an alternative to the actual unsustainable model. This idea has been growing since the 1970s, when General Motors coined the term “Hydrogen Economy” (Navarro et al., 2007; Dunn, 2002; Armor, 1999; Balat and Kirtay, 2010; IEA, 2006a,b; Ni et al., 2007; Barreto et al., 2003).

Hydrogen has been claimed to be a clean fuel because the production of energy from H₂ only gives rise to water, avoiding the generation of CO₂ or other pollutant gases (Navarro et al., 2007; IEA, 2006a,b; Barreto et al., 2003; Lubitz and Tumas, 2007; Hamelinck and Faaij, 2002). However, to consider hydrogen as a clean fuel, its entire life cycle must be addressed. And here comes the controversy. Hydrogen is as clean as its method of production (Navarro et al., 2007; IEA, 2006a,b; Turner et al., 2008; Balat and Kirtay, 2010; Ni et al., 2007; Barreto et al., 2003). Ninety-five percent of the production of hydrogen nowadays is mainly based on carbonaceous raw material, primarily fossil in origin (IEA, 2006a,b; Barreto et al., 2003; Milne et al., 2006). Most of the hydrogen produced worldwide comes from processes involving carbon, oil, or natural gas. These processes give rise to the production of CO₂ which is then released to the atmosphere (IEA, 2006a,b; Barreto et al., 2003; Milne et al., 2006). In addition, the availability of these raw materials is decreasing and the cost of their exploitation is expected to increase for socioeconomic and geopolitical reasons (Barreto et al., 2003; Hart Energy, 2011; IEA, 2013). As a result of the concerns about global warming and the unstable prices of fossil fuels, the search for new ways of producing hydrogen has been promoted (Ni et al., 2006, 2007; Barreto et al., 2003; Milne et al., 2006).

Renewable-based processes like solar- or wind-driven electrolysis, photobiological water splitting, or bacterial production have appeared as promising technologies for their application in hydrogen production (Turner et al., 2008; Woodward et al., 2000). However, these technologies need substantial advances before achieving economic competitiveness (Milne et al., 2006). For this reason, the use of biomass as a raw material seems to be the best-positioned alternative for hydrogen production in the short and medium term. But this application still has some major challenges to face (IEA, 2006a,b; Turner et al., 2008; Balat and Kirtay, 2010; Milne et al., 2006; Hannula, 2009; Jahirul et al., 2012; Speight, 2011a,b). For example, hydrogen content in biomass is low (around 6%) compared to natural gas (25% for methane) or petroleum (around 12%) (Ortuño, 1999; Perry et al., 1997), and the energy content is low due to the 40% oxygen content of biomass (Milne et al., 2006). Other challenges include the cost of biomass harvesting, transport, or preconditioning for subsequent processing, which still hinder economic competitiveness (IEA, 2006a,b; Milne et al., 2006; Jahirul et al., 2012; Beneroso et al., 2014).

Among all these routes, thermochemical processes (especially gasification and pyrolysis) are the most developed. These routes have the advantage of high efficiency and lower cost compared to other routes (Balat and Kirtay, 2010). In addition, their high degree of development gives them a greater chance to be implemented shortly (Balat and Kirtay, 2010; Hamelinck and Faaij, 2002; Jahirul et al., 2012).

During the first half of the 20th century, the development of coal gasification technology was linked to weak economies. These economies had difficulty accessing low-cost oil or natural gas, unlike the more enonomically powerful countries which found syngas production through gasification of coal economically unattractive (IEA, 2006a,b; Adams et al., 2009). The battered German economy during war and post-war periods (1930s–1950s) and the foundation of Sasol in South Africa (1950s) played a key role in the development of coal gasification technologies whose influence has remained until today (Liu et al., 2009; Higman and Van der Burgt, 2011). Sasol facilities in South Africa are the largest gasification center in the world and, in 2007, the Sasol-Lurgi fixed bed dry bottom gasification process accounted for the 75% of the global coal gasification capacity (Liu et al., 2009; Turna, 2007).

In the early 1970s, the first oil crisis pushed interest in coal gasification to produce liquid and gaseous fuels. Companies like Lurgi, British Gas, Koppers, Shell, and Texaco developed different processes that improved the technology (IEA, 2006a,b; Liu et al., 2009). However, in the 1980s the oil came back to be the main driver in the fuel market and most of the developments achieved in coal gasification had to wait before being industrially implemented (Higman and Van der Burgt, 2011). The economic fluctuations in the energy cost since the beginning of the 21st century have had a huge impact on the renaissance of the gasification technologies (Van der Drift and Boerrigter, 2006; Higman and Van der Burgt, 2011; NASDAQ, 2005; Breault, 2010). Oil prices rose from steady values of 20–40 US$ per Brent barrel during the 1990s and early 2000s up to peaks of 140 and 125 US$ per Brent barrel in 2008 and 2011 (Higman and Van der Burgt, 2011; NASDAQ, 2005). Natural gas prices have also shown high volatility lately, peaking in 2005 and 2008 at values of 14 and 13 US$ per million of BTU (Higman and Van der Burgt, 2011; NASDAQ, 2005). Another main driver for this boost in gasification technologies has been the growing interest in gas-to-liquid and Fischer–Tropsch technologies (IEA, 2006a,b; Higman and Van der Burgt, 2011).

The development of the integrated gasification combined cycle (IGCC) is one of the main recent advances of the gasification technology (IEA, 2006a,b; Breault, 2010; Joshi and Lee, 1996). This flexible polygeneration technology can be readily optimized for producing H₂, power, heat, and other chemicals (IEA, 2006a,b). Similar to a natural gas combined cycle (NGCC), IGCC generates electricity through gas and steam turbines, but using syngas produced in the gasifier instead of natural gas (Fig. 15.2) (IEA, 2006a,b; Liu et al., 2009; Breault, 2010; Joshi and Lee, 1996; Gasifipedia).

Only a few coal-fuelled IGCC plants have been built and operated successfully over long periods (Adams et al., 2009). The first coal-fired IGCC demonstration plants were built at Lünen (Germany, 1972–77), followed by Cool Water (1984–89) and Plaquemine (1987–95) in the US, but were shut down after providing operational experience and information for the improvement of the technology (Adams et al., 2009). Since 1995, several large-scale IGCC demonstration plants have started to operate in Europe and the US. Nevertheless, there are still some difficulties to its full industrial spread, related to the capital cost and complexity, reliability and availability of IGCC cycles (IEA, 2006a,b; Adams et al., 2009). Despite these difficulties, the good prospects for this process make IGCC the most promising technology for the deployment of biomass gasification via the cogasification of biomass and coal (see Fig. 15.2). Cogasification of coal and biomass via IGCC is a flexible process, which can easily adapt to a wide range of biomass and coal/biomass feeding rates (IEA, 2006a,b).

The interest in developing and demonstrating biomass gasification technology is huge because of its potential:

The mature coal gasification technology could in principle be adapted to the use of biomass as feedstock. However, there are significant differences between coal and biomass gasification processes which result in incompatibility of many of the coal gasifier technologies to biomass (Huber et al., 2006). These differences can be both beneficial (biomass is more reactive, so lower temperatures can be used) and detrimental (biomass contains alkali that can cause fouling and slagging) (Huber et al., 2006). For these reasons, the complete industrial landing of biomass gasification needs further development of the technology to make it more technically and economically feasible (Bridgwater, 2003).