A commercial-scale gasification plant using mixed feedstock of biomass and coal has been demonstrated at the 253 MWe Nuon Power Plant in Buggenum, the Netherlands [6]. The plant was built in 1993, and it uses biomass to reduce CO2 emissions based on dry feed Shell gasification technology. The Shell gasifier is an oxygen-blown continuous slagging, entrained flow reactor. The plant is capable of using different types of coal and contains several advanced design features that are different from U. S. IGCC plants. The air separation unit and gas turbine are very closely coupled, with the gas tur­bine compressor supplying all the air to the ASU. Although this improves efficiency, it makes the plant more complex and harder to start.

Pulverized coal is fed into the gasifier with transport gas via dense phase conveying. Either product gas or nitrogen can be used as a carrier gas. The reactor is operated at 1,500-1,600°C and pressure ranging from 350 to 650 psig to produce syngas principally composed of H2 and CO and very little CO2. Operation at the elevated temperatures eliminates the production of hydrocarbon gases and liquids in the product gas. The molten slag at high temperature runs down the refractory-lined water wall of the gasifier into a water bath, where it is solidified and is removed through a lock hopper as slurry in the water. The hot gas leaving the reactor is first cooled by the recy­cling product gas and then by a waste heat recovery (syngas cooler) unit. The syngas is further cooled before particle removal in a wet scrubber. The syn­gas is then treated to remove carbonyl sulfide and hydrogen sulfide before going to a gas turbine.

The plant processed mixed feedstock of coal and biomass first from 2001­2004 with about 18% by weight of pure and mixed biomass. More recently, biomass concentration has increased up to 30 wt%. In addition to gasifica­tion of demolition wood, tests were also conducted with chicken litter and sewage sludge. The test program evaluated the effects of biomass on product gas and ash quality. The NUON/IGCC plant uses the coal and biomass com­position shown in Table 7.10. As shown, the plant takes about 30% by weight biomass, most of which is waste wood to provide about 17% of energy input to the gasifier.

This integrated gasification combined cycle power plant (see Figure 7.3) is operated by Tampa Electric [6]. In 2001/2002, the plant used about 1.5 wt% woody biomass harvested from a five-year-old eucalyptus grove along with coal to test whether biomass can be converted to fuel gas and whether a fuel handling system accommodates this change. The original system was not designed to handle softer fibrous biomass.

The Polk Power Station used old ChevronTexaco IGCC technology that is now owned by General Electric. In this process, 60-70% coal-water slurry is fed to the gasifier at the rate of 2,200 tons (on dry basis) of coal per day. The normal feed is a blend of coal and petroleum coke, the solid residue from crude oil refining. The fresh feed is mixed with unconverted recycled solids and finely ground in rod mills until 98% of the particles are less than 12 mesh in size. The slurry passes through a series of screens before being pumped into the gasifier. The slurry and oxygen are mixed in the gasifier process injector. The gasifier is designed to convert 95% of carbon per pass, and it produces syngas of 250 BTU/Scf heat content.

A schematic of the Polk Power Station plant is shown in Figure 7.3. As shown in the diagram, the syngas coming out of gasifier is cooled in a series of steps, each recovering heat in the form of saturated high-pressure steam. The first syngas cooler, called the "radiant syngas cooler" (RSC), produces 1,650 psig saturated steam. The gas from RSC is split into two streams and they are sent to parallel convective syngas coolers (CSC) where the pro­cess of cooling and generating additional high-pressure steam (at lower

FIGURE 7.3

Polk Power Station co-gasification configuration. (From Ratafia-Brown et al. 2007. Assessment of Technologies for Co-converting Coal and Biomass to Clean Syngas-Task 2 Report (RDS), NETL report (May 10); and McDaniel,
temperature) is repeated. The gases then further go through a simultaneous cooling and impurity removal (particulates, hydrogen chloride) process. A final trim cooler reduces the syngas temperature to about 100°F for the cold gas clean-up (CGCU). The CGCU system is a traditional amine scrubber sys­tem, and it removes sulfur which is then converted to sulfuric acid and sold to the local phosphate industry.

The eucalyptus feedstock used in this power plant contained about 1/3 of heating value per pound at about half the bulk density of coal. The character­istics of the mixed feedstock for the Polk Power Plant are shown in Table 7.11a. These numbers indicate that even a modest concentration of this biomass will require a massive and expensive feed system. Although the combined characteristics of the mixed feedstock are not significantly different from the baseline, it increases hydrogen, oxygen, and ash content by 4.6, 11, and 3.4%, respectively. The CO2 discharge is reduced by 0.87%. Biomass used in the Polk plant did not lend itself to size separation and screening, and it caused minor plugging of the suction to one of the pumps [6]. The results indicate that for a slurry system, feed preparation must be tailored to the nature of the biomass in order to prevent any malfunction by the slurry pump as well as downstream gas cleaning and turbine operation. Typical test results for the Polk Power Station are described in Tables 7.11a and b. The experience of the Polk Power Station can be extended to coal and other materials.

Polk Power Station Biomass Co-Gasification Test Results

Source: Ratafia-Brown, et al., 2007. "Assessment of Technologies for Co-converting Coal and Biomass to Clean Syngas-Task 2 Report (RDS)", NETL report (May 10); and McDaniel,

J., 2002. "Biomass gasification at Polk Power Station-Final Technical Report," DOE award DE-FG26-01NT41365 (May).

Alter NRG’s WPC two-stage plasma process [114] (described in the previ­ous chapter) has been used to build plants of various sizes in the United States, Canada, and Japan. Table 7.12 depicts basic descriptions of some of these plants. This technology provides clean fuel (toxin free) from a vari­ety of mixed feedstock. The basic description of the process is described in Figure 7.4. The plasma technology is most suitable for a mixed feedstock. It uses a moving bed reactor. The temperatures are high enough so that ash is melted and molten ash and slag are collected, vitrified, and discarded into landfill. The composition of the fuel gas produced by this technology depends on the nature of the feedstock, but high temperature and lack of oxygen can lead to the production of clean syngas containing hydrogen and

Plant Locations and Their Capacities for Various WPC Operations

Source: The Alter NRG/Westinghouse Plasma Gasification Process. 2008. Independent Waste Technology report by Juniper Consulting Services Limited, Bathurst House, Bisley UK, November.

carbon monoxide. The product gas composition also depends on the operat­ing conditions. The syngas is purified and conditioned and then converted to numerous different products via FT, methanol, or other syntheses. As shown in Figure 7.4, the process is divided into a number of different steps such that each can be optimized individually or collectively. The feed preparation and handling are a very important part of all new plants. In the second step, the feed can be gasified in one or multiple reactors. Generally one reactor is preferred, because unlike in gasification the slag is not used for further applications.

Unlike gasification technologies, liquefaction technologies are more at the developmental stage. For both coal and biomass there are direct and indirect methods for producing liquid products. The indirect methods are based on the use of a syngas platform from which liquid fuels and methanol can be pro­duced using Fischer-Tropsch syntheses employing different types of catalyst. Both biosyngas and petroleum — (or coal-) derived syngas can be obtained from coal-biomass mixture gasification. This subject has already been discussed in detail. The gas-to-liquid conversion process via FT synthesis depends strictly on purity and syngas composition irrespective of its generation source.

In this section we address direct methods for producing liquids from bio­mass and coal. There are three basic methods for liquid production: (a) direct liquefaction, (b) low severity pyrolysis, and (c) supercritical extraction and liquefaction. Methods (a) and (c) can be carried out either by an organic sol­vent or by water. We briefly evaluate both options.

Direct liquefaction of coal has been carried out in a hydrogen donor solvent at a temperature between 350-450°C, pressure between 2,000-5,000 psig, and in the presence of a hydrogenation catalyst along with hydrogen or another suitable reducing agent (such as carbon monoxide). During the 1970s and 1980s, significant research on direct coal liquefaction was carried out and this was summarized by Shah [115]. Although liquefaction is technically feasible, high hydrogen consumption, high pressure, short catalyst life, and poor liquid composition (without upgrading) made the process economically unattractive. The oil produced was stable, insoluble with water but not of the same quality as that derived from crude oil. Although direct liquefaction can be applied to bituminous, subbituminous, and lignite coals, the liquid production per ton of coal was higher for bituminous and subbituminous coals compared to lignite coals. Lignite coals are more active due to the high amount of hetero atoms and oxygen, but they also contain a large amount of water which reduces the oil production per ton of coal.

To some extent biomass is similar to lignite (see Figure 7.1) in that it con­tains a high amount of oxygen, a large amount of volatile matter, and its H/C and O/C ratios are not too far from the ones for biomass (see Figure 7.1). This is to be expected considering the fact that lignite is the lowest rank and youngest coal. The process of biomass liquefaction in the presence of a hydrogen donor solvent, catalyst, and hydrogen is likely to be similar to that for lignite coal liquefaction. Biomass liquefaction generally requires a tem­perature between 250-450°C and pressure between 700 to 3,000 psig [116]. A number of different hydrogen donor solvents have been used including creosote oil, ethylene glycol, tetralin, methanol, phenol, and recycled oil. The catalysts used for biomass liquefaction are alkaline oxides, carbonates and bicarbonates, metals such as zinc, copper, and nickel, formate, iodine, cobalt sulfide, zinc chloride, ferric hydroxide, and so on. Some of these are very similar to those used in coal liquefaction, for example, Fe, Co, Mo, Zn, Cu, and their derivatives. Both biomass and coal can be dissolved by solvolysis using a reactive liquid solvent. A review of biomass liquefaction research from 1920-1980 is presented by Moffatt and Overend [117].

In recent years, studies [118-123] have been reported to co-liquefy a mix­ture of coal and biomass. These studies have used lignite coal and various types of cellulosic waste materials. These studies indicated that the conver­sion is not significantly affected by the particle size of coal and biomass. Although all biomass gave good liquefaction results, waste paper gave the most desirable product distribution under both catalytic and noncatalytic conditions. The optimum reaction conditions were a solvent/solid ratio of 3, temperature of 400°C, and a reaction time of 90 min. The most suitable cata­lyst for the mixture was Fe2O3, although Cr(CO)6, Mo(CO)6, and MoO3 were also effective catalysts.

The studies on direct liquefaction of mixed feedstock carried out thus far have come to the same conclusion that was arrived at for direct coal liquefac­tion. High pressure, hydrogen, and low catalyst life make the co-liquefaction economically unattractive at the present time. A cheap catalyst or a catalyst with long life, low pressure, use of recycled solvent, and low hydrogen par­tial pressure will make this process more attractive. The quality of bio-oil is better than that produced from fast pyrolysis, however, it can only be used as boiler fuel and the like without further upgrading.

Water, particularly at high temperature and pressure is a good solvent for both biomass and coal [124-131]. For biomass, as described in the previous chapter, between temperatures of about 180-280°C, hydrothermal carbonization occurs which produces a heavy biocrude. For temperatures close to the critical tem­perature, hydrothermal liquefaction occurs producing a higher quality crude and this can be further upgraded with the use of hydrogen by a hydrothermal upgrading process. These processes are described in Chapter 6 and are not repeated here. Similarly finely pulverized coal and high-temperature water can also depolymerize coal producing asphaltene and preasphaltene types of materials. Initial tests done at Auburn University indicate that liquefaction of a mixed feedstock in water at high temperatures results in a product similar to biocrude, bio-oil, and asphaltene types of materials. There was no syner­gistic effect between liquefaction of biomass and coal. The tests were done for different types of coal and biomass. Because water is not a hydrogen donor, further upgrading of these crudes (or heavy materials) will require the use of hydrogen. Hydroliquefaction is a good method to produce heavy crude from coal and biomass mixture which may have some practical applications in the construction (e. g., cement) or fertilizer industries.

Just as with direct co-liquefaction, in recent years significant attention to co-pyrolysis of a variety of mixed feedstock has been given. Some of these studies have been focused on low-severity (low residence time as with fast pyrolysis) conditions to produce more oil and these are summarized in Table 7.13. Although the studies have examined a wide range of feedstock and reaction conditions, the major conclusion that emerges is that the pyro­lytic reactivity of biomass and coal are different because biomass in general is more reactive than coal and requires a lower temperature to devolatilize

TABLE 7.13

Some Typical Studies of Co-Pyrolysis

Mixed Feedstock Author Comment

and depolymerize compared to coal. However, there seem to be no or very little reactions or interactions between species of biomass and coal. Hydrogen release from biomass does not appear to interact with the species from coal. Thus, in general there is no synergy between coal and biomass pyrolysis. The final results for co-pyrolysis are additives of individual pyrolysis. Each species within the mixture produces its own liquids and gases. The situation is, however, different for the mixtures of biomass and a variety of plastics. In these cases, there appears to be a significant synergy between pyrolysis of these two substances. Not many studies using catalyst and hydrogen (i. e., hydropyrolysis) for a mixed feedstock have been reported. It is possible that under those conditions more synergies between coal and biomass pyrolysis would be observed. More work in this area is needed.

As mentioned before, the co-firing of coal and biomass creates problems for the use of mixed ash that contains fly ash as well as inorganic materials. Coal ash is used in the construction industries and biomass ash is used in the fer­tilizer industry. The ash content of a feedstock (biomass) has a major impact on gasifier operation. This type of impact depends on the gasifier type: slag­ging or nonslagging. For a moving bed (or fixed bed) nonslagging operation, ash below its fusion temperature forms clinker which stops the flow of feed­stock within the reactor. Although ash fusion temperature depends on the amount of sodium present in the feedstock, clinkers can become a signifi­cant problem for reactor operation. The ash can also affect the fuel’s reaction response. For high sodium content woody biomass such as birchwood, the formation of sticky sodium silicates by the interaction between sodium and silica bed materials used in a circulating fluidized bed can cause agglomera­tion and potential interruption in the gasification operation.

For an entrained flow gasifier, ash from biomass does not melt even at temperatures of 1,300-1,500°C because ash is rich in CaO, and alkali met­als are removed by the gas phase. Despite the high melting temperature of ash, the slagging entrained flow reactor is preferred because melt can never be avoided and the slagging entrained flow gasifier is more fuel flexible. Slagging co-gasification may require fluxing materials such as silica or clay in order to obtain proper slag properties at reasonable tem­peratures. By adding flux material to biomass, coal-based slag (generally coal ash with added limestone) is mimicked and slag properties become comparable. Solids handling is one of the important reasons why new gasifiers tend to be high-pressure, high-temperature entrained bed gasifi­ers. Such gasifiers will also handle solids produced with the mixed feed­stock well.

As reported in the previous chapter, supercritical extraction of coal, biomass, and other organic wastes by CO2, water, and other organic solvents have been extensively reported [146-160]. These studies have clearly indicated the value of this process. Outstanding reviews of supercritical extraction by
water both at high and low temperatures are given by Guo, Cao, and Liu [161] and Peterson et al. [124]. Only limited studies [161-163] for supercritical extraction of a mixed feedstock by water have been reported. Once again, there seems be no synergy for the high-temperature supercritical extrac­tion of coal and biomass in the mixture environment by water. The work of Veski, Palu, and Kruusement [163], however, shows an interesting interaction between liquefaction reactions of oil shale and wood. As shown in Chapter 6 and the previous section, syngas and hydrogen productions by supercriti­cal water gasification of pure and mixed feedstock have been the subjects of significant recent interest [66, 124, 161].

Mixed feedstock process options for gasification technology depend on the nature of the technology.

7.4.4.1 Combustion

There are basically three process configurations for co-combusting coal and biomass [1]. The most popular option is direct co-firing where biomass and coal are fed together in the same combustor. This is because with this method an existing coal power plant can be converted to a co-firing plant with a rela­tively low financial investment. In this method, both coal and biomass are either fed together or separately in the same combustor. When they are fed together, biomass feed can either be prepared jointly with coal or prepared separately and then injected in the combustor using the coal injection and burning system. When they are injected separately, a new and dedicated bio­mass feed preparation and sometimes also burning equipment is used. Thus there are three separate subconfigurations for feed preparation and burning within a co-firing system. Ultimately, the common combustor unit produces steam from both coal and biomass for power generation.

Many different types of biomass can be co-fired with coal. These include wood, residues from forestry and related industries, agricultural residues, and various biomass in refined forms such as pellets (RDF). Energy crops except oil, sugar, and starch can also be used for co-firing [1]. Constraints in the use of co-firing originate from feedstock properties. Raw biomass has high moisture content and low bulk and energy densities compared to coal, a low ash melting point, higher chlorine and oxygen content, and a hydro­philic and nonfriable character. The constraints related to co-firing include fuel preparation, handling and storage, possible decrease in overall effi­ciency, deposit formation (slagging and fouling) agglomeration, corrosion or erosion, and ash utilization. The degree of these constraints depends on the quality and percentage of biomass in the fuel blend, type of combustor used, co-firing configuration of the system (as mentioned above), and the prop­erties of coal. The importance of these problems increases with increased biomass/coal ratios and the use of poor quality biomass without a dedicated biomass preparation infrastructure.

Biomass pretreatment can help alleviate several concerns. As mentioned earlier, leaching, pelletizing, and torrefaction are preferred pretreatment methods; however, they can be expensive. Another interesting pretreatment option is fast pyrolysis to produce pyrolysis oil of high energy density. This oil can be mixed with coal and the slurry can be injected in the combus­tor. This method, however, requires a dedicated infrastructure for transport, storage, and feeding as well as a separate conversion unit. Herbaceous bio­mass is presently not considered a suitable biomass for co-firing. It can prob­ably be used with pretreatment by torrefaction and pelletization.

The second method is parallel co-firing (hybrid system) where coal and biomass are fed into separate combustors (with a separate set of operating conditions) producing steam that can be combined in a common header before being sent to the turbine for power generation. The advantage of this method is that ash coming from coal and biomass is kept separate and can be used separately, thus allowing the use of biomass with high chlorine and alkali content. The disadvantage of this method is that it is more expensive, and it may require a larger capacity for the steam turbine. This method is also particularly popular in the paper and pulp industries.

The third and final method is indirect co-firing. In this method biomass is gasified in a separate gasifier or combustor and the gases are injected to the coal combustor thus providing additional heat for the combustion pro­cess. The method once again keeps the ash from coal and biomass separate, but the overall process is more expensive than methods one and two. This method with pregasification is currently practiced in a number of demon­stration plants in Austria, Finland, and the Netherlands [1].