In addition to the costs of biomass energy, another and probably more impor­tant factor should be considered when assessing market prices for biomass energy and biofuels. It is the accumulated, tangible socioeconomic benefits of the com­mercial utilization of a local or regional energy resource for the local or regional economy. A detailed assessment of these benefits is perhaps best illustrated by the results of a projection done for the state of Wisconsin on the impacts of a 75% increase in Wisconsin’s biomass energy use by the year 2010 (Clemmer and Wichert, 1994). The study was referred to briefly in Chapter 2; more detail is presented here. Using indigenous biomass feedstocks, the projection consists of the impacts of 775 MW of new generating capacity and 379 million liters per year of new fuel ethanol production. This amount of biomass energy could supply electricity to 500,000 Wisconsin homes and 10 vol % ethanol-90 vol % gasoline blends (gasohol) to 45% of Wisconsin’s automobiles. Investment under this pro­jection generates about three times more jobs, earnings, and output (sales) in Wisconsin than the same level of imported fossil fuel usage and investment. This incremental increase in biomass energy alone is equivalent to 63,234 more job — years of net employment, $1.2 billion in higher wages, and $4.6 billion in addi­tional output. Over the operating life of the technologies analyzed, about $2 billion in avoided payments for imported coal, natural gas, and petroleum fuels could remain in Wisconsin to pay for state-supplied renewable resources, tech­nologies, and labor. Collecting and distributing the wood, corn, and waste feed­stocks correspond to 47% of the total net new employment for this industry and create permanent forestry, agriculture, and transportation jobs in Wisconsin’s rural communities. Operating and maintaining biomass energy technologies produce 27% of the net employment growth, and installing and manufacturing these technologies generate 13% of the newjobs on a temporary basis. Net savings in consumer income, with environmental regulations, account for the remaining 13% of newjobs. Five of the 11 biomass technologies analyzed for power produc­tion are less expensive to operate than a new baseload coal plant, without consid­ering incentives for environmental costs. When federal incentives and potential environmental regulation costs are included, 9 of the 11 biomass technologies cost less than a new coal-fired plant. Ethanol produced by established technolo­gies competes with gasoline at the federal incentive levels in place in the 1990s. Investing in biomass energy instead of fossil fuels in Wisconsin could save the state’s residents about $700 million in avoided environmental regulations to control C02 and S02 emissions from fossil fuels and $250 million in personal income. So it is evident there is more to development of a biomass energy industry that can compete with conventional fossil fuels than the basic costs of biomass energy.

I. INTRODUCTION

The simple act of burning biomass to obtain heat, and often light, is one of the oldest biomass conversion processes known to mankind. The basic stoichoimetric equation for the combustion of wood, represented by the empiri­cal formula of cellulose, (C6H505)n, is illustrated by

(C6H10O5)n + 6n02—» 6nC02 + 5nH20.

Carbon dioxide (C02) and water are the final products along with energy. If most biomass did not sustain its own combustion to make heat readily available in preindustrial times when and where it was needed, our historical develop­ment would not have reached its present state, and would probably have taken a different course. Up to the early 1900s, much of industrialized society utilized biomass combustion and a few related thermal processes for a wide range of applications including heating, cooking, chemical and charcoal production, and the generation of steam and mechanical and electric power.

The science of combustion has advanced a great deal since then and im­proved our understanding of the chemical mechanisms involved. Improved

combustion processes are available for conversion of virgin biomass and com­plex waste biomass feedstocks to heat, steam, and electric power in advanced combustion systems and in co-combustion systems supplied with both biomass and fossil fuels. Small-scale catalytic woodstoves have been developed that operate at higher overall thermal efficiencies with low emissions. Medium — to large-scale incinerators have been designed with heat recovery capability for efficient combustion and disposal of municipal solid wastes (MSW) with mini­mal emissions. And modern boiler systems are available for wood, municipal solid waste, refuse-derived fuel (RDF or the combustible fraction of MSW), and other biomass fuels for municipal and utility use. The technology has progressed far beyond the basic idea of just using biomass as a solid, combusti­ble fuel.

It is noteworthy that of all the processes that can be used to convert biomass to energy or fuels, combustion is still the dominant technology. More than 95% of all biomass energy utilized today is obtained by direct combustion.

In this chapter, the basic chemistry of direct biomass combustion, develop­ments that have made it possible to improve operating efficiencies and environ­mental performance, and state-of-the-art systems that have been or are expected to be commercialized are examined. Improvements needed to overcome some of the operating problems and advancements that are expected from ongoing research are also discussed.

Using cellulose as a representative feedstock composition, estimates of the enthalpy changes for some of the primary reactions that take place in biomass gasification systems are shown in Table 9.1. Although many stoichiometries are possible, as alluded to in this table, most of the hypothetical steam gasification reactions listed are endothermic at 300 and 1000 K. If methane is produced, along with the concomitant formation of C02, the process becomes progres­sively more exothermic. The partial oxidation reactions, as expected, are exo­thermic except at low oxygen levels. The degree of endothermicity and exother — micity of the pyrolysis reactions depends upon the product distributions. As carbon monoxide formation decreases and methane and carbon formation increase, the trend is toward more exothermic processes. It is evident that if fuel gases of higher energy content are desired, the gasification process should be operated to maximize methane and other light hydrocarbon products be­cause their heating values are considerably greater than those of the other fuel components, carbon monoxide and hydrogen, as shown in Table 9.2. As will be shown later, pyrolysis and steam gasification of biomass can be self­sustaining under certain conditions. These types of conversions have each been demonstrated in large facilities.

Except during startup, wood pyrolysis is reported to have been carried out commercially in the 1920s and 1930s without an external heat source. For example, the Ford Motor Company’s continuous wood pyrolysis plant was operated on hogged hardwood dried to 0.5% moisture content and an external heat source was not needed (Chapter 8). Presuming oxygen is excluded in such processes and that exothermic partial oxidation is not a factor, several exothermic reactions can contribute to the self-sustained pyrolysis of wood— the conversion of carbon monoxide and carbon dioxide to methane or metha­nol, char formation, and the water gas shift (Table 8.2). Methanation has one of the highest exotherms per unit of carbon converted. These reactions or modifications and combinations of them seem to have occurred in the self­sustained process at a sufficient rate to make the overall process self-sustaining under the operating conditions used by Ford Motor Company.

When applied to biomass feedstocks, few steam gasification systems in which oxygen and air are excluded have been described or operated as autother­mal processes since this early work. Wright-Malta Corporation’s directly heated, pressurized steam gasification process for the production of medium — energy gas described earlier is one of these (Hooverman and Coffman, 1976; Coffman and Speicher, 1993). An external heat source is needed only during startup, and water is added as a cofeedstock if the biomass feedstock contains insufficient moisture (i. e., less than about 50 wt %). The process was described as follows (Coffman, 1981):

As the biomass moves through the kiln from the cool feed end, it is gradually heated and first partially dries, yielding steam; then pyrolyzes, yielding gas, liquids, tars, and char. These move co-currently down the kiln. The liquids and tars steam reform, yielding more gas; the char steam-gasifies, yielding still more gas. The hot gas moves back through coils in the auger and kiln wall, giving its heat to the process, and being discharged at the cool end. This regenerative heat and wood decomposition exotherm are sufficient to sustain the process after initial heat-up by an auxiliary boiler. Over-all energy efficiency, raw biomass to clean, dry product gas is estimated to be 88-90%.

As shown in Table 9.1, most of the steam gasification reactions listed are endothermic, but as noted in the discussion of the Wright-Malta process, substantial amounts of carbon dioxide and methane are formed. Many of the gasification reactions that yield these products are exothermic. Char formation and the water gas shift are also exothermic (Table 8.2). Estimated equilibrium gas compositions from the steam gasification of green biomass at different pressures and temperatures shown in Table 9.11 indicate that at the tem­perature and pressure ranges of the Wright-Malta process, about 2 MPa and 900 K, substantial quantities of carbon dioxide and methane are formed. Calculations show that the process can be exothermic under these conditions. The heat of the exotherm and the sensible heat of the exiting gases, which are passed through tubular heat exchangers in the kiln, and the enthalpy of methanation, which occurs in the kiln and the heat exchangers, apparently drive the process. The total heat released is apparently large enough under Wright-Malta’s operating conditions to sustain steam gasification.

It should be emphasized that many investigators who have specialized in biomass gasification have questioned the validity of the steam gasification of biomass without the application of external heat because only a few autothermal systems have been reported to be operable. It is important to develop additional data to establish whether such systems can be self-sustaining over long periods. If they are, adiabatic, autothermal steam gasification would have several advan­tages for both medium-energy gas production and synthesis gas production. These include acceptability of a wide range of green biomass feedstocks without pretreatment; lower process energy consumption; direct internal heating of the reactants and therefore more efficient energy utilization; elimination of the need for feedstock dryers, an oxygen plant, and more complex indirectly heated gasifiers and indirectly heated, dual, circulating, fluid-bed gasifiers; and lower overall operating costs because of process simplicity. Another advantage would involve environmental benefits; steam gasification is reported to avoid formation of dioxins and to convert any chlorinated compounds that may be present to salts and clean gas (Mansour, Durai-Swamy, and Voelker, 1995). The disadvantage may be the relatively long solids residence time in the gasifier compared to some of the other processes. This can increase the plant’s capital cost for a given throughput rate.

The energy content of biomass is obviously a very important parameter from the standpoint of conversion of biomass to energy and synfuels. The different components in biomass would be expected to have different heats of combus­tion because of the different chemical structures and carbon content. This is illustrated by the HHVs listed in Table 3.6 for each of the main classes of organic compounds in biomass. The more reduced the state of carbon in each class, the higher the energy content. Monosaccharides have the lowest carbon content, highest degree of oxygenation, and lowest heating value. As the carbon content increases and the degree of oxygenation is reduced, the structures become more hydrocarbon-like and the heating value increases. The terpene hydrocarbon components thus have the highest heating values of the compo­nents shown in Table 3.6; the lipids have the next highest heating values. The dominant component in most biomass is cellulose. It has a HHV of 17 51 MJ/ kg (7533 Btu/lb).

“All analyses and HHVs were determined by the Institute of Gas Technology.

^Harvested from a residential site in the Midwest. cMacrocystis pyrifera harvested from kelp beds off the California coast. dEichomia crassipes harvested from a biosolids-fed lagoon in Mississippi.

‘From a commercial cattle feedlot.

^Refuse-derived fuel; i. e., the combustible fraction of municipal solid waste, from a Chicago facility. 8From a Chicago Metropolitan Sanitary District facility.

’’From Minnesota.

‘From Illinois.

JAs received with metals.

Typical lower heating values (LHV, product water in vapor state) of selected biomass species are shown in Table 3.7. Woody and fibrous materials appear to have energy contents between about 19 and 21 MJ/ kg, whereas the water — based algae Chlorella has a higher value, undoubtedly because of its higher lipid or protein contents. Oils derived from plant seeds are much higher in energy content and approach the heating value of paraffinic hydrocarbons. High concentrations of inorganic components in a given biomass species can greatly affect its energy content because inorganic materials generally do not contribute to the heat of combustion, This is illustrated by the HHV for giant brown kelp, which leaves an ash residue equivalent to about 46 wt % of the dry weight, as shown in Table 3.3. On a dry basis, the HHV is about 10 MJ/kg, while on a dry, ash-free basis, the heating value is about 16 MJ/kg.

When the heating values ot the waste and virgin biomass samples and even the peat and coal samples listed in Table 3.5 are converted to energy content per mass unit of carbon, it is apparent that they fall within a narrow range. This is usually characteristic of most biomass. The energy value of the total material can be estimated from the carbon analysis and moisture determinations without actual measurement of the heating values in a calorimeter. Manipula­tion of the data in Table 3.5 leads to a simple equation for calculating the HHV of biomass and also coal and peat with reasonably good accuracy:

HHV in MJ/dry kg = 0.4571(% C on dry basis) — 2.70.

A comparison of the experimental HHVs with the calculated HHVs for the biomass, coal, and peat using the carbon analyses listed in Table 3.5 is shown in Table 3.8. With the exception of the primary biosolids sample, the percentage error of the calculated HHV is relatively small.

Abundance

Agricultural crop residues are those left in the field or accumulated during sorting and cleaning of produce. Because of the discontinuity in growing seasons, the many crops that are grown, the differences between specific crops, variations in crop yields in different areas, the difficulty of acquiring reliable data, and long-term time effects, an inventory of the annual production of agricultural crop residues and their disposition might seem to be an impossible task. Fairly reliable data can be obtained, however, for small and large regions of a country. Somewhat detailed commentary is justified for one of these studies because it is a good example of how the task was addressed in a reasonably scientific manner for all 3069 counties of the continental United States (Stanford Research Institute, 1976). Although the assessment was done some time ago, the methods used still appear to be valid.

Hay and forage crops were excluded, since little residue accumulates from cultivation of these crops. Food processing wastes were excluded except for bagasse and sugarbeet pulp. With the exception of hay and forage crops, yields on a dry basis of the harvested crops and the areas harvested were tabulated for essentially all other cash crops, about 60, over a З-year period, 1971 to 1973, and averaged for each county by year and by quarter. At the same time, data were collected regarding what was done with the residue: returned to soil, sold, used as feed or fuel, and wasted. To estimate the quantity of residue generated, a residue factor for each cash crop was developed that, when multi­plied by the county yield total for that crop, gave the total mass of residue generated. The residue factors as used in the Stanford assessment were the ratio of field weight of residue per mass unit of crop yield and differed somewhat from those used by others in subsequent work (Table 5.4). It is important to

note these differences. Experimental measurements were made to determine the residue factors in the Stanford assessment by collecting field, packing shed, and mill residues immediately before or following crop harvest, determining fresh and oven-dry residue weights, converting the production figures from whatever the standard units were, such as bushels, to mass units, and calcu­lating the residue factors. For example, for field corn, the residue factor was 1.10 mass units of fresh residue per mass unit of corn yield. The weights of the residues were converted to dry weights later in the calculations. The residue factors as defined in the study were applied nationwide, except for two cases, the assumption being that geographical variation in residue generation in a given crop was accounted for by the geographical variation in the yield of that crop. The two exceptions were cotton gin trash and mint, wherein specific regional variations in residue production were considered, which led to devel­opment of separate regional residue factors. It is evident that this type of assessment is not an everyday event. Massive amounts of data are compiled, the easy manipulation of which requires computational methods.

A summary of the results of this assessment of residue generation from agricultural crops for the contiguous United States is presented here to provide an idea of the availability of agricultural residues for the contiguous United States in the mid-1970s. The data indicated a total of 292 million dry tonnes of residue were generated annually; about 252 million dry tonnes were judged to be collectible during normal operations. About 74% was returned to the soil, 19% was used as animal feed, 4% was sold, 3% was used as fuel, and a small amount was wasted. While there is controversy over what fraction of the residue returned to the soil could be utilized as waste biomass feedstock without adverse environmental impacts, it represented the largest portion of the collectible residue. Of the total available crop residues, 48% was estimated to be from small grains and grasses.

The top five states for agricultural residue production in millions of dry tonnes per year were Iowa, 25; Illinois, 24; Oregon, 23; California, 22; and Kansas, 21; the sum of these is 39% of total residue generation. Interest­ingly, only six counties in the continental United States averaged more than 350.2 dry t/km2-year (1,000 dry ton/mi.2-year). In units of dry t/km2-year, these were Lewis County, Idaho, 537; Delaware County, Indiana, 378; Lane County, Oregon, 363; Polk County, Oregon, 357; and Cook County, Georgia, 353. Also, only 55 counties averaged 2.24 dry t/ha-year (1.0 dry ton/ac-year) or more in available agricultural residue.

The fouling of heat exchanger surfaces can be a major problem with solid biomass fuels, especially straws and herbaceous residues. Fouling occurs be­cause of formation in the conversion zone of low-fusion point alkali metal salt eutectics such as the alkali metal silicates. If the temperature is above the fusion point of the salts, particulates form in the combustion gases that can stick to heat exchanger surfaces when the gases leave the zone. The problem can be severe in biomass combustion systems, but is usually not severe in biomass gasifiers (Chapter 9). Furnace-boiler systems for solid biomass fuels are often designed to keep the temperature in the combustors below about 900°C to reduce slagging and formation of molten agglomerates. Careful design of the internals is necessary to avoid contact of the hot gases that may contain low-fusion point particulates with higher temperature surfaces.

Another method of eliminating this problem with solid biomass fuels when the combustors and gasifiers are operated above slagging temperatures is to remove the ash from the bottom of the units as molten slag. This technique is well established with coal fuels, which often have higher ash contents than biomass, and seems to be quite effective. It is important to note that some biomass, although high in mineral matter, may be low in alkali metals. Fouling by sticky particulates should therefore be far less with this type of biomass. An obvious approach to the reduction of alkali metal fouling is to remove the alkali metals from the fuel before conversion. Extraction of the water-soluble salts has been evaluated, but unless it is effective and low in cost, it adds unnecessary complexity and expense to the process.

A slagging index developed by the coal industry has been used to rate solid fuels for fouling. This index corresponds to the mass of alkali metal as oxides (K20 + Na20) per energy unit in the fuel and is useful for rating biomass feedstocks too. The calculation is made by

0.1[(% ash)(% alkali in ash)](MJ/dry kg)"1 = kg alkali/GJ

An index range of 0 to 0.17 kg/GJ (0 to 0.4 lb/MBtu) is a low slagging risk; 0.17 to 0.34 kg/GJ (0.4 to 0.8 lb/MBtu) indicates the material will probably slag; and an index greater than 0.34 kg/GJ indicates virtual certainty of slagging (Miles et al, 1993). When applied to hybrid poplar, pine, and switchgrass by use of the data in Tables 3.3 and 3.4, the corresponding indexes are 0.11, 0.009, and 0.85 kg alkali/GJ, respectively.

Another fouling mechanism that can occur is corrosion of boiler tubing and erosion of refractories due to formation of acids and their buildup in the combustion units from conversion of sulfur and chlorine present in the fuel. Fortunately, the amounts of these elements in most biomass are nil to small. The addition of small amounts of limestone to the media in fluidized-bed units or the blending of limestone with the fuel in the case of moving-bed systems are effective methods of eliminating this problem. Other sorbents such as dolomite, kaolin, and custom blends of aluminum and magnesium compounds are also effective (Coe, 1993).

Many thermal conversion processes can be classified as partial oxidation pro­cesses in which the biomass is supplied with less than the stoichiometric amount of oxygen needed for complete combustion. Both air and oxygen have been utilized for such systems. When the oxygen is supplied by air, low — energy gases are formed that contain higher concentrations of hydrogen, carbon monoxide, and carbon dioxide than medium-energy gases. When pure oxygen or oxygen-enriched air is used, gases with higher energy values can be obtained. In some partial oxidation processes, the various chemical reactions may occur simultaneously in the same reactor zone. In others, the reactor may be divided into zones: A combustion zone that supplies the heat to promote pyrolysis in a second zone, and perhaps to a third zone for drying, the overall result of which is partial oxidation.

One system (Fig. 9.6) uses a three-zoned vertical shaft reactor furnace (Fisher, Kasbohm, and Rivero, 1976). In this process, coarsely shredded feed is fed to the top of the furnace. As it descends through the first zone, the charge is dried by the ascending hot gases, which are also partially cleaned by the feed. The gas is reduced in temperature from about 315°C to the range of 40 to 200°C. The dried feed then enters the pyrolysis zone, in which the temperature ranges from 315 to 1000°C. The resulting char and ash then descend to the hearth zone, where the char is partially oxidized with pure oxygen. Slagging temperatures near 1650°C occur in this zone, and the resulting molten slag of metal oxides forms a liquid pool at the bottom of the hearth. Continuous withdrawal of the pool and quenching forms a sterile granular frit. The product gas is processed to remove flyash and liquids, which are recycled to the reactor. A typical gas analysis is 40 mol % carbon monoxide, 23 mol % carbon dioxide, 5 mol % methane, 5 mol % C2’s, and 20 mol % hydrogen. This gas has a higher heating value of about 14.5 MJ/m3 (n).

An example of the gasification of biomass by partial oxidation in which air is supplied without zone separation in the gasifier is the molten salt process (Yosim and Barclay, 1976). In this process, shredded biomass and air are

continuously introduced beneath the surface of a sodium carbonate-containing melt which is maintained at about 1000°C. As the resulting gas passes through the melt, the acid gases are absorbed by the alkaline media and the ash is also retained in the melt. The melt is continuously withdrawn for processing to remove the ash and is then returned to the gasifier. No tars or liquid products are formed in this process. The heating value of the gases produced depends on the amount of air supplied and is essentially independent of the type of feed organics. The greater the deficiency of air needed to achieve complete combustion, the higher the fuel value of the product gas. Thus, with about 20, 50, and 75% of the theoretical air needed for complete oxidation, the respective higher heating values of the gas are about 9.0,4.3, and 2.2 MJ/m3 (n).

Many gasifier designs have been offered for the manufacture of producer gas from virgin and waste biomass, and several types of units are still available for purchase. As mentioned in the introduction to this chapter, thousands of producer gasifiers operating on air and wood were used during World War II, particularly in Sweden, to power automobiles, trucks, and buses. The engines needed only slight modification to operate on low-energy producer gas. Al­though only limited research has been carried out on small-scale producer gasifiers for biomass in recent years, significant design advancements continue
to be made even though the gasifiers have been used for more than 100 years. One of the interesting developments is the open-top, stratified, downdraft gasifier in which the feedstock such as wood chips moves downward from the top as it is gasified and air is simultaneously drawn in from the top through successive reaction strata (LaFontaine, 1988; LaFontaine and Reed, 1991). Low-cost, portable gasifiers can be assembled for captive use from ordinary metal cans, garbage containers, and drums that are manually loaded with fuel from the open top. More sophisticated units can of course be manufactured. The open — top biomass gasifier is simple to operate, is inexpensive, and can be close-coupled to a gas engine-generator set without requiring the use of complex gas-cleaning equipment. The system appears to be quite suitable for small — and moderate-scale engine applications from 5 to 5000 HP and portable electric-power generation systems. The gasifier dimensions are sized to deliver gas to the engine based on its fuel-rate requirements, and minimal controls are needed.

A similar, wood-fueled, downdraft gasifier patterned after Swedish reports from the early years of World War II was initially built in the United States in the late 1970s of mild steel. It was used to power an unmodified 1978 Chevrolet Malibu station wagon equipped with a 3,3-L (200-in.3) V-6 engine for a coast-to-coast trip from Jacksonville, Florida, to Los Angeles, California, a distance of about 4300 km (Russel, 1980). Small pine and hardwood blocks of 15 to 25 wt % moisture content were used as fuel throughout the trip. The gasifier was pulled on a small two-wheel trailer behind the vehicle. The system was subsequently driven a total of 8046 km. Examination of the vehicle and all components showed no significant wear or abnormalities. A typical composi­tion of the low-energy fuel gas was reported to be 18 mol % carbon monoxide, 9 mol % carbon dioxide, 1 mol % methane, 17 mol % hydrogen, 45 mol % nitrogen, and 10 mol % water. On a distance traveled basis, about 3.0 to 3.6 kg of wood fuel was estimated to equate to 1 L of gasoline.

Steam Gasification

Steam is also blended with air in some gasification units to promote the overall process via the endothermic steam-carbon reactions to form hydrogen and carbon monoxide. This was common practice at the turn of the last century, when producer gasifiers were employed to manufacture low-energy gas from virgin and waste biomass. The producer gas from these gasifiers generally had heating values around 5.9 MJ/m3 (n), and the energy yields as gas ranged up to about 70% of the energy contained in the feed.

Study of the steam gasification of biomass in a sequential pyrolysis-steam reforming apparatus has shown that gasification occurs as a two-step process (Antal, 1978). At temperatures in the 300 to 500°C range, volatile compounds are evolved from biomass and some residual char is formed. At about 600°C, the volatile compounds are steam reformed to yield synthesis gases. The con­densable tars, oils, and pitches are reduced by the steam reforming reactions to less than 10 wt % of the original feedstock. Table 9.5 is a summary of the steam gasification of pure cellulose that illustrates the effects of temperature and residence time in the steam reformer on product yields. As temperature and residence time are increased, char and tar yields decrease and gas yields increase as expected. A medium-energy gas was produced in these experiments because of the relatively high concentrations of lower molecular weight hydro­carbons in the product gas.

An obvious improvement in the steam gasification of biomass for synthesis gas production is to operate at higher temperatures and to use catalysts to gasify as much of the char and liquid products as possible. Laboratory-scale experiments have been carried out to examine this possibility (Mitchell et al, 1980). Nickel precipitated on silica alumina (1:1) and a mixture of silica alumina and nickel on alumina were evaluated as catalysts for steam gasification at 750°C and 850°C and atmospheric pressure. The results are summarized in Table 9.6. The function of the silica alumina is to crack the hydrocarbon

intermediates, and the function of the nickel is to promote methane reforming and the hydrogenolysis of higher molecular weight hydrocarbons. It is evident from the data in Table 9.6 that a synthesis gas almost stoichiometric for methanol synthesis can be produced from wood at high yields by catalytic steam gasification in a single-stage reactor at atmospheric pressure. Potential methanol yields over 60 wt % of the wood feedstock were estimated. The advantages of catalytic steam gasification of biomass over steam-oxygen gasifi­cation include elimination of the need for an oxygen plant and shift conversion, higher methanol yields for a stand-alone plant, and less carbon dioxide forma­tion. Using the data from the example in Table 9.6 in which the steam-to — wood weight ratio is 0.71, and assuming wood that contains 20 wt % moisture is fed at 100°C with steam at 850°C, the net reactor heat requirement is estimated to be 2800 kj/kg of dry wood.

The various stoichiometric equations listed in Table 9.1 suggest that synthe­sis gas mixtures from biomass gasification are generally deficient in hydrogen for methanol synthesis; i. e., the molar ratio of H2: CO is less than 2. The use of steam in biomass gasification could conceivably increase hydrogen yields by reaction of residual char, if formed, via the steam-carbon reaction. Steam gasification might also make it possible to use green biomass feedstocks without drying. Under the proper gasification conditions, the use of oxygen or air to meet any heat requirements would be expected to increase the yields of carbon oxides, but an oxygen plant is required in the case of oxygen usage. Gas quality would suffer with air because of nitrogen dilution of the product gases unless air is utilized separately from the gasification process, as already mentioned. However, as just indicated (Mitchell et al, 1980), it has been shown that product gases containing a 2:1 molar ratio of hydrogen to carbon monoxide can be produced without use of a separate water gas shift unit:

C6H10O5 + 3H20 -» 4CO + 2C02 + 8H2.

Gasification of biomass for methanol synthesis under these conditions would offer several advantages if such processes can be scaled to commercial size.

Commercial methanol synthesis is performed mainly with natural gas feed­stocks via synthesis gas. Synthesis gas from biomass gasification could conceiv­ably be used as a cofeedstock in an existing natural gas-to-methanol plant to utilize the excess hydrogen produced on steam reforming natural gas. Examina­tion of a hypothetical hybrid plant has been shown to have significant benefits (Rock, 1982). Typical synthesis gas mixtures from the steam-oxygen gasifica­tion of wood and the steam reforming of natural gas are as follows:

From wood: 2CO + C02 + 1.8H2

From natural gas: 5.2/3(2CO + C02 + 10H2)

Combined: 5.5CO + 2.7C02 + 19.1H2.

This combined synthesis gas mixture is stoichiometric for methanol synthesis:

5.5CO + 2.7C02 + 19.1H2 -* 8.2CH3OH + 2.7H20.

The stoichiometry for methanol from the unmixed gases is

2CO + C02 + 1.8H2 + 0.73H2O 1.27CH3OH + 1.73C02

5.2/3(2CO + C02 + 10H2) 5.2CH3 OH + 5.2H2 + 1.73H20.

The unmixed synthesis gases produce 6.47 mol of methanol, of which 1.27 mol comes from wood, and the mixed synthesis gases yield 8.20 mol of methanol. In theory, the use of the combined synthesis gases provides 24% more synthesis gas, but methanol production is increased by 58% over that from natural gas alone. Since hydrogen in the purge gas in the reformed natural gas case has been largely consumed in the hybrid case, the total purge gas stream is greatly reduced. This purge gas is normally used as fuel in the reforming furnace and its reduction must be balanced by firing additional natural gas or other fuel for reforming. The use of natural gas and fuel is about 25% lower for the hybrid design than when using natural gas only for the production of the same amount of methanol. In addition, the hybrid version has eliminated the water gas shift and acid gas removal equipment from the wood gasification process alone. This serves to reduce both capital and operat­ing costs associated with wood-derived synthesis gas.

The stoichiometry of this particular hybrid process is approximately as follows:

Wood: 0.5C6H10O5 + 1.102 — 2CO + C02 + 1.8H2 + 0.7H2O

Natural gas: 5.2CH4 + 6.93H20 — 3.47CO + 1.73C02 + 17.33H2

Methanol synthesis: 5.47CO + 2.73C02 + 19.13H2 — 8.2CH3OH + 2.73H20 Net: 0.5C6H10O5 + 5.2CH4 4- 3.5H20 + 1.Ю2 -► 8.2CH3OH.

By use of the enthalpy of formation for dry poplar wood of 840.1 kj/g-mol (361,440 Btu/lb-mol) of cellulosic monomeric unit at 300 K, which is calculated from its measured heat of combustion and the standard enthalpies of formation for the other components, the enthalpy changes for wood gasification (with oxygen) to synthesis gas, the steam reforming of natural gas, and methanol synthesis, are calculated to be —363.8, 1001, and —631.5 k], respectively. In theory, the overall enthalpy change is almost zero, 5.7 kj. Biomass gasification can of course be carried out in several ways, and the gas compositions used for this analysis are idealized. But this type of analysis makes it possible to calculate several parameters of interest. For example, assuming 100% selectivi- ties for intermediates and products, or that no by-products are formed, and that poplar wood and natural gas are accurately represented by (C6H10O5) and CH4, the feedstock rates for a 907-t/day (1000-ton/d) methanol plant are estimated to be 0.4 million m3 (n)/day (288 t/day) of natural gas and 280 t/ day of dry wood.

In 1955, Farrington Daniels, professor of chemistry at the University of Wisconsin from 1920 to 1959 and a pioneer in solar energy applications, stated (Daniels and Duffle, 1955):

POPULATION, BILLION EJ/YEAR

YEAR

-s — POPULATION, BILLION EJ/YEAR

FIGURE 1.7 World population and consumption of fossil fuels, 1860—1990.

GJ/CAPITA-YEAR

100

YEAR

EJ/YEAR GJ/CAPITA-YEAR

FIGURE 1.8 World consumption of coal, oil, and natural gas, 1860-1990.

. . . our fuels were produced millions of years ago and through geological accident preserved for us in the form of coal, oil, and gas. These are essentially irreplaceable, yet we are using them up at a rapid rate. Although exhaustion of our fossil fuels is not imminent, it is inevitable.

Few people paid any attention to such remarks at that time. Many regarded them as the usual gloom-and-doom commentary of the day.

Between 1860 and 1990, the world’s population and the consumption of fossil fuels per capita sequentially doubled almost three times and four times, but over the same period of years, global consumption of fossil fuels passed through six sequential doubling cycles. The doubling times for global fossil fuel consumption, population, and fossil fuel consumption per capita in the mid-1990s were approximately 25, 35, and 50 years, respectively (Table 1.4). These trends suggest several features of a society whose gradual and then rapid industrialization has depended on the availability of energy and fuels, namely that fossil fuel consumption is disproportionately increasing as more and more of the world’s population is industrialized despite the large improvements in the efficiency of energy utilization over the past 50 years. Human activity and interactions at all levels require the acquisition and consumption of energy and fuels, no matter what the living standards are. It is simply a matter of increasing population and the apparent preference for energy-rich, high-quality fossil fuels. Questions of where recoverable fossil fuel deposits are located and the size of these deposits are obvious. How long will it be, for example, before the world’s supplies of petroleum crude oils begin to permanently fall short of demand?

Energy specialists and reservoir engineers in the United States and several other countries use “proved reserves” to predict the amounts of coal, oil, and natural gas that can be produced and marketed. Proved reserves are defined

as the estimated portion of a natural fossil fuel deposit that is projected from analysis of geological and engineering data with a reasonably high degree of certainty, usually a combination of experimental field data, modeling, and experience, to be economically recoverable in future years under existing economic and operating conditions. Unfortunately, there are no international standards for estimating or defining reserves, and there are many problems associated with development of accurate proved reserves figures. They are, however, the best running accounting method available today to project fossil energy supplies.

Examination of the world’s proved reserves of coal, crude oil, and natural gas and their regional locations shows that well over half of the world’s crude oil and natural gas supplies are located in the Middle East and the former Soviet Union, while North America, the Far East, and the former Soviet Union have over 70% of the coal reserves (Table 1.5, Fig. 1.9).

Intuitively, these data suggest that countries in those regions having large amounts of specific proved fossil fuel reserves would tend, because of proximity to these resources, to consume more of the indigenous fossil fuels than those

TOTAL = 1039 BILLION METRIC TONNES

WESTERN EUROPE 2%

FAR EAST & OCEANIA 6%

TOTAL = 163.7 BILLION CUBIC METERS

c

FORMER U. S.S. R. 42%

MIDDLE EAST 28%

TOTAL = 136.4 TRILLION CUBIC METERS

that are not within their confines. This is often the case, as illustrated by some of the data in Table 1.3 for the world’s 10 highest energy-consuming countries. There are many exceptions. The proved reserves-to-annual consumption ratios calculated from the proved reserves and annual consumption data for coal, crude oil, and natural gas for a few selected countries illustrate some of these exceptions (Table 1.6). In theory, these ratios indicate the number of years until the proved reserves of a particular resource are exhausted, assuming no imports of fossil fuels, a constant rate of fuel consumption, and no further discoveries of economically recoverable coal, oil, or natural gas. According to these data, a 258-year supply of coal, the world’s largest energy resource of the three conventional fossil fuels, is available in the United States, whereas oil and natural gas have much shorter depletion times. Nevertheless, coal currently contributes less to energy demand than either oil or natural gas. In contrast, other countries such as China, Germany, and India have large proved reserves of coal and consume relatively large amounts, while Saudi Arabia has essentially no proved coal reserves and consumes none. Worldwide, coal consumption grew at an annual rate of 1.4% between 1980 and 1993 and accounted for about 25% of the world’s total energy use in 1993, so it continues to be an important energy resource.

Oil is clearly a much smaller fossil energy resource than coal. Because of its intrinsic properties such as high energy density, ease of transport, storage, and conversion to storable liquid fuels, and an existing infrastructure that facilitates worldwide distribution of refined products to the consumer, it is the fossil fuel of choice for the manufacture of motor fuels. Some countries, such as Japan, that have little or no proved reserves of oil consume relatively large quantities and are therefore strongly dependent on imports to meet demand. Some countries, such as Saudi Arabia, have an abundance of proved oil reserves and supply their own demands as well as a large fraction of the world’s markets. Global consumption of oil increased by 18.4 EJ between 1983 and 1992 at an annual rate of growth of 1.5% (U. S. Dept, of Energy, 1994). Motor fuels from oil are expected to remain the dominant international trans­portation fuel for the foreseeable future. Other projections indicate that global consumption of oil will exhibit a growth rate of nearly 2% per year up to 2015 (U. S. Dept, of Energy, 1996). While natural gas and renewables are making inroads into the energy markets of OECD (Organization for Economic Cooper­ation and Development) nations, leading to a decline in oil’s share in those

FIGURE 1.9 (a) World coal reserves by region, December 31, 1990. (b) World oil reserves by region, January 1, 1993. (c) World natural gas reserves by region, January 1, 1993.

markets, its share is rising in the developing nations as transportation, indus­trial, and other uses for oil expand.

Natural gas is somewhat similar to oil in that it is a relatively clean-burning fuel compared to coal. Long-distance pipelines have been built in many devel­oped and developing countries to deliver gas from the producing areas to large urban markets where it is delivered to the consumer via local gas distribution networks. In modern combined-cycle, cogeneration systems, it is generally the fossil fuel of choice for electric power production and stationary applications. Again, a correlation does not necessarily exist between the location of indige­nous proved reserves in a given country and energy consumption in that country. Japan is an example of a country that has no natural gas reserves, yet consumes considerable natural gas that is transported to Japan from producing countries as liquefied natural gas (LNG) in large cryogenic tankers. Another example is the utilization of the large reserves of natural gas in Eastern Europe. Consumption is high in Eastern Europe, but high-pressure pipelines are used to transport natural gas from producing regions in Eastern Europe to Western Europe where proved reserves are small. Natural gas is the fastest-growing fossil fuel in the world’s energy mix. Its annual rate of growth in production was 3.7% from 1983 to 1992, and it contributed 22% to world energy demand in 1993.

A somewhat more quantitative estimate of depletion times for fossil fuels can be calculated under specific conditions using a simple model that accounts for proved reserves and growth rates in consumption (Appendix B). Application of this model to the consumption of global proved reserves of petroleum crude oils is presented here. Calculation of global depletion times eliminates the problem of accounting for imports and exports. The conditions assumed for these calculations are those for 1992. The world’s proved reserves are 6448 EJ, the annual consumption is 144 EJ, and the average annual growth rate in consumption of petroleum products is assumed to be a conservative 1.2%, which is projected by the U. S. Department of Energy to hold until 2010. Under these assumed conditions, the depletion time of the proved reserves of petroleum is 35 years, or the year 2027.

Current estimates of proved reserves do not represent the ultimate recover­able reserves because of ongoing oil exploration activities and new discoveries, which have generally been able to sustain proved reserves for several decades. For this reason, and because changing economic conditions and technical improvements affect the assessment of proved reserves and the economic recoverability of oil from lower-grade reserves and unconventional reserves of tar sands and oil shales, calculation of the depletion time for several multiples of the proved reserves is also of interest. The depletion time for five times the proved reserves (32,240 EJ) at the same consumption rate is 108 years, or the year 2100. The ultimate recoverable reserves are believed to be closer to two times the world’s proved reserves of oil and syncrudes (12,896 EJ) from unconventional sources (Institute of Gas Technology, 1989). Note that the depletion time of 108 years for five times the proved reserves is not a factor of five greater than that calculated for proved reserves of 6448 EJ because of the compounding effect of the growth rate in consumption of 1.2% per year; it is about three times greater. The changes in remaining reserves with time from these calculations are illustrated in Fig. 1.10.

Despite the facts that world trade in the international oil and natural gas markets is flourishing and there is little sign of a significant reduction in energy

YEAR

RESERVES OF 6448 EJ FIVE TIMES RESERVES

BASELINE CONSUMPTION IN 1992 IS 144 EJ

FIGURE 1.10 Global depletion of petroleum reserves at annual consumption growth rate of 1.2%.

consumption, the limited data and simplified analysis presented here suggest that gradual depletion of oil and natural gas reserves can be expected to become a major problem by the middle of the twenty-first century. Without preparation and long-range planning to develop alternative fuels, particularly nonpolluting liquid motor fuels for large-scale worldwide distribution and clean-burning fuels for power production in stationary applications, energy and fuel shortages could become severe. The disruptions in energy and fuel supply and availability that occurred in the 1970s illustrate the potential impact on society. The oil marketing policies of the Organization of Petroleum Exporting Countries (OPEC) and the resulting First Oil Shock in 1973-74 had a lasting impact on the international oil markets and the energy policies of most industrialized nations. In 1973, Mideast light crude oil spot market prices rose to about $13 per barrel from a low of about $2 per barrel. The Second Oil Shock began in 1979 as a result of OPEC’s curtailment of production until spot Mideast oil prices peaked in early 1980 at $38.63 per barrel. Major policy changes and legislative actions occurred in many industrialized countries to try to counteract these conditions. The First Oil Shock resulted in a flurry of legislative activities and executive orders by the executive and legislative branches of the U. S. Government, for example, that affected literally all energy-related sectors. This was actually the beginning of national policies in many countries to develop new indigenous energy supplies. In the United States, the federal laws that have been enacted since the First and Second Oil Shocks have had a profound and continuing impact on all U. S. energy production and utilization. When it was realized that oil prices and availability could be manipulated or controlled to a significant extent by outside forces and how important these factors and their impact are for the U. S. economy, massive programs were undertaken to make the United States less dependent on imported oil. Other nations have taken similar actions. Many of these programs continue today.

A few words of caution are warranted in dealing with depletion times and the proved reserves of fossil fuels, that is, the possibility of new discoveries, the variability of depletion time, the effects of new technologies, and the uncertainty of predictions. Detailed assessment of the proved reserves-to — consumption ratios for oil and natural gas over the past several decades shows that although there has been a slight decline in the values of specific proved reserves reported by some sources, new additions to proved reserves have been able to sustain market demands over many years while the calculations indicated that depletion should have occurred in just a few years. The estimated depletion times calculated in the mid-1970s showed, for example, that the global reserves of natural gas should have been depleted by about 1995. Discov­ery of large new reserves capable of economic production, the development of significantly improved gas producing and processing methods, higher gas utilization efficiencies by end-use equipment, and lower actual annual growth rates in consumption than those predicted have all contributed to prolong depletion and the time of depletion. Basically, the estimates of the world’s total remaining recoverable reserves of oil and natural gas have been sustained and continue to keep pace with consumption. But given the extensive periods of time required to replenish finite supplies of fossil fuels, the earth is not an infinite source of these materials when considered in terms of world energy demand and population growth. Presuming Professor Daniels’ prediction that depletion of coal, oil, and natural gas is truly inevitable, it is still prudent to use these natural resources wisely. This will help conserve our valuable fossil fuels and extend the time when depletion and the unavoidable rise in energy prices and shortages occur and become a fact of life. The coupling of fossil fuel usage and environmental problems may eventually result in the equivalent of mandated conservation of fossil fuels.

The production of marine biomass in the ocean, even on the largest scale envisaged for energy applications, would require only a very small fraction of

the available ocean areas. For example, it is estimated that, depending on biomass yield, a square area about 320 to 540 km on each edge off the coast of California may be sufficient to produce enough giant brown kelp for conversion to methane to supply all U. S. natural gas needs (Bryce, 1978). This is a large area, but it is very small when compared with the total area of the Pacific Ocean. Also, the benefits to other marine life from large kelp plantations have been well documented. Any conflicts that might arise would be concerned primarily with ocean traffic. With the proper plantation design for marine biomass and precautionary measures to warn approaching ships, it is expected that marine biomass growth could be sustained over long periods.

Freshwater biomass could in theory be grown on the 20 million ha of fresh water in the United States. But there are several difficulties that mitigate against large-scale freshwater biomass energy systems. About 80% of the fresh water in the United States is located in the northern states, whereas several of the freshwater biomass species considered for energy applications require a warm climate such as that found in Gulf states. The freshwater areas suitable for biomass production in the southern states, however, are much smaller than those in the North, and the density of usage is higher in southern inland waters. Overall, these characteristics make small-scale aquatic biomass produc­tion systems more feasible for energy applications. In the future, it may be advisable to examine the possibility of constructing large man-made lakes for this purpose, but this does not seem practical at this time except possibly where an aquatic biomass species is used for wastewater treatment.