Biomass and Coal Plus Biomass to Power

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Burning fossil fuels for power generation and for transportation releases carbon that has been stored for millions of years as CO2 into the atmosphere, resulting in the build-up of atmospheric CO2. Using biomass as a fuel releases carbon removed as CO2 from the atmosphere in a recent plant growth cycle and does not contribute to increasing atmospheric CO2 concentration if done sustainably. Thus, using biomass in power generation reduces the life-cycle emissions of CO2 per unit of power generated.

Biomass can be burned directly or co-fired with coal in a boiler. The major issues are effective size reduction of the biomass in order to feed it into the boiler and its lower energy density. Today, most biomass power plants burn demolition wood wastes, forest product wastes or agricultural wastes to produce steam for power generation. The U.S. has 11 GW of installed biomass-only plant capacity [30], with an average size of 20 MWe. The industry average generating efficiency is of order 20%. Typically SOx emissions are low because biomass contains little sulfur, but NOx emissions can be quite high because the relatively high nitrogen content of many biofuels. These emissions can be controlled, at a cost, which, however, can be significant on small units. A generally more attractive approach is to co-fire biomass at levels of less than 25% (wt.%) with coal to gain the advantages of scale of a much larger generating facility and reduced CO2 emissions per kWe-h generated. The other option is to gasify the biomass and generate power in a combined-cycled configured power island. Gasification technology is considered below, and the economic and CO2 impacts of using biomass to generate power are discussed. Thermochemical Conversion of Biomass

Biomass gasification and/or pyrolysis involves the conversion of biomass to a mixture of carbon monoxide, hydrogen, carbon dioxide, methane, and other organics including bio-oils and tars, ash and small char particles. The concentration of these gases and other materials depends on the process design, and operating conditions. Gasification has the advantage that it can convert essentially any biomass material to syngas at sufficiently severe conditions (Fig. 2.14). This syngas can be burned in a boiler or can be cleaned and burned in a turbine in a combined cycle power island to produce electricity. It could also be cleaned and shifted to produce a synthesis gas from which a broad range of fuel and chemical products can be produced. This latter option is considered in Chap. 3. Biomass gasification exhibits many similarities to coal gasification, including a significant number of gasifier types and different approaches to gasification technology. Electricity or fuels produced via gasification of biomass should have low net CO2 emissions; and if biomass gasification is combined with capture and geologic storage of CO2, such processes have a negative CO2 emission footprint.

Gasification can be carried out under a variety of pressure and temperature conditions. When relatively low pressures and temperatures are used, it is primarily a pyrolysis process. Under these less-severe conditions, the main products are a mixture of hydrogen, CO, and light hydrocarbons, bio-oil, tars, and char. For less-severe gasification (pyrolysis), the heating is usually indirect, avoiding the need for an expensive air separation unit, reducing the capital cost significantly. The mix of

Biomass Pyrolysis Upon

Gases Liquids & Char

Gasification Reactions


Heating to ~ 500°C

Char/Liquids/Gases, ~1100°C

Fig. 2.14 Schematic of thermochemical conversion of biomass, flow from left to right. Pyrolysis produces a broad range of materials, including bio-oils and tars, which can undergoes gasification at higher temperatures to produce syngas, which is composed primarily of CO, H2, and CO2. One-step gasification at high temperature combines the pyrolysis and gasification stages to rapidly produce only syngas


Fig. 2.14 Schematic of thermochemical conversion of biomass, flow from left to right. Pyrolysis produces a broad range of materials, including bio-oils and tars, which can undergoes gasification at higher temperatures to produce syngas, which is composed primarily of CO, H2, and CO2. One-step gasification at high temperature combines the pyrolysis and gasification stages to rapidly produce only syngas primary products can be separated into several fractions for upgrading of for gasification or combustion. The gas stream can also be cleaned, compressed, the CO shifted to H2 and CO2, and the CO2 removed for geologic storage.1 If air is used directly as an oxidant in gasification, the nitrogen present results in a low Btu gas that is most easily used for steam or power generation via a boiler or combustion turbine but without CCS.

Biomass gasification using direct firing with oxygen at higher pressure and temperature produces a relatively pure syngas stream of CO and H2, with some CO2 and other gases. For temperatures greater than 1,100°C, little or no methane, higher hydrocarbons, or tar are present. The high oxygen content of biomass reduces the oxygen requirement and thus the air separation unit size and cost. With biomass there is almost no sulfur, limited ash, or few other contaminants to deal with, although there are issues with some feedstocks such as rice straw that contain silicon.

Several U.S. and European organizations are developing advanced biomass gasification technologies, and there are about ten different biomass gasifiers with a capacity greater than 100 tonnes per day operating in the U.S., Europe, and Japan. These units demonstrate a broad range of feedstocks, of feed capabilities, of gas-ifier characteristics, of product gas clean-up approaches, and of primary products. Biomass Technology Group (BTG) lists over 90 installations (most are small) and over 60 manufacturers of gasification technologies [31]. A recent NETL benchmarking report summarizes the status of larger scale biomass gasifiers [32] For example, at the McNeil Generating Station in Vermont, a low-pressure wood gasifier, which started operation in August 2000, converted 200 tonnes per day of wood chips into fuel gas for electricity generation [33].

Most of the gasification technologies have technical or operational challenges associated with them, but most of these issues are probably resolvable or manageable with commercial experience. Gasifier choice depends on the type of biomass feed and on the specific application of the gasification/pyrolysis products. The most persistent problem area appears to be biomass feed processing and handling, particularly if a gasifier must contend with different biomass feeds. DOE has funded five different advanced biomass R&D projects to advance the technology [33]. Although several of the available gasification technologies have been commercially demonstrated, biomass gasification technology has yet to be robustly demonstrated for commercial, integrated biomass gasification and power generation. The implication is that biomass gasification technology is still on a relatively steep learning curve, as is the integration of biomass gasification, gas clean up, and power generation or biofuel synthesis. A major characteristic of biomass gasification is that it will involve smaller units than coal gasification, and it will thus not benefit from the economies of scale of coal gasification. This is because of the dispersed nature

1 Geologic storage of CO2 (deep saline aquifer, depleted oil and gas reservoirs, and enhanced oil recovery) is considered most likely; other options such as deep ocean storage are considered unlikely.

of biomass and cost of biomass transport, which limit the area that could supply feedstock to a given plant to a relatively small radius near the plant site. This limits annual biomass feed availability to a given plant. This will increase the cost per unit product unless major process simplification and capital cost reductions can be achieved. A primary strategy has been to eliminate the air separation unit, which is typically required with most high-severity gasification technologies. This leads to gasification with air and involves nitrogen-diluted syngas or involves indirect heating to avoid nitrogen dilution which then typically produces a product stream containing more bio-oil, tar, and light hydrocarbon gases. Power Generation

Next, the cost and performance, including CO2 impacts, of biomass to power are examined. Because of the small scale of biomass-to-power plants and the higher cost of biomass vs. coal, biomass-combustion based power generation is generally not competitive with PC generation. However, with Renewable Energy Credits that are in effect in some locations, the technology can be profitable [34]. These cost issues can be reduced by co-firing with coal at a coal plant. In this case, there is additional expense associated with the higher cost of biomass vs. coal and with the facilities needed for biomass receiving, storage, preparation, and feeding into the boiler. These are in addition to the coal handling facilities. The rest of the PC unit remains essential the same. CO2 emissions reductions are in direct proportion to the ratio of carbon per unit of biomass energy feed to the plant to the carbon per unit of coal energy feed.

The other approach to power generation involves gasification of biomass plus combined-cycle power generation. Using the approach outlined earlier for evaluating coal power plants, and utilizing a steam/oxygen blown fluidized-bed gasifier with gas cooling and gas cleaning for the biomass feed, a consistent set of cost and performance estimates were made [11, 35]. Table 2.7 summarizes these projections for biomass to power. It was assumed that the plants were sited such that 1 million tonnes of dry biomass per year is available for the plant (3,790 tonnes/day, 85% capacity factor).

Subcritical generation is assumed for conventional combustion, steam generation; CCS was not considered because of the high cost of flue gas CO2 capture. Capital cost is higher primarily due to smaller unit size, and biomass fuel cost is more than twice that of coal. The resulting COE at 1O0/kWe-h is about 70% higher than for a larger PC plant (5.80/kWe-h) (Table 2.7 and Table 2.4). Although plant CO2 emissions are similar to those of a coal-based plant, life-cycle CO2 emissions are very small because the CO2 was recently captured and will be recaptured in the next growth cycle. The small positive value (50 g CO2eq/kWe-h) is due to fossil-based emissions occurring in biomass production and transport.

Gasification-based generation [11] has higher efficiency with biomass, driven by lower utility costs for air separation and gas clean-up due to the high biomass oxygen content and low impurity levels. Estimated COE for biomass IGCC is about

Table 2.7 Projected cost and performance of power generation from biomass, and from coal plus biomass

Biomass subcritical Biomass IGCC Coal/biomass IGCC

Table 2.7 Projected cost and performance of power generation from biomass, and from coal plus biomass

Biomass subcritical Biomass IGCC Coal/biomass IGCC

w/o capture

w/o capture

w/ capture

w/o capture

w/ capture


Heat ratea, Btu/k\V-h






Generating efficiency (HHV). %






Coal feed, tonnes/day (AR)






Biomass feed, tonnes/day (AR)

Carbon in feed, kg/h






CO, emitted, kg/h






CO, captured. kg/hb






Plant CO, emitted. g/kW-h






Life-Cycle CO, emitted. g/kW-h







Total plant cost. $/kW






Total capital required. $/kW






Inv. charge. 0/kWe-h @ 14.4%c






Fuel. 0/kW-h






O&M. 0/kW-h






COE, i/kW^-h






CO, Disposal cost. 0/kWe-h






COEd, t/kVV-h total






Cost of CO, avoided vs. same



technology w/o captured, $/tonne

Basis: 500 MW plant net output. Illinois #6 coal (63.7%wt C. 27.1 MJ/kg (HHV). 85% cap Fac) aEfficiency = 3,414 Btu/kW-h/ (heat rate)

b90% removal used for all capture cases, except PC-Oxy which was assumed 95%

""Annual capital charge rate of 14.4% from EPRI-TAG methodology, based on 55% debt @ 6.5%. 45% equity @ 11.5%. 38% tax rate. 2% inflation rate. 3 year construction period. 20 year book life, applied to total plant cost to calculate investment charge dIncludes the cost of CO, transport and geologic storage, details discussed in the text

50% higher than for PC generation and about 30% higher than coal IGCC, primarily because of the higher cost of biomass. Because biomass is the only feed, the electricity generated is essentially CO2 neutral, because the CO2 emitted from the plant was recently removed from the atmosphere and will be recaptured in the next growth cycle. However, it actually has a negative life-cycle CO2 balance of minus 26 g CO2eq/kWe-h (without CCS) because the char from the gasification contains more carbon than fossil carbon consumed in the production and transportation of the biomass. This carbon is assumed permanently sequestered with the char. The COE for biomass IGCC is less than coal IGCC with CCS which still has a life-cycle CO2 balance of +138 g CO2 /kW -h.

2 2eq e

At zero life-cycle GHG (CO2eq) price, biomass gasification with CCS has a COE that is about 25% higher than coal IGCC with CCS, but it has a large negative life-cycle CO2 balance (-740 g CO2eq/kWe-h) associated with it. Therefore, it would receive a large CO2eq credit in any carbon tax or carbon-trading regime. The cost of CO2eq avoided is $48/tonne (Table 2.7). If coal-based PC with CCS is compared with biomass IGCC venting the CO2 the avoided cost of CO2eq is about $14/tonne. Comparing coal-based IGCC with CCS with biomass IGCC with venting, the cost of avoided CO2eq is effectively zero (slightly negative) as is coal-based IGCC with CCS compared with biomass IGCC with CCS (slightly positive $/tonne CO2eq avoided). These numbers should be considered to be zero within the ability to estimate costs at this point.

Co-feeding coal and biomass can provide improved generating economies-of-scale and reduced CO2 emissions. To accommodate the different properties of biomass and coal, the process design estimates here are based on biomass gasification utilizing a steam/oxygen blown fluidized-bed gasifier and coal gasification via an entrained flow GE Texaco gasifier. Coal to biomass feeds were 60%/40% on an energy basis; 3,480 tonnes/day coal and 3,790 tonnes/day biomass, each on an as-received (AR) basis (Table 2.7) [11, 35]. The quenched syngas streams were combined to take advantage of available economies of scale downstream of gasification. With this configuration, without CCS, the COE for the coal/biomass case is about 20% higher (1.20/kWe-h) than for the coal only case due mainly to the higher biomass fuel cost. Although the plant CO2 emissions are similar, the life-cycle CO2 emissions are 478 g CO /kW -h or about 40% less due to the 40% biomass feed,

° 2eq e without CCS. With CCS, the COE is also about 20% higher (~2.00/kWe-h) for the coal/biomass case than for the coal-only emissions are -278 g CO /kW -h for the

2eq e kWh for the coal-only IGCC with CCS.

coal/biomass case than for the coal-only IGCC case. However, the life-cycle CO2eq emissions are -278 g CO2eq/kWe-h for the coal plus biomass case vs. +138 g CO2eq/

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