Part 1 was an overview of the energy strategies the country needs to stop building new coal plants and start reducing emissions from existing ones, focusing on energy efficiency, wind, and concentrated solar power. Biomass cofiring will be the focus of a couple of posts since, although rarely-discussed, it is probably the cheapest, easiest, and fastest way to provide new renewable baseload power without having to build any new transmission lines.
I first started analyzing the carbon benefits of cofiring biomass with coal in 1997 when I was overseeing a study by five U.S. national laboratories that examined what an aggressive technology-based strategy built around energy efficiency and renewable energy could achieve in terms of emissions reductions. (See full study here and some history on it by California Energy Commissioner Art Rosenfeld here.) With supporting analysis done by the Electric Power Research Institute, the Five Lab Study concluded that biomass cofiring was the single biggest potential contributor to near-term greenhouse gas reductions of any renewable energy strategy.
Cofiring is a well demonstrated strategy with multiple benefits. From a practical perspective, most of the existing coal plants are mostly paid off. Plus they are fully permitted and have all the necessary transmission plus they are connected to freight train lines and water supply. Plus this is baseload power. So you avoid all of the problems associated with citing new renewables in the Midwest or Southwest. Cofiring is thus a key near-term strategy for meeting climate goals — and renewable standards — in the midwest and southeast.
And, again, this is baseload power, and your typical coal plant has a capacity factor that is some 2 to 3 times larger than that of wind. So 20 GW of biomass coal firing will generate as much power as 50 GW of wind.
The down side of co-firing is, of course, that it is biomass power, and thus may prove not to be either scalable or sustainable in the long term (see “Are biofuels a core climate solution?“). But as a strategy for existing coal utilities to start weaning themselves off of coal over the next two decades, cofiring may be a critical piece.
Also, in the event that carbon capture and storage ever proves practical, affordable and scalable — which is no slam dunk to say the least (see “Is coal with carbon capture and storage a core climate solution?“) — then we will certainly want to insist that coal plants with CCS including biomass cofiring. After all, what strategy could be more important for averting catastrophic global warming than pulling CO2 out of the air with biomass and then sequestering that CO2 in underground repositories. Such coal with biomassing cofiring and CCS — BCCCS — has the potential to be negative-carbon electricity.
You may ask why you hardly hear anything about biomass cofiring if it is such a great idea. That will be covered in Part 3. In the rest of this post, I will reprint the discussion of biomass cofiring from Chapter 7 — Electricity Supply Technologies of the Five Lab Study:
[Note: In the interest of space and readability, I won’t indent this lengthy extract. Also certain numbers below, such as the price of coal, are out of date. I will present more recent analyses in the next post.]
220.127.116.11 Cofiring Coal with Biomass
Cofiring biomass with coal has the technical and economic potential to replace at least 8 GW of the nation’s coal-based generating capacity by 2010, and as much as 26 GW by 2020.
Though the current substitution rate is negligible, a rapid expansion is possible with the use of wood residues (urban wood, pallets, and secondary manufacturing products) and dedicated feedstock supply systems (DFSS) such as willow, poplar, and switchgrass.
The current coal-fired power-generating system represents a direct opportunity for carbon mitigation by substituting biomass-based renewable carbon for fossil carbon. Extensive demonstrations and trials have shown that biomass can replace up to about 15% of the total energy input with little more than burner and feed-intake system modifications to existing stations (CONEG, 1996). Since large-scale power boilers in today’s 310-GWcapacity fleet range from 100 MW to 1.3 GW, the biomass potential in a single boiler ranges from 15-150 MW.
Preparation of biomass to an appropriate size of less than one-quarter inch, with a moisture content of less than 25%, can be achieved using existing commercial technologies. “Tuning” the combustion output of the boilers causes little loss in total efficiency, implying that the biomass-to-electricity combustion efficiency is close to the 33-37% range of an unmodified coal plant, an efficiency that stand-alone biomass generating capacity has yet to demonstrate.
The cost of implementing biomass cofiring varies from site to site. It is influenced by the space available for yarding and storing the biomass, the installation of size-reduction and drying facilities, and the nature of the boiler burner modifications required. The cost is expected to be in the range of $100-$700/kW of biomass capacity. Early trials indicate that a median value of about $180/kW is likely. A 100-MW coal plant with 10% biomass substitution would then require an investment of $1.8 million. There is an O&M cost increase of $70,000/year over coal, as a result of the need for an additional yard worker to handle the biomass. Assuming a GENCO recovers its investment cost in three years, the annual fuel offset then has to be $670,000 to cover capital recovery ($1.8 million) and increased O&M costs ($210,000 for three years). If the average price of coal is about $1.40/MBtu (million Btu), the annual fuel cost of coal is $1.081 million (10 MW of biomass capacity at 85% capacity factor and 32.9% thermal efficiency, 10,337 Btu/kWh). The allowable cost of biomass then is $411,000, or about $9/tonne. Above this cost, the biomass would have to be subsidized to encourage a GENCO to use biomass cofiring.
[JR: Ultimately cofiring will be driven by climate regulations and whatever price for carbon is established.]
Near-term potential biomass feedstocks are those residues available within a radius of about 50 miles around a plant. Data from existing biomass power plants in the Northeast and California indicate that there are extensive sources of biomass residues available for about $0.50/MBtu (less than $9/tonne). Transportation costs limit the range over which such biomass feedstocks can be acquired and, in the long term, there are likely to be dedicated feedstock systems much closer to the power plants. By definition, residues (e.g., urban wood residues, rights-of-way clearance, construction and demolition wood, pallets, and sawdust shavings from secondary wood processing) are finite and will respond to the prices offered for them.
Dedicated feedstocks would not be bound by this constraint. However, such feedstocks are much more expensive than residues. With current technology the price is about $2/MBtu, although the current development goal is in the range of $1-$1.50/MBtu. It is assumed that an estimated 10.4 million acres will be needed to reach a nominal production of 86 Mt by 2020. Because DFSS is in an early stage of development, the model assumes that the initial planting will yield only about 6 tonnes/acre by 2002 (today’s state-of-the-art), and that by 2010 the yield will be closer to 8 tonnes/acre. Today’s costs are high; $45/tonne is feasible, but a combination of learning-curve improvements and economies of scale should bring the cost down to about $32/tonne by 2010. The competing coal price is assumed to be 1.40/MBtu ($1.33/GJ) throughout.
Biomass Substitution Potential
The cofiring estimates in this section were derived from a 30 GW scenario for all biomass technologies, developed by NREL for the current Biomass Power Program Strategic Plan. This scenario is for a mix of steam, cofiring, and integrated gasification/combined cycle (IGCC) biomass generation. However, the resource plan that was developed, which included residues and DFSS, is independent of the end use and involves the development of 11-12 million acres of land for DFSS by 2020, or just under 3 million acres by 2010. The resource development shown in Figure 7.11 is used as the basis for this carbon assessment. This indicates that DFSS would come on rapidly after the year 2001 and assumes that residues would be capable of only a small increase in quantity, since much is already being utilized.
The average cost of residues is expected to increase gradually, while the cost of DFSS crops is expected to demonstrate a strong learning curve and large economies of scale.
While a coal-fired station could be modified for cofiring in less than one year (including environmental permitting), a biomass resource assessment, contractual arrangements, and logistics for biomass residues could take the better part of 18 months, based on actual project experience. Although the availability of residues is assumed to be significant and would ultimately supply about 50 Mt, price and availability are likely to be variable. The price will no doubt increase with the level of demand; therefore, the biomass feedstock supply is
expected to be a blend of DFSS and residues.
The DFSS component is predicated on making a start on land accumulation (whether purchases, leases, or cooperatives), with land preparation and planting in 1999. A significant effort will be required to initiate development of the 11-12 million acres proposed for 2020; today, discussions are about DFSS demonstrations at the 1000-acre level. Adequate clonal material and management systems for planting, tending, and harvesting will also need to be developed. The crops of choice in much of the Northeast and Southeast are probably woody species, which would require extensive nursery activity to put the needed clonal material in place for planting out. With willow, the first harvest cycle would be four years after planting and a rotation of three years thereafter. For poplar, the cycle is likely to be in the range of six to eight years.
Because biomass generally contains significantly less sulfur than coal, cofiring with biomass could reduce SOx emissions. Early results suggest that there is also a NOx reduction potential using woody biomass. However, most coal-fired power stations have efficient precipitators and some have sulfur-capture technologies, so the net environmental effect of 10% biomass substitution (on an energy basis) appears to be negligible. The solid wastes (ash) would be little changed in either composition or mass (most biomass has considerably less ash than coal). But some stations sell fly ash to Portland cement manufacturers, so there may be a need to negotiate the acceptance of mixed biomass and coal ash in such applications with respect to ASTM standards.
The DFSS environmental impact is dependent on the choice of lands for plantations. Replacing annual cropland with perennial DFSS appears to result in a net environmental gain. Results for pasture land are probably negligible and replacement of forest may result in some increased impacts.
The use of residue has the potential to offset landfilling as well as potential methane emissions from landfilling clean biomass materials. Experiences in California indicate that the issue will be one of rationalizing the cost distribution between the waste generator, the hauling contractor, and the generating station receiving the residue rather than it going to a landfill. If such negotiations were successful, and the generating station could guarantee reception of the residues at all times (many urban wood residue generators do not have storage facilities), both residue costs and their availability could improve significantly.
Impact on Carbon Emissions
Given the technical and economic potential described above, it is probably reasonable to assume additional biomass-cofired capacity of 8-12 GW by 2010, which should reduce carbon emissions by 16-24 MtC.
[JR: And the study found that by 2020, we could achieve more than double that — 26 GW. Obviously, these time frames need to be pushed out several years, though the cofiring potential is quite significant for meeting 2020 and later targets, according to recent studies that will be the subject of Part 3.]