Biomass, Renewables

Biomass: An Emerging Fuel for Power Generation

Issue 11 and Volume 113.

By Lee Clair and Pete Fordham, Norbridge Inc.

The use of renewable fuels for power generation is set to increase dramatically in the U.S. primarily due to current and proposed government policies and requirements. Yet for all the publicity that wind and solar power receive, biomass is most likely to be the biggest beneficiary of the renewables movement. However, biomass has only a limited history as a fuel for large-scale power generation, which presents a number of issues and challenges for utilities looking to convert to or develop biomass-fired units.

Renewable fuels in general, and biomass in particular, are “the tail on the power generation dog.” Renewable fuels are dominated by hydro and collectively accounted for only 9.5 percent of total power generated in the U.S. As such they are dwarfed by coal, nuclear and natural gas. Biomass fuel (including municipal solid waste) accounted for only 1.4 percent of total U.S. power generation in 2008 (see Fig. 1) and about 15 percent of overall renewable power generation. Additionally, much of the biomass power generated today comes from cogeneration at facilities for pulp and paper and other industries, not utilities.

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Future Renewables Growth

While the role of non-hydroelectric renewables in the U.S. power generation portfolio is small, the landscape for renewables is likely to change dramatically over the next decade. As of last summer, 34 states had enacted renewable energy portfolio standards (RPS) that set requirements for the use of renewable fuels. While differences exist between states, RPS typically set minimum percentages for renewable power generation or usage over a defined time frame. Examples include Minnesota, which requires that 25 percent of power generation come from renewables by 2025, and Colorado, which requires 20 percent of power generation from renewables by 2020 for large investor-owned utilities.

At the same time, the federal government is considering a national Renewable Electricity Standard (RES) through the proposed cap-and-trade bill, or the American Clean Energy and Security Act (ACES) of 2009. The cap-and-trade bill could require 20 percent renewables by 2020, of which 25 percent to 40 percent may come from energy efficiency.

Based in part on the state-level renewable requirements in place as of March 2009, the Department of Energy’s Energy Information Administration (EIA) estimates that renewables will grow from 9.5 percent of total U.S. electric generation in 2008 to 13.4 percent by 2020. If the ACES Act were to pass, renewables could constitute as much as 15 percent of total generation by 2020, much of which may have to come from biomass.

The Only Game in Town?

The renewable energy standards are a critical driver of the potential for biomass fuel growth. On a purely economic basis, biomass fuel costs are typically not favorable against lower cost coal and natural gas. Wood pellets, with a Btu content similar to Powder River Basin coal, can cost $100 to $200/ton.

With the support of renewables standards, biomass is set to be a major component of renewable energy growth. Based in part on the state-level RPS in place as of March 2009, the EIA estimates that biomass generation (including municipal solid waste) will grow from 1.4 percent of total U.S. generation in 2008 to 4.1 percent in 2020, or from 60 million MWh to 188 million MWh, led by wood and other biomass. Over the same period of time, hydro, wind and solar are expected to grow only marginally (see Fig. 2). If the federal RES is mandated, additional biomass generation could be required by 2020.

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Biomass is projected to be an engine of renewable growth for two main reasons. First, biomass generation can be developed almost anywhere. Other renewables can be much more location-specific. Hydro power has already been developed in most areas where it is feasible. Both solar and wind power are location-specific as well. Many heavily populated areas are not good candidates for solar or wind farms due to weather conditions and NIMBY (not in my backyard) concerns of residents. Second, biomass power can be produced on demand. Most other renewables are susceptible to the weather or seasonal changes. Biomass—like coal, natural gas and nuclear power generation—can be run around the clock throughout the year.

U.S. utilities are taking notice of both the changing regulatory environment and the benefits and drawbacks of various types of renewable energy. Norbridge conducted a study this past May to assess the interest level in biomass generation and to identify some of the issues pertaining to conversion to biomass. The study included interviews with 16 utilities and power generators and 17 state agencies.

One quarter of the utilities interviewed stated that their interest in an increased role for biomass fuel was a “10” on a scale of 1 to 10 (with 10 indicating the highest level of interest). Across all 16 utilities, the median response was 7.5 out of 10. This high level of interest was driven by renewable energy standards, as well as many utilities’ limited ability to increase use of hydro, wind and solar power.

Based on our study interviews, state agencies are also bullish on biomass. Twelve of the 17 states that participated in the study indicated their interest in biomass was 7 to 10 on the same 10-point scale. In support of biomass efforts, 11 states indicated they had state subsidies, tax credits or other assistance in place to support the growth of biomass-fired electricity generation.

Biomass Conversion Challenges

Shifting power generating capacity to biomass will not be easy, however. Biomass as a fuel source for large-scale power generation is in its infancy in the U.S. The suppliers and the supply chain have not yet been developed on the scale necessary to supply the significant increase in biomass necessary to meet U.S. power needs. Unlike the coal supply chain that has been in place for many years, it is not clear at this point how the biomass supply chain will develop, or how it should develop. This is made even more complex as numerous utilities begin to look at biomass options.

Key questions for a utility considering a conversion to biomass are likely to include the following:

  • Boiler: Type of boiler to use or boiler conversion options.
  • Type of biomass: Wood vs. agricultural products, raw vs. pelletized, purpose grown vs. byproduct/residual; specifications (Btu content, moisture content, size, emissions and so on).
  • Sourcing: Biomass origins, suppliers, producer facility sizes, pellet plant locations (if applicable).
  • Transportation: Modal options, equipment requirements, unloading infrastructure, delivery quantities.
  • Storage/Handling: Type of fuel storage (indoor for non-torrefied biomass pellets), conveying infrastructure, dust control systems, fire suppression systems.

Each involves a variety of options and trade-offs that must be considered when developing a biomass supply chain. In addition, each may include significant capital requirements. For example, boiler modifications, transportation equipment, unloading infrastructure, storage facilities and other potential requirements could add up to a significant expense depending on the needs of a specific utility or generating facility.

Boiler: Boiler capabilities and requirements are critical to the success of any biomass-fired power plant. It goes without saying that the fuel supplied to the boiler must be a fuel the boiler is capable of burning. While a new biomass power plant can be designed from the start to burn a certain type of biomass, a plant converted from coal to biomass will likely have greater biomass fuel limitations. When blending coal and biomass fuel for a boiler, it is likely that only certain types of biomass, such as biomass pellets, would be viable.

The type of combustion system could have a major impact on steam rate and efficiency. Stoker and fluidized bed boilers each have different advantages when it comes to burning biomass. Stokers have a longer operating history and can be good for moisture and size flexibility. Fluidized bed boilers have better emissions and efficiency, but more limited operating history.

Several additional factors will determine the compatibility of biomass with boilers. For example, fuel characteristics such as moisture, ash and alkaline content, among others, will impact performance. Different fuel mixes could also cause scaling and slagging at different rates. There may be new or additional permitting and/or environmental requirements that also must be addressed.

Type of Fuel: Biomass fuel can come in many flavors. The right choice for a particular power plant will depend on biomass availability and cost and fit with boiler and environmental requirements. Wood-based and agriculturally-based biomass are both potential fuel sources. However, there are major regional differences in the local availability of potential biomass resources. For a power plant in the Southeastern U.S., a wood-based fuel may be preferred due to the abundance of softwoods in the region. In parts of the Midwest that are agricultural “breadbaskets,” an agricultural product solution may be a better option.

Biomass can be purpose-grown as fuel or can be the byproduct of or residual from another process (see Fig. 3). The advantage of purpose-grown biomass is the stability of supply of biomass fiber and increased efficiency in harvesting the biomass. The disadvantage of purpose-grown biomass is that it can compete with other uses for that product. For example, using some types of roundwood as a fuel source would take that supply “out of circulation” for the lumber and pulp/paper industries. Using residual biomass is typically less expensive and competes less directly with the primary use for that biomass. This is especially important for food crops. However, residual biomass (such as corn stover and tree branches) are not always harvested with the primary material, making collection difficult.

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Biomass fuel can also be “raw” or processed. Processing can include pelletization and processes such as torrefaction. The process of pelletizing the fuel typically increases the Btu content by removing moisture from the biomass. It also standardizes the size and shape of the fuel. However, pelletizing the biomass is typically energy intensive and requires the capital cost of the pellet plant and drying and pelletizing equipment, adding cost to the biomass. Torrefaction is the process of adding chemicals to the biomass, typically to make it more durable and to increase its Btu content. While torrefaction may offer an improved solution, it is only being performed on a limited scale today.

Sourcing: While biomass is burned for power in the U.S. and Canada, it is done so on a relatively small scale. For a utility looking to convert or develop significant generating capacity, it is not at all clear from where the biomass would be sourced or who would provide it. There may be some sources near a power plant, but they may be unable to provide the quantity of biomass required to supply a 100 MW plant or larger. A utility may need to find a number of suppliers in different geographic areas to obtain the quantity of fuel necessary.

In most cases, these suppliers do not yet exist. While some may be active in the agricultural or wood products industries, they are not active in the biomass fuels business. In many cases, the suppliers are startups with limited operating history. The current credit crisis is inhibiting the ability of some of these new companies to obtain financing.

The way in which the biomass supply industry develops will have a major impact on utilities and the delivered cost of biomass fuel. For example, pellet plant size and location could be good for one utility but bad for another. Pellet plants can be large, producing up to 500,000 tons/year, although there are more plants in the range of 50,000 to 125,000 tons. A key determinant of pellet plant size is how far from the plant the raw biomass will be harvested to produce the volume of pellets. Since raw biomass can have a moisture content approximating 50 percent, the inbound transportation costs to the pellet plant can become significant as distances increase. This will also influence whether pellet plants are located near utilities or near the raw biomass supply. Since the industry is still relatively undeveloped, there may be opportunities for utilities to shape the supply chain before it is fully established.

This uncertainty about supply and suppliers is magnified by the long-term investments that utilities will need to make to develop or convert to biomass-fueled generation.

Transportation: Most utilities receive their coal by unit train or by barge, in either case in large quantities. Biomass fuel is much more likely to arrive in smaller quantities from a larger number of suppliers. This will require greater coordination and management at the power plant to efficiently receive the biomass fuel. Railcar blocks will likely be smaller and arrive more frequently. River terminals will have to serve as consolidation points from multiple biomass suppliers where the biomass would be loaded on barges and delivered to the utility. Modal options are likely to change as well. Trucks could play a more significant role in biomass fuel transportation than they do with coal, as utilities may tap local biomass sources first and then reach further out.

Biomass will also require different equipment and unloading infrastructure than most utilities currently use for their coal. Traditional wood pellets, for example, must remain dry, requiring covered equipment. Railcars will have to be covered hoppers instead of open top gondolas or hoppers. They will be bottom dump with gates instead of doors. Trucks will have to be covered dump trucks. Barges would have to be covered as well. Unloading infrastructure will have to be covered and may need to be available for receiving by multiple modes.

Since the cost of biomass can be much higher than that of coal, transportation costs will likely be a lower percentage of total delivered cost than with coal. In certain cases it may be worth sourcing lower-cost biomass further from the plant, with the biomass cost-savings exceeding the additional transportation cost. A large number of potential sourcing and transportation option combinations will have to be assessed.

Storage/Handling: Many types of biomass, such as wood pellets, will require inside storage. Storage quantities can be high, requiring multiple large silos or flat warehousing. A 100 MW plant could burn an estimated 400,000 tons of biomass pellets annually. If storage capacity were to be required for a three-months supply, or 100,000 tons, a warehouse 180 feet wide by 1,200 feet long could be required as storage. Alternatively, 10, 10,000-ton silos would be required. If a generating station had units burning both biomass and coal, then storage space and infrastructure for both fuels would be required.

Other handling equipment, such as conveyors and stacker/reclaimers, may have to be modified or replaced with equipment better-suited to the type of biomass fuel selected.

Storage and handling infrastructure also must take into account biomass’ high combustibility. This is true for both pelletized and raw biomass. Wood pellets are not as durable as coal and produce more combustible dust. Dust control systems, temperature sensors and fire suppression systems may be required to support safe operations. In the design of storage and handling, the distances that pellets are dropped either into storage or through the conveying process should be managed to limit pellet damage and dust creation.

As utilities look to biomass to meet RPS requirements, it will be necessary for them to understand the issues associated with the conversion and how biomass differs from coal. In addition to boiler-specific issues, identifying and developing viable biomass types, sources and transportation/logistics will be critical to many utilities’ long-term renewable-fuel success.

Authors: Lee Clair is a partner and Pete Fordham is a principal with Norbridge Inc.

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