Biomass, Renewables

Co-firing Biomass

Issue 11 and Volume 113.

Concern about global warming has altered the landscape for fossil-fuel combustion.

By Trotter Hunt, Hunt, Guillot & Associates LLC, and David Tennant, International Applied Engineering Inc.

Utilities are taking a second look at biomass as a fuel source in power generation. There are many forms of biomass that can be used such as saw grass and agricultural wastes (peanut hulls, bagasse, pecan shells, switchgrass and others) but the most common biomass that can be found in plentiful supply year round is waste wood, on which this article will focus.

A circular stacker reclaimer. This is a method for fully automated storage and reclaiming biomass materials. Photo, Guillot & Associates.
Click here to enlarge image

In the past, woody biomass could not compete with less expensive options, primarily coal. Coal is a plentiful resource in the U.S. and its use in combustion technologies has been perfected over many decades. Although wood is a plentiful resource too, it contains less energy (about one-third that of coal by wet weight) and has a high moisture content. And unlike coal, which is concentrated and extracted from one location, wood is distributed over a large area, so gathering and transportation costs can be high.

The size of a large wood plant is about one-tenth that of a modern large coal-fired unit. For example, large coal-fired plants can consist of four 600 to 800 MW units, while a large wood-fired power plant is typically 40 to 50 MW for a single unit. The amount of waste wood fuel required to supply even a single utility-scale 100 MW boiler unit would be significant. Sufficient waste wood sources may not be available within a 50-mile radius of the plant.

For these reasons, waste wood has generally been discounted as a serious fuel source for conventional electric power generation. In economic terms, it simply has not been competitive. Today, however, concern about global warming has altered the landscape for fossil-fuel combustion. Legislation being proposed could require electric utilities to generate up to 20 percent of their power with renewables. For a large utility with 10,000 MW of generation, 2,000 MW would have to be generated from renewable sources, a tall order for even the best-run utilities.

At the same time, generous grants and tax credits are available as an incentive to move toward biomass power. Against this backdrop, many utilities and independent power producers (IPPs) are looking at biomass in a new light.

Biomass Co-firing Advantages

Co-firing biomass blended with coal offers several advantages to utilities. First, utilities are able to use existing, large-scale assets that provide baseload power. For example, co-firing biomass to achieve 50 MW of renewable power at an 800 MW facility will result in a minimal unit de-rate and continued operation of a large-scale asset that can provide baseload power.

A second advantage is an improved emissions profile, a major consideration if the plant site is in an ozone non-attainment area. One hundred percent wood firing has much lower nitrogen oxides (NOX) and sulfur oxides (SOX) emissions than coal but elevated levels of carbon moNOXide (CO) and volatile organic compounds (VOCs). However, by co-firing biomass and coal the overall emissions profile improves.

Finally, co-firing biomass offers flexibility to utilities. As renewable energy requirements increase, the percent of biomass co-firing can also be increased—up to a point.

Co-firing Challenges

Introducing biomass co-firing to an existing coal-fired facility is not as straightforward as many think. A number of challenges exist with co-firing biomass and coal as a blended mixture:

  • Double fuel storage, handling and processing equipment
  • Slight plant output de-rating
  • Logistics of introducing waste wood into a coal-fired boiler
  • Operational considerations
  • Air emissions and permitting

Our experience has been that woody biomass in chip form does not work well with coal pulverizers. The wood has high moisture content and tends to clump together. This creates problems when passing through a pulverizer that is designed for coal. Mixing wood chips onto the coal pile will not work.

Conveying biomass to the boiler. Coal and biomass materials must be conveyed separately. Photo, Guillot & Associates.
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A more effective method to introduce biomass is to inject it directly into the boiler. Biomass can be blown in with a separate feed system or, more practically, introduced into the primary air pipe downstream of the coal pulverizer. The primary air serves to pre-heat the wood and blow it into the boiler premixed with coal. Using this method, a realistic goal for a mix of 10 percent to 20 percent waste wood to 90 percent to 80 percent coal by heat input can be effective. Waste wood particle size for this purpose will need to be 1/8 inch or less.

As mentioned above, co-firing will improve the air emissions profile of a coal plant. However, if the goal is to increase the use of renewable energy sources on a small scale (10 percent to 20 percent biomass), this method will improve air emissions to a limited degree. Many utilities are considering a full conversion of selected older, smaller capacity boilers from coal to waste wood to reach regulatory goals of 20 percent renewable energy use and avoid some of the challenges associated with blended co-firing.

Complete Conversion

It may not be practical to convert all of a plant’s units from coal to waste wood. The amount of waste wood fuel needed to feed a plant with four 100 MW units would pose a significant challenge to fuel procurement requirements. Also, because waste wood produces more gas per unit of heat produced, a unit de-rate of about 30 percent is typical. Therefore, switching a 100 MW unit to wood will mean roughly 70 MW of power output under the same gas flow conditions. Assuming that each unit is 70 MW, then enough wood must be fed to generate power from each of four units to get a total output of 280 MW. A plant this size will require approximately 3 million tons of wet waste wood a year.

Obtaining 3 million tons a year of waste wood fuel is most likely not economically practical for many sites, so some utilities are evaluating converting one or two units per site. This makes the wood supply logistics and economics more manageable. However, such a strategy now means there would be two fuel trains for a four-unit plant: one to supply waste wood to two units, the other to provide coal to two units.

The technology and equipment for producing energy from waste wood is mature and experience has shown that the most critical system with the most downtime is the fuel delivery system. Therefore, the wood conveying system must have a robust design and selective redundancy and surge capacity to minimize downtime.

Boiler Technologies

For wood-firing power generation two primary boiler technologies exist: stoker-grates and bubbling fluidized bed (BFB). Both are well-established and have their pros and cons.

Stoker-grates can be easier to operate and can generally meet air emission requirements. The stoker units will often be less expensive. BFBs, on the other hand, can burn higher moisture fuels and will be able to meet more stringent air emissions requirements in non-attainment areas. The drawbacks are cost and a higher parasitic load due to higher pressure air flows for the fluidized bed. It may also be necessary to change the forced draft (FD) fans on some units.

A common solution for converting existing boilers from coal fuel to waste wood fuel is to remove the bottom and replace it with a stoker or BFB. In rare cases, the entire boiler may need to be replaced. Age and the condition of the boiler tubes will be factors to consider.

Changing the Emissions Profile

Due to the fact that waste wood is releasing carbon that was absorbed from the atmosphere when the tree was grown, waste biomass fuels are considered CO2 neutral. NOX and SO2 will generally see significant reductions but CO and VOCs will increase; VOCs in wood are from terpenes that occur naturally from the combustion.

Many older power plants were permitted under the rules in effect and technology advances available at the time of their design and construction. Therefore, changing the emissions profile through a fuel conversion will require a new air emissions permitting application based on today’s rules and technology.

All utility coal plants have electrostatic precipitators (ESPs) and in some cases, scrubbers. For the most part, either an ESP or a scrubber will remove enough particulate matter to meet air emissions requirements. However, depending on the type and efficiency of the emission control technologies (and depending on whether a BFB or stoker is to be used) Best Available Control Technology (BACT) or Lowest Achievable Emissions Rate (LAER) scenarios may apply. This is a concern primarily within non-attainment areas, which are usually near large metropolitan areas. BACT allows the power plant operator to consider the economic costs of conversion. LAER does not allow economics to enter into consideration; LAER technology may have to be implemented regardless of the cost if the conversion to biomass fuel is pursued.

A change in the emissions profile is one reason why each plant conversion must be considered on a case-by-case basis. Simply converting to a more “environmentally friendly” fuel does not guarantee breezing through the permitting process. Boiler technology, plant location, expected emissions and type of emissions controls are all factors in the plant evaluation process. The emissions requirements can significantly drive up the cost of converting to waste biomass fuel. Consequently, not all plants will be suitable candidates for conversion.

Fuel Availability and Quality

The challenges of fuel availability and quality are significant and deserve careful attention. A prudent starting point for any biomass co-firing or conversion study is to evaluate the available “fuel basket” to give the utility an idea of what type and volume of waste biomass material is available in the area, the expected market price and the number of potential suppliers with which to negotiate.

Logistical costs associated with bringing in woody biomass from far-flung locations can make project economics difficult, to say the least. Further, the challenge of having to negotiate with many small fuel providers rather than one large coal-mining firm is new to most utilities.

Unlike coal, natural gas and other fossil fuels, woody biomass quality is not clearly standardized. Quality must be proactively managed and the ability to tolerate variation must be incorporated into other aspects of the plant design. At the outset, a clear fuel specification must be established. Fuel pre-processing is designed around this fuel specification, but rigorous sampling methods must also be devised to prevent suppliers from submitting contaminated and otherwise out-of-spec fuel loads into the system. Additionally, raw woody biomass is not hydrophobic. When it rains, the top layer of the fuel pile will become saturated and can cause a minor decrease in power output from the facility.

Some utilities are considering wood pellets, torrefied briquettes or other engineered fuels that will have more uniform fuel characteristics. The benefits of these fuels, however, must be measured against the costs. Aggregating, processing and transporting them can be expensive. Torrefied pellets could be interchangeable with coal and use the same storage, conveying and pulverizing equipment, but full-scale commercialization has not yet been realized.

Each site is unique and will require a full engineering analysis to balance the environmental and economic conditions. In the long run, biomass can reduce emissions when compared to traditional fossil fuels and is an excellent choice for meeting the new and pending renewable energy requirements.

Authors: Trotter Hunt, P.E., is marketing manager at Hunt, Guillot & Associates LLC. He has more than nine years of experience in project management, marketing and consulting in a variety of industries. David Tennant, P.E., PMP, is a principal at International Applied Engineering Inc. He has more than 25 years of experience in the energy generation field with a successful track record in engineering, operations, marketing, management and consulting.

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