Biomass Looking To Build Steam in Power Market

Issue 1 and Volume 106.

By: Brian K. Schimmoller,
Managing Editor

Biomass and bioenergy resources such as agricultural products, forest and paper products, and waste-derived fuels satisfy 3-4 percent of U.S. energy needs. Included in this total are more than 500 biomass-fired power plants with a combined capacity of 7,000 MW and numerous other cogeneration facilities. U.S. consumption of bioenergy products has been increasing about 2 percent per year since 1990, and the Freedonia Group expects demand for biomass energy and raw materials to reach $2.8 billion in 2005, an annual gain of 8.5 percent. Electric power generation will remain the dominant end use for biomass, with demand rising from about 24 billion kWh in 2000 to more than 40 billion kWh by 2010.

Biomass-based energy production can provide various economic, environmental and technical benefits. Converting these benefits into commercial reality, however, is not necessarily easy. Sim Weeks, Director of Business Development with Future Energy Resources Corp. (FERCO), identifies at least four barriers to wider commercialization in the U.S.: (1) current low prices for natural gas, coal and power; (2) little economic benefit for commercializing more efficient “green” technologies; (3) lack of industry familiarity with the technology options; and (4) restrictions on the production tax credit so that only closed-loop biomass projects using dedicated, plantation crops are eligible. Still, environmental and efficiency pressures, and the search for low-cost fuels, will likely support increased use of biomass for power production and thermal energy applications.

In the near term, biomass-fired or co-fired power plants or cogeneration facilities will be fueled predominantly by waste biomass resources. Long-term, dedicated farm-grown biomass crops hold significant promise as a potentially large resource – giving biomass a way to be 10 percent or more of U.S. electricity supply rather than the 1.5 percent of today or the 3-5 percent role allowed by using wood wastes and other readily-collected residues. “With super high-yield crops, biomass could have a 10 percent, even 20-25 percent role in future electricity supply,” says Evan Hughes, EPRI Manager of Biomass Energy. “Such closed-loop, farm-grown biomass is both the hope and the challenge for biomass energy.” The challenge is much higher yields and lower costs, especially harvesting costs. While dedicated biomass crops offer a promising pathway toward carbon mitigation, the associated technical and economic constraints mean that the first steps on that pathway will likely focus on wastes and residues as the biomass fuel source. Fossil-derived expertise and fossil power plant assets provide an excellent starting point from which to launch a new round of growth in biomass power generation – growth from today’s 7,000 MW and 45 TWh of generation each year to something like 2 to 3 times as much within about a 10-year period. “I believe there are going to be more biomass plants coming on-line in the next several years,” says Anders Rydaker, President of District Energy St. Paul, “but with electricity prices where they are today, and where they’re projected to be, I don’t think dedicated biomass crops are going to be a major part of the mix. Waste biomass facilities are much more attractive.”


The growing worldwide interest in gasification due to its fuel flexibility, environmental performance, and high efficiency has logically led to interest in biomass gasification. For the most part, these efforts have been offshoots of broader gasification technology efforts aimed at coal and petcoke gasification. Because of its unique properties – high reactivity, low ash, low sulfur and high volatile matter content – biomass is a different animal, however, and requires a different approach to optimize performance.

The McNeil Generation Station in Burlington, Vermont is hosting a commercial-scale demonstration of FERCO’s SilvaGas biomass gasification process. Photo courtesy of FERCO.
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Building on R&D efforts begun in the 1980s by Battelle and the U.S. Department of Energy, FERCO is pursuing commercialization of a unique biomass gasification process called SilvaGas. FERCO has accumulated more than 20,000 operation hours in a 10-ton per day process research unit and, since August 2000, has been testing a commercial-scale demonstration unit (200-ton per day) at the 50 MW wood-fired McNeil Generating Station in Burlington, Vermont.

The SilvaGas process converts biomass into a medium-Btu gas (450-500 Btu/scf) that can directly displace natural gas as a fuel for power production, steam production, heating, etc. Two circulating fluidized bed reactors function as the primary process vessels, one as the gasifier and one as the combustor. Sand at 1,800 F circulates between the two vessels, thermally breaking down the highly reactive biomass and conveying char from the gasification reactor to the process combustor. Since the sand provides the energy to gasify the biomass, the process can operate near atmospheric pressure without the need for pure oxygen, thereby eliminating the need for an oxygen separation plant, as is common in coal and conventional biomass gasification facilities.

The SilvaGas demonstration at McNeil has completed several extended test campaigns in the past year. Gas quality has been extremely consistent and reproducible, firing a range of fuels (woody biomass, herbaceous crops, hybrid willow, reconstituted wood pellets, whole-tree chips) with widely different compositions and moisture contents (10-50 percent). Operational results have been excellent, according to Mark Paisley, FERCO Vice President of Technology, with demonstrated turndowns of 1.75:1, recovery from a process upset in less than 30 minutes, and cold startup times reduced from 24 hours to 6-8 hours.

While gas cleanup is by no means simple, the absence of sulfur in the biomass feedstocks eliminates one of the main issues faced by coal gasifiers, says Paisley. Removing particulate matter and condensibles are the main concerns in the SilvaGas process. Particulate matter can be removed to levels less than 5 ppm using a conventional, off-the-shelf wet scrubbing process. Condensible hydrocarbon removal is a little more difficult, but can be accomplished with a cracking operation similar to those used in the petroleum industry.

Extremely low contaminant levels are particularly important for applications where the SilvaGas will be used to fire gas turbines, since the internals of gas turbines are more easily damaged by solid contaminants. FERCO had originally planned an additional testing phase at McNeil, where the product gas would be fed to a gas turbine for direct electricity generation and heat recovery, but it’s not certain these tests will be needed. “Several of the turbine manufacturers we’ve spoken to have said they are prepared to offer commercial guarantees on their engines firing SilvaGas, based on the results they’ve seen to date,” says FERCO’s Paisley.

FERCO is pursuing several commercial project opportunities for the SilvaGas process. Most are in the same size range as at McNeil, and one potential customer class FERCO is targeting are existing industrial facilities where permits are in place and where waste biomass is available either on-site or nearby. SilvaGas production costs are competitive with natural gas prices – at the burner tip – because the transportation costs associated with natural gas distribution are completely avoided. SilvaGas end users would also benefit from much lower volatility in their fuel expenditure levels.

Biomass CHP

District Energy St. Paul (DESP) provides heating (since 1983) and cooling (since 1993) services to more than 150 buildings and almost 300 single-family residences in downtown St. Paul, Minn. In the early 1990s, several factors persuaded the non-profit company that owns and operates the existing district heating and cooling plant to pursue development of a new biomass combined heat and power (CHP) plant. First, the state required the local utility, Northern States Power Co., now Xcel Energy, to obtain a certain percentage of its electricity from renewable resources. Second, DESP desired to reduce the environmental impact caused by its use of coal; a biomass plant would reduce coal usage by up to 80 percent and eliminate 280,000 tons per year of CO2 emissions. Third, St. Paul and its surroundings had ample local biomass supplies to feed the plant. The metro area produces more than 600,000 tons of wood waste per year.

A DESP affiliate, Market Street Energy Company, has teamed with Trigen-Cinergy Solutions to develop the $55 million facility, which is under construction and will come on-line in December 2002. The project team evaluated various technologies, including gasification and fluidized bed combustion, but ultimately shied away from these options, says DESP President Anders Rydaker, because of concerns about safety in a downtown setting and concerns about economics and financing. The team selected a 310,000 lb/hr vibrating grate boiler from Foster Wheeler, large enough to replace the heat output from one-and-a-half of the existing 150,000 lb/hr traveling grate boilers (which will remain available as needed after the biomass facility comes on-line). The vibrating grate technology was chosen rather than fluidized bed technology because of better overall economics, including lower operating and maintenance costs, and greater flexibility in controlling combustion air distribution.

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The boiler will feed steam at 1,280 psi and 950 F to a 37.4 MW steam turbine-generator, with a net output of 33 MW. The plant will produce hot water, at 190-250 F depending on the outdoor temperature, for distribution to downtown St. Paul customers, replacing about 80 percent of the thermal energy output provided by the existing facility, and will also produce 25 MW of electricity in the winter to be sold to Xcel Energy. In the summer, the plant could produce up to 33 MW of electricity due to lower heating demands. Under the terms of Xcel’s mandated renewable energy supply program, the CHP project will receive a price higher than market price for the electricity it provides.

Great care was taken in the selection of a plant design so that all community stakeholders would benefit. The downtown location prompted the use of architecturally pleasing elements that will enable the plant to fit into its surroundings. Due to its urban setting, the plant will only have a 16-hour storage silo on-site, which means that biomass fuel will be trucked in every day. Three trucks per hour will deliver wood waste to a covered, below-grade receiving hopper to control dust. The material will then be raised to the top of the enclosed storage silos and transferred to the boiler via a belt conveyor. The available fuel consists of about one-third tree trimmings, one-third industrial wood waste and one-third demolition and construction waste. Only non-treated wood will be accepted, and preprocessing will be handled off-site.

Fuel handling is the only significant concern with the operation of the plant. “The boiler is designed to accommodate fuels with moisture contents up to 50 percent,” says Rydaker. “In our proposed fuel supply contracts, to reduce the chance of any problems, we have included wording to encourage moisture levels between 25 and 40 percent.”

This Old Biomass

A number of biomass power plants built in the past few decades to capitalize on favorable rates available through PURPA provisions have been shut down in recent years as their power purchase contracts lapsed or were bought out. In light of rising demand for electricity, however, many are being restored to supply incremental power to the grid. Energy Products of Idaho (EPI) has refurbished and recommissioned one such facility, the Madera power plant near Fresno, Calif., to provide needed electricity to the California grid.

The original biomass facility, commissioned in 1988, was shut down and mothballed in early 1995 when PG&E bought back its power purchase agreement. In response to the California energy crisis in 2000, Madera Power LLC, a wholly owned subsidiary of EPI, purchased the facility and embarked on a retrofit project to return the unit to service. The retrofit consisted primarily of renovations to existing equipment, but also included some new additions to enhance cost-effective operation.

Energy Products of Idaho purchased and refurbished the idle Madera biomass plant near Fresno, Calif. to add needed generation capacity to the California grid. Photo courtesy of Energy Products of Idaho.
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The heart of the plant is EPI’s patented atmospheric fluidized bed boiler, where biomass fuel feedstocks from the San Joaquin Valley and as far away as San Francisco and Los Angeles are combusted. Heat is recovered in a forced-circulation boiler, and steam is fed to a steam turbine, which drives a 28.5 MW generator. The facility converts renewable biomass into electricity for California consumers. Fuel is supplied to the plant already ground to size, minus three inches, and no drying is required.

“During the renovation, special consideration was given to reliability and high equipment availability,” says Joe Eisele, EPI Director of Business Development. “The turbine island was completely disassembled, cleaned, and overhauled. All electrical subsystems, switchgear and relays were tested, overhauled as necessary and re-certified.” To maximize operational readiness, the bed cleaning system received remanufactured valves, a vibrating conveyor and bucket elevator overhaul. Boiler tube surface area was restored and additional surface area was added to the superheater; all sootblowers were overhauled; the baghouse received new bags, new actuator cylinders and solenoids; and the ash handling system was renovated, modified and the capacity improved. Madera decided to replace the existing boiler feedwater treatment equipment with a packaged demineralizer and reverse osmosis unit from USFilter, minimizing operator involvement and eliminating concerns about waste discharge.

Madera invested in a number of other plant upgrades to improve the facility’s economic viability, according to Eisele:

  • New telemetry systems and revenue meters
  • New operator interface control stations, upgraded to work in a Windows NT environment
  • A new engineering interface work station
  • New UPS batteries with higher capacity
  • New hardware and software for CEMS and data acquisition
  • A new ash surge bin to collect ash from the primary superheater hoppers, which represents a change from mechanical to pneumatic collection and conveyance
  • Two new instrument air compressors
  • A new ash system blower package
  • A new ash system bin vent filter
  • A new fuel truck tipper/unloader
  • General upgrades to field instrumentation and transmitters.

As an example of how these improvements enhanced the plant’s economic viability, Madera upgraded field transmitters to current-generation “smart models” that improve accuracy from 2 percent to 0.15 percent and reduce maintenance requirements and expense. Further, because dedicated land lines can be problematic and expensive, Madera opted to send ISO control telemetry data via satellite. This provides monthly savings (four times less than land transmittal), and the satellite connection can be used with commercial software to view real-time process conditions remotely. Engineers at EPI’s Idaho offices can readily assist with troubleshooting, diagnostics and system modifications, making site visits a rare occurrence.

The Madera plant operates 24×7 except for planned maintenance outages and forced shutdowns. Total cost of the purchase and renovation was $650/kW, which is about one-third the cost of a new facility, according to Eisele. EPI retained the existing air permit from Madera, but RATA (relative accuracy test audit) testing and CEMS certification was required prior to commercial operation. From hot shutdown, about two hours is required to bring the unit to full production, depending on the temperature of the combustor; from cold shutdown, 10-12 hours is required to reach full output. Plant heat rate has averaged about 18,000 Btu/kWh since coming back on-line.