Environmental Matters

March 1, 2004

An inevitable consideration for energy customers evaluating onsite power-generation solutions is environmental emissions and related permitting requirements. The issue of how to treat distributed-generation (DG) technologies in terms of environmental permitting has become, in some states, the focus of intense debate, precipitating a much larger and wider-ranging discussion on setting and achieving environmental goals.

The purpose of this column is to provide an overview of the emissions characteristics of currently available onsite power-generation technologies and to explain how states in general approach the regulation of distributed-energy (DE) technologies on an environmental basis.


Gas-Fired Distributed Energy Resource Technology Characterizations, a report sponsored by the United States Department of Energy (DOE) Office of Energy Efficiency and Renewable Energy and released in October 2003 by the National Renewable Energy Laboratory in conjuction with the Gas Research Institute, catalogs major onsite power-generation systems with descriptions of applications, emissions, and cost and performance characteristics in both power-only and combined heat and power configurations. The report, available at http://www.nrel.gov/analysis/pdfs/2003/2003_gas-fired_der.pdf, contains a chapter for each of five major onsite-power system types – small steam turbines, small gas turbines, microturbines, reciprocating engines, and fuel cells – and a chapter on emerging Stirling engine-based DE systems. It provides, in addition to other key information, emissions characteristics for a set of representative systems within each technology type, focusing on those that are natural gas-fueled.

One of the chief authors, Bruce Hedman of Arlington, VA-based Energy and Environmental Analysis (EEA) Inc., notes that the report team collaborated with industry participants over a period of several years to provide both DOE and the energy community with a consistent and objective set of cost and performance data for DE resources and gas-fired technologies. “This report offers decision-makers at all levels a single-source, one-stop reference for comparative performance and costs of major onsite-power-system technology options,” says Hedman. Both current technology status and potential are addressed; along with current performance characteristics, the report contains future cost and performance estimates through 2030, providing a valuable glimpse at what benefits advanced-technology initiatives are expected to yield, and when.

The following selections from the report are related to the emissions performance of DE technologies:

Reciprocating Engines. Driven by economic and environmental pressures for power-density improvements (more output per unit of engine displacement), increased fuel efficiency, and reduced emissions, reciprocating-engine technology has improved dramatically over the past three decades. The emissions signature of natural-gas engines in particular has improved significantly in the last decade through better design and control of the combustion process and through the use of exhaust catalysts. Advanced lean-burn natural-gas engines produce untreated nitrogen oxide (NOx) levels as low as 50 ppmv (at 15% reference oxygen on a dry basis).

With current technology, the highest efficiency and the lowest NOx are not achieved simultaneously. Therefore many manufacturers of lean-burn gas engines offer different versions of an engine – a low-NOx version and a high-efficiency version – based on different tuning of the engine controls and ignition timing. Achieving highest-efficiency operation results in conditions that generally produce twice the NOx that low-NOx versions do, but achieving the lowest NOx typically entails sacrifice of one to two points in efficiency. In addition, carbon monoxide and volatile organic compound (VOC) emissions are higher in engines optimized for minimum NOx.

Table 1 shows typical emissions of NOx, carbon monoxide, VOCs, and carbon dioxide for each of five commercially available gas-engine systems, assuming no exhaust treatment. System 1, a 100-kW engine, is a high-speed, rich-burn engine. Use of a three-way catalyst system would reduce NOx emissions to 0.15 g/bhp-hr., carbon monoxide emissions to 0.6 g/bhp-hr., and VOC emissions to 0.15 g/bhp-hr. Systems 2-5 are lean-burn engines optimized for low emissions. Use of an oxidation catalyst could reduce carbon monoxide and VOC emissions from these engines by 98-99%.

Small Gas Turbines. Gas turbines provide one of the cleanest means of generating electricity, with NOx emissions from some large turbines in the single-digit parts-per-million range, either with catalytic exhaust cleanup or lean, premixed combustion (also known as dry, low-NOx, or DLN, combustion). Because of their relatively high efficiency and reliance on natural gas as the primary fuel, gas turbines emit substantially less carbon dioxide per kilowatt-hour generated than any other fossil technology in general commercial use.

Table 2 presents typical emissions for five turbine systems without exhaust control but using DLN technology. These systems represent technology commercially available in 2003 and levels guaranteed by manufacturers. Lower levels have been demonstrated with technology that has been technically proven but is not yet commercial and with technology that is technically feasible but neither technically proven nor commercially available. Add-on control options for NOx and carbon monoxide can further reduce emissions by 80-90% over the levels shown, although they might not be appropriate for smaller systems.

Microturbines. Microturbines can operate using a number of different fuels: natural gas, sour gas (i.e., gas with a high-sulfur, low-Btu content), and such liquid fuels as gasoline, kerosene, and diesel fuel/heating oil. Sophisticated combustion systems, relatively low turbine-inlet temperatures, and low (lean) fuel-to-air ratios result in NOx emissions of less than 10 ppm and inherently low-carbon monoxide and low-unburned hydrocarbon emissions, especially when running on natural gas. Most microturbines feature DLN combustion systems. Because microturbines are able to meet key emissions requirements with this or similar built-in technology, postcombustion emissions control techniques currently are not needed.

Table 3 presents typical emissions for a set of four representative systems first available commercially in 2003, reflecting manufacturers’ guaranteed emissions levels.

Small Steam Turbines. Boiler-/steam-turbine systems offer a wide range of fuel flexibility using a variety of fuel sources in the associated boiler or another heat source, including coal, oil, natural gas, wood, and waste products. Emissions depend on the fuel used by the boiler or another steam source, the boiler design, environmental conditions, and pollution-control technologies.

Table 4 illustrates typical emissions for boilers for three typical steam-turbine system electrical capacities by boiler fuel type.

Fuel Cells. Fuel cells, which produce electricity from hydrogen and oxygen, emit only water vapor. Very low levels of NOx emissions, however, are associated with the reforming of natural gas or other fuels to produce the fuel cell’s hydrogen supply and with the burning of a low-energy hydrogen exhaust stream used to heat the fuel processor. Most fuel cell technologies still are being developed, with only one type (the phosphoric acid fuel cell, or PAFC) commercially available in limited production. Emissions from the fuel-processing subsystem of a representative 200-kW PAFC system are estimated at <1.0-ppmv NOx, 2.0-ppmv carbon monoxide, 0.7-ppmv VOC, and 1,135 lb./MWh carbon dioxide.

Regulatory Requirements

Of course, the whole point of becoming familiar with DE technology emissions characteristics is to be able to anticipate and successfully address the regulatory requirements affecting your location. Unfortunately, as Joel Bluestein, president of EEA and noted DE and environmental expert points out, “Not only do requirements vary from state to state, but states in general are constantly reevaluating regulations affecting DG.” With support from DOE, EEA has constructed a very useful database that outlines basic air-permitting and emission control requirements for each state, which you can access by clicking on the DG regulations database tab at http://www.eea-inc.com.

EEA staff interviewed state permitting officials and reviewed state permitting regulation developments to construct the database, and the company updates entries as changes occur. The information framework used for each state divides the requirements into four categories typical of the structure of air regulations for small generators:

  • De minimus exemptions

  • State minor-source permitting

  • State major-source permitting

  • Emergency generators

“‘De minimus exemption’ refers to the fact that most states have a threshold below which units either are too small or emit a small enough amount that they do not have to apply for a permit of any kind,” explains Bluestein. “The requirements and conditions for these exemptions vary by state, but most states allow some kind of de minimus exemption. Sources that are not exempted must obtain a permit.

“Once it’s determined that the source in question is not exempted, an important factor in determining how it will be permitted is its potential to emit, which is the measure of a source’s maximum possible emissions if operated at full capacity for 8,760 hours per year.” If a source’s potential emissions exceed certain emissions thresholds, the source is called a major source and is subject to the federal New Source Review permitting process. The New Source Review’s trigger threshold depends on the air-quality status of the area where the unit is located. Sources that fall in between the de minimus and the major thresholds generally are subject to state minor-source permitting.

Finally Bluestein comments that both the minor-source permit and the major-source permit likely will require some kind of emissions limitation or control. These control requirements could be anything from raising the stack height of a unit to installing the most stringent control technologies available. The permitting process also can range from a simple application to a complex, cost-based technology evaluation. The requirements vary, depending on the state and the type of unit proposed. In addition, most states have special treatment for emergency backup generators. They typically adhere to an EPA recommendation that states calculate the potential to emit for emergency units based on 500 hr./yr. of operation.

If this whole system sounds complicated, it is – for DE developers, energy customers, and regulators. The latest trend in environmental regulations for DE is predetermined emission limits that allow manufacturers to precertify their equipment as being in compliance with those limits. Texas and California were the first to develop such regulations, but they are not consistent with each other, and there is concern that some of their standards cannot be achieved by available DE technologies.

The Regulatory Assistance Project has developed a national model rule for DE emission regulation that establishes a gradual phase-in of new standards with allowance for precertification and credit for combined heat and power configurations (see http://www.raponline.org). The hope is that many states will adopt this rule, creating a consistent, simple regulatory framework that will benefit developers, equipment manufacturers, and regulators. So far several states in the Northeast are considering adopting the model rule framework. This kind of standardization, along with interconnection standards and reasonable rates, could be a significant boost for the DE market.

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