Recent increases in nitrogen oxide (NOx) emissions from coal-fired electric generating units equipped with selective catalytic reduction

The most effective control technology available for the reduction of oxides of nitrogen (NO_x) from coal-fired boilers is selective catalytic reduction (SCR). Installation of SCR on coal-fired electric generating units (EGUs) has grown substantially since the onset of the U.S. Environmental Protection Agency’s (EPA) first cap and trade program for oxides of nitrogen in 1999, the Ozone Transport Commission (OTC) NO_x Budget Program. Installations have increased from 6 units present in 1998 in the states that encompass the current Cross-State Air Pollution Rule (CSAPR) ozone season program to 250 in 2014. In recent years, however, the degree of usage of installed SCR technology has been dropping significantly at individual plants. Average seasonal NO_x emission rates increased substantially during the Clean Air Interstate Rule (CAIR) program. These increases coincided with a collapse in the cost of CAIR allowances, which declined to less than the cost of the reagent required to operate installed SCR equipment, and was accompanied by a 77% decline in delivered natural gas prices from their peak in June of 2008 to April 2012, which in turn coincided with a 390% increase in shale gas production between 2008 and 2012. These years also witnessed a decline in national electric generation which, after peaking in 2007, declined through 2013 at an annualized rate of ?0.3%. Scaling back the use of installed SCR on coal-fired plants has resulted in the release of over 290,000 tons of avoidable NO_x during the past five ozone seasons in the states that participated in the CAIR program.

Implications: To function as designed, a cap and trade program must maintain allowance costs that function as a disincentive for the release of the air pollutants that the program seeks to control. If the principle incentive for reducing NO_x emissions is the avoidance of allowance costs, emissions may be expected to increase if costs fall below a critical value, in the absence of additional state or federal limitations. As such, external factors as the cost of competing fuels and a low or negative growth of electric sales may also disincentivize the use of control technologies, the continuation of desirable emission rates will be best maintained by the implementation of performance standards that supplement and complement the emissions trading program.     

Retrofit NO x Control Options

Modifications to the combustion process have been the basis for NO_x control on new coal-fired power plants to meet federal New Source Performance Standards (NSPS) Promulgated in 1971 and revised in 1978. In the event that retrofit NO_x control is required on pre-NSPS plants, low-NO_x combustion will likely be the least cost approach, if such controls can be successfully applied to the wide diversity of these older utility boiler designs now in operation. A series of retrofit low-NOx combustion demonstrations supported by EPRI and electric utility companies are intended to establish the technical and economic feasibility of this approach.     

A Feasibility Study on the Predictive Emission Monitoring System Applied to the Hsinta Power Plant of Taiwan Power Company

Abstract

The continuous emission monitoring system (CEMS) can monitor flue gas emissions continuously and instantaneously. However, it has the disadvantages of enormous cost, easily producing errors in sampling periods of bad weather, lagging response in variable ambient environments, and missing data in daily zero and span tests and maintenance. The concept of a predictive emission monitoring system (PEMS) is to use the operating parameters of combustion equipment through thermodynamic or statistical methods to construct a mathematic model that can predict emissions by a computer program. The goal of this study is to set up a PEMS in a gas-fired combined cycle power generation unit at the Hsinta station of Taiwan Power Co. The emissions to be monitored include nitrogen oxides (NO_x) and oxygen (O₂) in flue gas. The major variables of the predictive model were determined based on the combustion theory. The data of these variables then were analyzed to establish a regression model. From the regression results, the influences of these variables are discussed and the predicted values are compared with the CEMS data for accuracy. In addition, according to the cost information, the capital and operation and maintenance costs for a PEMS can be much lower than those for a CEMS.     

Performance/Cost Estimates for Retrofitting Control Technologies

The U.S. EPA’s Air and Energy Engineering Research Laboratory is responsible for assessing control technology performance and costs under the National Acid Precipitation Assessment Program. A major part of this assessment involves developing site-specific estimates of the performance and costs of retrofitting SO₂ and NO_x control technologies for the top 200 SO₂- emitting (1980) coal-fired power plants in the 31-state eastern region. This effort includes detailed evaluation of a small number of plants (30 or less) representing a cross-section of the top 200 population. In cooperation with the states of Ohio and Kentucky (in conjunction with the U.S. EPA’s State Acid Rain Grant Program), efforts were undertaken to visit and conduct detailed evaluation of 12 coal-fired plants—five in Ohio, seven in Kentucky and the Tennessee Valley Authority System. A variety of commercial and advanced SO₂ and NO_x control technologies—including precombustion, combustion (in-furnace), and postcombustion (flue gas cleanup) technologies—were applied to each plant through conceptual designs. Retrofit factors (applied to the capital cost of a new pollution control system), cost “adders” (e.g., movement of existing equipment), and costs were developed for applying the control technologies to the boilers of each plant. Results of these and subsequent efforts will be valuable in evaluations of acid deposition control strategies by federal and state agencies and by electric utilities.     

Phase II Allowances Allocations and an Assessment of the Allowance Market in the West

Title IV of the Clean Air Act Amendments of 1990 establishes a unique “market-based“ approach to reduce national electric utility sulfur dioxide (SO₂) emissions during the next century by about 10 million tons/year below the corresponding level in 1980. This program is designed to provide utility operators with the flexibility to achieve the applicable SO₂ emissions limitations (total tons) using the most cost-effective approach. However, in reality, it is unlikely that many utility operators would have such operational flexibility, especially in the case of plants located in the Western United States. This is due to the fact that these sources may also be subject to other more stringent provisions of the Act, such as to protect public health and visibility, which override the Title IV provisions.

This paper examines the Phase II allowance allocations for the utility units located in the 11 western states and assesses the potential impacts of the current federal/state air quality regulatory programs on the allowance market in the West. This analysis shows that, even after accounting for the projected population growth and the accompanying growth in electric power demand during the next decade, the West should have a surplus of allowances, especially if new regulations are initiated to further reduce SO₂ emissions, mainly for the purpose of improving visibility in Western Class I areas.     

Electricity from Fossil Fuels without CO2 Emissions: Assessing the Costs of Carbon Dioxide Capture and Sequestration in U.S. Electricity Markets

ABSTRACT

The decoupling of fossil-fueled electricity production from atmospheric CO₂ emissions via CO₂ capture and sequestration (CCS) is increasingly regarded as an important means of mitigating climate change at a reasonable cost. Engineering analyses of CO₂ mitigation typically compare the cost of electricity for a base generation technology to that for a similar plant with CO₂ capture and then compute the carbon emissions mitigated per unit of cost. It can be hard to interpret mitigation cost estimates from this plant-level approach when a consistent base technology cannot be identified. In addition, neither engineering analyses nor general equilibrium models can capture the economics of plant dispatch. A realistic assessment of the costs of carbon sequestration as an emissions abatement strategy in the electric sector therefore requires a systems-level analysis. We discuss various frameworks for computing mitigation costs and introduce a simplified model of electric sector planning. Results from a “bottom-up” engineering-economic analysis for a representative U.S. North American Electric Reliability Council (NERC) region illustrate how the penetration of CCS technologies and the dispatch of generating units vary with the price of carbon emissions and thereby determine the relationship between mitigation cost and emissions reduction.     

Cofiring Hazardous Waste Fuels in Industrial Processes

Although energy-intensive industrial processes have the potential to incinerate hazardous wastes while effecting fuel cost savings, increased government regulation and heightened public interest require that the financial aspects of a hazardous waste fuel (HWF) program be considered fully. Apparent fuel savings are offset by the capital requirements for institutional factors such as permitting and public relations. This paper provides cost information for initiating and operating a HWF program, and outlines the steps required to perform a thorough financial analysis. Falling fuel prices lessen the appeal of HWF programs, and unless the facility is paid to accept the HWF, only very large users (more than 80 × 10⁹ Btu/yr) of energy can consider them. The paper includes a figure from which the reader can estimate the return on investment for HWF programs over a range of program sizes (80 × 1200 × 10⁹ Btu/yr).     

Determination of S02 Emission from Oil Combustion Sources by Fuel Analyses and S02/C02 Relations

The current S0₂ emission test methods, based on wet chemistry, are time consuming and costly. Final results depend on at least 10 separate measurements of quantities which may introduce significant errors due to human factors especially under unfavorable field environment. Performance evaluation of several promising S0₂ instrumental methods indicated that results were reliable and reproducible, but instrumental problems still exist. The problems were found to be calibration, mechanical and electronic components, and sample conditioning system. An alternative method proposed requires only two separate analyses: ultimate fuel analysis and stack gas analysis for C0₂. This method can be further simplified with reasonable accuracy by a single measurement of sulfur in the fuel if results are corrected to 12% C0₂. The method can be a useful addition to the current methods, especially if cost and manpower preclude actual stack tests. A test program was conducted at four industrial and utility power plants. Results are presented with discussion to show the application and validity of the simplified method.     

Creating markets for combined heat and power and clean distributed generation in New York State

Combined heat and power (CHP) is the simultaneous production of electrical or mechanical power and thermal energy from in a single process. Because thermal output from the generation of electricity is captured and utilized onsite, CHP systems can achieve efficiencies from 60% to as high as 90%. In contrast generation of electric power at sites remote from the loads served often results in efficiencies of 33% or less due to losses in generation and transmission and distribution of the power to ultimate end users. A well designed CHP system is the essence of energy efficiency. It may also provide significant environmental benefits. However, the full promise of CHP for improving the efficiency and productivity of businesses and the quality of the environment is unlikely to be realized given the current market structure and regulatory environment in which CHP projects are forced to compete. This paper examines the market structure and regulatory obstacles that hinder the development of more robust markets for CHP in New York State.     

Predicting the Performance of Particulate Control Equipment

A new probabilistic modeling environment is described which allows the explicit and quantitative representation of the uncertainties inherent in new environmental control processes for SO₂ and NO_x removal. Stochastic analyses provide additional insights into the uncertainties in process performance and cost not possible with conventional deterministic or sensitivity analysis. Applications of the probabilistic modeling framework are illustrated via an analysis of the performance and cost of the fluidized bed copper oxide process, an advanced technology for the control of SO₂ and NO_x emissions from coal-fired power plants. An engineering model of a conceptual commercial-scale system provides the basis for the analysis. The model also captures interactions between the power plant, the SO₂/NO_x removal process, and other components of the emission control system. Results of the analysis address payoffs from process design improvements; the dependence of system cost on process design conditions and the availability of byproduct markets; and the likelihood that the advanced process will yield cost savings relative to conventional technology. The implications of case study results for research planning and comparisons with alternative systems also are briefly discussed.     

A Probabilistic Production Costing Analysis of SO2 Emissions Reduction Strategies for Ohio: Emissions,Cost, and Employment Tradeoffs

A new approach for state- and utility-level analysis of the cost and regional economic impacts of strategies for reducing utility SO₂ emissions is summarized and applied to Ohio. The methodology is based upon probabilistic production costing and economic input-output analysis. It is an improvement over previous approaches because it: (1) accurately models random outages of generating units, “must-run” constraints on unit output, and the distribution of power demands; and (2) runs quickly on a microcomputer and yet considers the entire range of potential control strategies from a systems perspective. The input-output analysis considers not only the economic effects of utility fuel use and capital investment, but also those of increased electric rates. Two distinct strategies are found to be most attractive for Ohio. The first, more flexible one, consists of emissions dispatching (ED) alone to meet short run emissions reduction targets. A 75 percent reduction can then be achieved by the turn of the century by combining ED and fuel switching (FS) with flue gas desulfiirization, limestone Injection multistage burners, and physical coal cleaning at selected plants. The second is a scrubber-based strategy which includes ED. By the year 2000, energy conservation becomes a cost effective component of these strategies. In order to minimize compliance costs, acid rain legislation which facilitates emissions trading and places regional tonnage limits on emissions is desirable.     

Issues and Trends in Electrostatic Precipitation Technology for U.S. Utilities

The pace and direction of electrostatic precipitator (ESP) technology evolution in the United States will be governed by two key forces. The first is new clean air legislation passed by the U.S. Congress and signed by President Bush on November 15,1990. This law requires electric utilities to further reduce SO₂ and NO_x emissions, which may impact particulate controls. In addition, very fine (< 10 micron) participates and potentially toxic trace emissions from utility power plants may be regulated. The second major factor is the expected upsurge in new plant construction beginning in the late 1990s. Together, these forces should define the performance requirements and market for new ESPs.

This paper identifies and briefly describes technologies that the Electric Power Research Institute (EPRI) is developing to help U.S. utilities meet these challenges cost-effectively. Among the technologies addressed are: advanced digital voltage controls, flue gas conditioning, intermittent energization, temperature-controlledprecharging (i.e., two-stage ESP), wide plate spacing, positive energization of corona electrodes for hot-side ESPs, and integration of conventional ESPs with pulse-jet baghouses.     

Sulfur Dioxide Emissions and Market Effects under the Clean Air Act Acid Rain Program

ABSTRACT

The Clean Air Act Amendments of 1990 (CAAA90) established a national program to control sulfur dioxide (SO₂) emissions from electricity generation. CAAA90's market-based approach includes trading and banking of Soumissions allowances. We analyzed data describing electric utility SO₂ emissions in 1995, the first year of the program's Phase I, and market effects over the 1990-1995 period. Fuel switching and flue-gas desulfurization were the dominant means used in 1995 by targeted generators to reduce emissions to 51% of 1990 levels. Flue-gas desulfur-ization costs, emissions allowance prices, low-sulfur coal prices, and average sulfur contents of coals shipped to electric utilities declined over the 1990-1995 period. Projections indicate that 13-15 million allowances will have been banked during the program's Phase I, which ends in 1999, a quantity expected to last through the first decade of the program's stricter Phase II controls. In 1995, both allowance prices and SO₂ emissions were below pre-CAAA90 expectations. The reduction of SO₂ emissions beyond pre-CAAA90 expectations, combined with lower-than-expected allowance prices and declining compliance costs, can be viewed as a success for market-based environmental controls.     

Wet vs Dry Gas Cleaning In the Steel Industry

Deciding whether the gas should be cleaned by a “dry” system or a “wet” system requires a full consideration of all factors of which the capital cost is only one. Anticipating the various problems which might be expected and designing adequate measures for each calls for major engineering effort,but onlythen can a best choice be made. The principles which govern the above are illustrated by a typical selection of gas cleaning equipment to be used as part of a BOF steel making installation. Two entirely different gas cleaning systems are presently in BOF service in North America. Both will do an excellent job if properly designed. Either system will cost in excess of $2,000,000 and will require careful control and large amounts of electrical power. One system, the dry electrostatic precipitator, requires humidification of the gas; protection against explosions; elaborate electrical controls, insulators, etc.; and a rugged handling system for the bone dry dust collected. The other system, wet washing with water, Is easier to control but uses large quantities of water and electric power. As in the case of the “dry” system, handling the dirt collected is a difficult problem requiring careful study and choice of equipment. In either case the dust may be discarded or reused, but it must be handled with care lest it become an air or stream pollution problem all over again.     

A Fast Gas Chromatographic Method for Measuring C2-C6 Alkanes and Alkenes in Air

The Environmental Protection Agency is responsible for establishing, reviewing, and revising standards of performance for new stationary sources of air pollution. Since this federal program was authorized in 1970, standards of performance (commonly referred to as new source performance standards or NSPS) have been developed for 34 categories of stationary sources. These regulations have focused primarily on large new sources of particulate matter, NO _x , and SO₂ emissions. Recently, work has begun on NSPS for a number of source categories that emit volatile organic compounds. Environmental professionals in these industries and in many regulatory agencies have little direct experience with the NSPS program and are unaware of the detailed engineering, cost, and economic information available with each proposed rulemaking. This article, therefore, reviews the purposes, procedures, and benefits of the NSPS program. A summary of the NSPS that have been promulgated through February 1983 are presented in tabular form.     

Further Validation of Artificial Neural Network-Based Emissions Simulation Models for Conventional and Hybrid Electric Vehicles

Abstract

With the advent of hybrid electric vehicles, computer-based vehicle simulation becomes more useful to the engineer and designer trying to optimize the complex combination of control strategy, power plant, drive train, vehicle, and driving conditions. With the desire to incorporate emissions as a design criterion, researchers at West Virginia University have developed artificial neural network (ANN) models for predicting emissions from heavy-duty vehicles. The ANN models were trained on engine and exhaust emissions data collected from transient dynamometer tests of heavy-duty diesel engines then used to predict emissions based on engine speed and torque data from simulated operation of a tractor truck and hybrid electric bus. Simulated vehicle operation was performed with the ADVISOR software package. Predicted emissions (carbon dioxide [CO₂] and oxides of nitrogen [NO_x]) were then compared with actual emissions data collected from chassis dynamometer tests of similar vehicles. This paper expands on previous research to include different driving cycles for the hybrid electric bus and varying weights of the conventional truck. Results showed that different hybrid control strategies had a significant effect on engine behavior (and, thus, emissions) and may affect emissions during different driving cycles. The ANN models underpredicted emissions of CO₂ and NO_x in the case of a class-8 truck but were more accurate as the truck weight increased.     

Product Gudie/1987

A computer program has been written to determine the cost of building and operating wet scrubbers on individual coal fired utilities in the states where emissions are likely to affect the acid rain problem in the eastern United States. The program differs from many other estimates since it calculates the cost for each of 831 individual sites. The capital costs for installing scrubbers on the top fifty sulfur oxide emitting plants will be about $20 billion. This will result in an increase in the cost of electricity on an average of 0.88 cents/kWh and a reduction of sulfur oxide emissions from 1980 of 7,100,000 tons per year. An additional reduction of at least 1,000,000 tons per year can be obtained by requiring all plants burning oil to burn low sulfur oil. These figures assume utilities will use least emissions dispatching and will use local coals containing at least 3.5 percent sulfur. The use of local coals should result in a further saving of at least 0.2 cents/kWh. This should make available a large supply of low sulfur coal which could reduce emissions of sulfur oxides by up to 1,000,000 tons per year. The SO₂ reductions will be continued for at least the next thirteen years and have a very significant effect through the year 2010.     

Assessment of Dry Sorbenf Emission Control Technologies Part II. Applications

The injection of dry alkaline compounds into the furnace or post-furnace regions of utility boilers to reduce SO₂ is currently under development as a lower cost option to conventional flue gas desulfurization technology. Part I of this paper focused on the science and process development of the various dry sorbent technologies. Part II will address applications of these technologies, including SO₂ removals in full-scale boilers, methodologies for designing sorbent injection systems, power plant impacts, process integration issues, and cost.

Because the dry technologies use the furnace and/or ducts as the chemical contactor, potential impacts on power plant operation and reliability are as critical in assessing the commercial applicability of each technology as SO₂ removal and sorbent utilization. Consequently, the technical and economic feasibility of the various dry processes is highly site specific.     

A feasibility study on the predictive emission monitoring system applied to the Hsinta power plant of Taiwan Power Company

The continuous emission monitoring system (CEMS) can monitor flue gas emissions continuously and instantaneously. However, it has the disadvantages of enormous cost, easily producing errors in sampling periods of bad weather, lagging response in variable ambient environments, and missing data in daily zero and span tests and maintenance. The concept of a predictive emission monitoring system (PEMS) is to use the operating parameters of combustion equipment through thermodynamic or statistical methods to construct a mathematic model that can predict emissions by a computer program. The goal of this study is to set up a PEMS in a gas-fired combined cycle power generation unit at the Hsinta station of Taiwan Power Co. The emissions to be monitored include nitrogen oxides (NOx) and oxygen (O2) in flue gas. The major variables of the predictive model were determined based on the combustion theory. The data of these variables then were analyzed to establish a regression model. From the regression results, the influences of these variables are discussed and the predicted values are compared with the CEMS data for accuracy. In addition, according to the cost information, the capital and operation and maintenance costs for a PEMS can be much lower than those for a CEMS.