Use of Aggregate Emission Reduction Cost Functions in Designing Optimal Regional SO2 Abatement Strategies

The 1990 Canadian long-range transport of air pollutants and acid deposition report divided North America into 40 sources of emission and 15 sensitive receptor sites. For the purpose of national policy making and international negotiation, the use of these large sources and few receptors may prove adequate. Due to inadequate information regarding cost of reducing emissions from each point source, it was felt necessary to design a method to generate cost functions for emission regions. The objective of this study was to develop aggregate cost functions that relate the cost of SO2 emission reductions to the amount of reduction achieved. The cost curves generated presume the application of control technologies to achieve a mandated regional emission reduction in the year 2000. The study has also assumed that trading will take place among plants within a region. The emissions inventories (GECOT and AIRS for the USA and RDIS for Canada) were used as the major source of data for the study. Cost functions were derived for forty emission regions. The functional forms that best fits estimated costs are either quadratic, power or linear in specifications. Furthermore, the cost functions indicted substantial variation (differences in marginal costs of removal) across emission regions. Preliminary analysis using Environment Canada’s Integrated Assessment Modelling platform indicated that strategies that make use of these functions and environmental goals will cost the industry and government the minimum amount compared to those that relay on quantitative emission reductions. Considering the findings of studies that indicated exposure of several watersheds to excess depositions of SO2 compared to critical loads, policy makers should examine ways of reducing emissions beyond what is already committed for the year 2005 or 2010. Future work will investigate interregional trading, especially between the bordering states of the USA and provinces of Canada based on these cost functions.long-range transport; air pollutants; acid deposition; North America ; sources; emission; cost functions; Canada; long-range transport; air pollutants; acid deposition; sources-receptors; SO2; cost curves; control technologies; USA; Integrated Assessment Modelling

Archiva: Volume 3, Issue 2

https://digitalcommons.imsa.edu/archiva/1000/thumbnail.jp

Use of Aggregate Emission Reduction Cost Functions in Designing Optimal Regional SO2 Abatement Strategies

The 1990 Canadian long-range transport of air pollutants and acid deposition report divided North America into 40 sources of emission and 15 sensitive receptor sites. For the purpose of national policy making and international negotiation, the use of these large sources and few receptors may prove adequate. Due to inadequate information regarding cost of reducing emissions from each point source, it was felt necessary to design a method to generate cost functions for emission regions. The objective of this study was to develop aggregate cost functions that relate the cost of SO2 emission reductions to the amount of reduction achieved. The cost curves generated presume the application of control technologies to achieve a mandated regional emission reduction in the year 2000. The study has also assumed that trading will take place among plants within a region. The emissions inventories (GECOT and AIRS for the USA and RDIS for Canada) were used as the major source of data for the study. Cost functions were derived for forty emission regions. The functional forms that best fits estimated costs are either quadratic, power or linear in specifications. Furthermore, the cost functions indicted substantial variation (differences in marginal costs of removal) across emission regions. Preliminary analysis using Environment Canada’s Integrated Assessment Modelling platform indicated that strategies that make use of these functions and environmental goals will cost the industry and government the minimum amount compared to those that relay on quantitative emission reductions. Considering the findings of studies that indicated exposure of several watersheds to excess depositions of SO2 compared to critical loads, policy makers should examine ways of reducing emissions beyond what is already committed for the year 2005 or 2010. Future work will investigate interregional trading, especially between the bordering states of the USA and provinces of Canada based on these cost functions

Alternative Methods of Marginal Abatement Cost Estimation: Non- Parametric Si Stance Functions

This project implements a economic methodology to measure the marginal abatement costs of pollution by measuring the lost revenue implied by an incremental reduction in pollution. It utilizes observed performance, or `best practice`, of facilities to infer the marginal abatement cost. The initial stage of the project is to use data from an earlier published study on productivity trends and pollution in electric utilities to test this approach and to provide insights on its implementation to issues of cost-benefit analysis studies needed by the Department of Energy. The basis for this marginal abatement cost estimation is a relationship between the outputs and the inputs of a firm or plant. Given a fixed set of input resources, including quasi-fixed inputs like plant and equipment and variable inputs like labor and fuel, a firm is able to produce a mix of outputs. This paper uses this theoretical view of the joint production process to implement a methodology and obtain empirical estimates of marginal abatement costs. These estimates are compared to engineering estimates

Use of Aggregate Emission Reduction Cost Functions in Designing Optimal Regional SO2 Abatement Strategies

The 1990 Canadian long-range transport of air pollutants and acid deposition report divided North America into 40 sources of emission and 15 sensitive receptor sites. For the purpose of national policy making and international negotiation, the use of these large sources and few receptors may prove adequate. Due to inadequate information regarding cost of reducing emissions from each point source, it was felt necessary to design a method to generate cost functions for emission regions. The objective of this study was to develop aggregate cost functions that relate the cost of SO2 emission reductions to the amount of reduction achieved. The cost curves generated presume the application of control technologies to achieve a mandated regional emission reduction in the year 2000. The study has also assumed that trading will take place among plants within a region. The emissions inventories (GECOT and AIRS for the USA and RDIS for Canada) were used as the major source of data for the study. Cost functions were derived for forty emission regions. The functional forms that best fits estimated costs are either quadratic, power or linear in specifications. Furthermore, the cost functions indicted substantial variation (differences in marginal costs of removal) across emission regions. Preliminary analysis using Environment Canada’s Integrated Assessment Modelling platform indicated that strategies that make use of these functions and environmental goals will cost the industry and government the minimum amount compared to those that relay on quantitative emission reductions. Considering the findings of studies that indicated exposure of several watersheds to excess depositions of SO2 compared to critical loads, policy makers should examine ways of reducing emissions beyond what is already committed for the year 2005 or 2010. Future work will investigate interregional trading, especially between the bordering states of the USA and provinces of Canada based on these cost functions

Oxygen-blown gasification combined cycle: Carbon dioxide recovery, transport, and disposal

This project emphasizes CO2-capture technologies combined with integrated gasification combined-cycle (IGCC) power systems, CO2 transportation, and options for the long-term sequestration Of CO2. The intent is to quantify the CO2 budget, or an ``equivalent CO2`` budget, associated with each of the individual energy-cycle steps, in addition to process design capital and operating costs. The base case is a 458-MW (gross generation) IGCC system that uses an oxygen-blown Kellogg-Rust-Westinghouse (KRW) agglomerating fluidized-bed gasifier, bituminous coal feed, and low-pressure glycol sulfur removal, followed by Claus/SCOT treatment, to produce a saleable product. Mining, feed preparation, and conversion result in a net electric power production for the entire energy cycle of 411 MW, with a CO2 release rate of 0.801 kg/kV-Whe. For comparison, in two cases, the gasifier output was taken through water-gas shift and then to low-pressure glycol H2S recovery, followed by either low-pressure glycol or membrane CO2 recovery and then by a combustion turbine being fed a high-hydrogen-content fuel. Two additional cases employed chilled methanol for H2S recovery and a fuel cell as the topping cycle, with no shift stages. From the IGCC plant, a 500-km pipeline takes the CO2 to geological sequestering. For the optimal CO2 recovery case, the net electric power production was reduced by 37.6 MW from the base case, with a CO2 release rate of 0.277 kg/kWhe (when makeup power was considered). In a comparison of air-blown and oxygen-blown CO2-release base cases, the cost of electricity for the air-blown IGCC was 56.86 mills/kWh, while the cost for oxygen-blown IGCC was 58.29 mills/kWh. For the optimal cases employing glycol CO2 recovery, there was no clear advantage; the cost for air-blown IGCC was 95.48 mills/kWh, and the cost for the oxygen-blown IGCC was slightly lower, at 94.55 mills/kWh

Well-to-wheels energy use and greenhouse gas emissions analysis of plug-in hybrid electric vehicles.

Researchers at Argonne National Laboratory expanded the Greenhouse gases, Regulated Emissions, and Energy use in Transportation (GREET) model and incorporated the fuel economy and electricity use of alternative fuel/vehicle systems simulated by the Powertrain System Analysis Toolkit (PSAT) to conduct a well-to-wheels (WTW) analysis of energy use and greenhouse gas (GHG) emissions of plug-in hybrid electric vehicles (PHEVs). The WTW results were separately calculated for the blended charge-depleting (CD) and charge-sustaining (CS) modes of PHEV operation and then combined by using a weighting factor that represented the CD vehicle-miles-traveled (VMT) share. As indicated by PSAT simulations of the CD operation, grid electricity accounted for a share of the vehicle's total energy use, ranging from 6% for a PHEV 10 to 24% for a PHEV 40, based on CD VMT shares of 23% and 63%, respectively. In addition to the PHEV's fuel economy and type of on-board fuel, the marginal electricity generation mix used to charge the vehicle impacted the WTW results, especially GHG emissions. Three North American Electric Reliability Corporation regions (4, 6, and 13) were selected for this analysis, because they encompassed large metropolitan areas (Illinois, New York, and California, respectively) and provided a significant variation of marginal generation mixes. The WTW results were also reported for the U.S. generation mix and renewable electricity to examine cases of average and clean mixes, respectively. For an all-electric range (AER) between 10 mi and 40 mi, PHEVs that employed petroleum fuels (gasoline and diesel), a blend of 85% ethanol and 15% gasoline (E85), and hydrogen were shown to offer a 40-60%, 70-90%, and more than 90% reduction in petroleum energy use and a 30-60%, 40-80%, and 10-100% reduction in GHG emissions, respectively, relative to an internal combustion engine vehicle that used gasoline. The spread of WTW GHG emissions among the different fuel production technologies and grid generation mixes was wider than the spread of petroleum energy use, mainly due to the diverse fuel production technologies and feedstock sources for the fuels considered in this analysis. The PHEVs offered reductions in petroleum energy use as compared with regular hybrid electric vehicles (HEVs). More petroleum energy savings were realized as the AER increased, except when the marginal grid mix was dominated by oil-fired power generation. Similarly, more GHG emissions reductions were realized at higher AERs, except when the marginal grid generation mix was dominated by oil or coal. Electricity from renewable sources realized the largest reductions in petroleum energy use and GHG emissions for all PHEVs as the AER increased. The PHEVs that employ biomass-based fuels (e.g., biomass-E85 and -hydrogen) may not realize GHG emissions benefits over regular HEVs if the marginal generation mix is dominated by fossil sources. Uncertainties are associated with the adopted PHEV fuel consumption and marginal generation mix simulation results, which impact the WTW results and require further research. More disaggregate marginal generation data within control areas (where the actual dispatching occurs) and an improved dispatch modeling are needed to accurately assess the impact of PHEV electrification. The market penetration of the PHEVs, their total electric load, and their role as complements rather than replacements of regular HEVs are also uncertain. The effects of the number of daily charges, the time of charging, and the charging capacity have not been evaluated in this study. A more robust analysis of the VMT share of the CD operation is also needed

Lighting energy efficiency opportunities at Cheyenne Mountain Air Station

CMAS is an intensive user of electricity for lighting because of its size, lack of daylight, and 24-hour operating schedule. Argonne National Laboratory recently conducted a lighting energy conservation evaluation at CMAS. The evaluation included inspection and characterization of existing lighting systems, analysis of energy-efficient retrofit options, and investigation of the environmental effects that these lighting system retrofits could have when they are ready to be disposed of as waste. Argonne devised three retrofit options for the existing lighting systems at various buildings: (1) minimal retrofit--limited fixture replacement; (2) moderate retrofit--more extensive fixture replacement and limited application of motion detectors; and (3) advanced retrofit--fixture replacement, reduction in the number of lamps, expansion of task lighting, and more extensive application of motion detectors. Argonne used data on electricity consumption to analyze the economic and energy effects of these three retrofit options. It performed a cost analysis for each retrofit option in terms of payback. The analysis showed that lighting retrofits result in savings because they reduce electricity consumption, cooling load, and maintenance costs. The payback period for all retrofit options was found to be less than 2 years, with the payback period decreasing for more aggressive retrofits. These short payback periods derived largely from the intensive (24-hours-per-day) use of electric lighting at the facility. Maintenance savings accounted for more than half of the annual energy-related savings under the minimal and moderate retrofit options and slightly less than half of these savings under the advanced retrofit option. Even if maintenance savings were excluded, the payback periods would still be impressive: about 4.4 years for the minimal retrofit option and 2 years for the advanced option. The local and regional environmental impacts of the three retrofit options were minimal

Gasification combined cycle: Carbon dioxide recovery, transport, and disposal

Initiatives to limit carbon dioxide (CO[sub 2]) emissions have drawn considerable interest to integrated gasification combined-cycle (IGCC) power generation. This process can reduce C0[sub 2] production because of its higher efficiency, and it is amenable to C0[sub 2] capture, because C0[sub 2] can be removed before combustion and the associated dilution with atmospheric nitrogen. This paper presents a process-design baseline that encompasses the IGCC system, C0[sub 2] transport by pipeline, and land-based sequestering of C0[sub 2] in geological reservoirs.The intent of this study is to provide the C0[sub 2] budget, or an equivalent C0[sub 2]'' budget, associated with each of the individual energy-cycle steps. Design capital and operating costs for the process are included in the full study but are not reported in the present paper. The value used for the equivalent C0[sub 2]'' budget will be 1 kg C0[sub 2]/kWh[sub e]