Economic evaluation of burning bituminous and western PRB coals for power production based on select pollution control scenarios

Loftus, Jonathan

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https://hdl.handle.net/2142/31010 Copy

Description

Title

Economic evaluation of burning bituminous and western PRB coals for power production based on select pollution control scenarios

Author(s)

Loftus, Jonathan

Issue Date

2012-05-22T00:21:25Z

Director of Research (if dissertation) or Advisor (if thesis)

• Rood, Mark J.
• Lu, Yongqi

Department of Study

Civil & Environmental Engineering

Discipline

Environmental Engineering in Civil Engineering

Degree Granting Institution

University of Illinois at Urbana-Champaign

Degree Name

M.S.

Degree Level

Thesis

Keyword(s)

• sulfur dioxide
• nitrogen oxides
• particulate matter (PM)
• mercury
• coal
• emissions
• regulations
• Integrated Environmental Control Model (IECM)
• economic
• bituminous
• Powder River Basin (PRB)
• pulverized coal power plant
• PC power plant
• air emission limitation
• carbon dioxide (CO2)
• greenhouse gas
• carbon dioxide (CO2) regulations
• carbon dioxide (CO2) capture
• flue gas
• monoethanolamine (MEA)
• absorption
• solid adsorption
• energy conversion efficiency
• limestone
• simulation
• ChemCAD
• energy use
• cost-effective
• coal cost
• mine-mouth
• coal blend
• SO2 control
• SO2 control cost
• plant size
• PM control
• PM control cost
• cost of electricity
• carbon dioxide (CO2) control cost
• carbon dioxide (CO2) emissions
• auxiliary power use
• limestone adsorption-desorption
• Monoethanolamine (MEA) process
• limestone process
• carbon dioxide (CO2) compression
• air separation unit (ASU)
• calcine
• power loss
• regeneration
• carbonation reaction heat
• high-temperature
• recovered for producing steam used for additional electricity generation
• net generation efficiency
• managers of coal-fired power plants
• cost-effective approach when burning select coals while simultaneously meeting stack emission regulations
• law- and policy-makers
• evaluate mining options
• free-on-board mine costs
• coal transportation costs
• policy options concurrent with desired impacts on coal production and sales
• assessing select CO2 control technologies regarding impact on energy conversion efficiency

Abstract

The U.S. Environmental Protection Agency (USEPA) finalized its Clean Air Interstate Rule (CAIR) and Clean Air Visibility Rule emission regulations in 2005, to limit emissions of sulfur dioxide, nitrogen oxides and particulate matter to the atmosphere. USEPA replaced CAIR with the Cross State Air Pollution Rule in August 2011. USEPA’s Clean Air Mercury Rule regulation was vacated by the D.C. Circuit Court in February of 2008; however, USEPA’s “National Emission Standards for Hazardous Air Pollutants from Coal and Oil-Fired Electric Utility Steam Generating Units” proposed in March 2011 further limits emissions of mercury to the atmosphere. As a result of these regulations, this study used the Integrated Environmental Control Model (IECM) to investigate the economic competitiveness of burning select blends of Illinois high-sulfur bituminous and western low-sulfur Powder River Basin (PRB) coals at pulverized coal (PC) power plants while meeting the air emission limitations in these regulations. Since power plants are one of the biggest emission sources of carbon dioxide (CO2) – a main greenhouse gas – and thus a target for potential CO2 regulations, 90% CO2 capture from the flue gas using a monoethanolamine (MEA) absorption process was also evaluated within the IECM study. Most existing CO2 capture systems utilize absorption-based technology, though it is an energy intensive process. The solid adsorption method has potential to be competitive with the MEA absorption process, regarding energy conversion efficiency for a PC power plant. Therefore, a second part of this study investigated a process using limestone to remove 90% of the CO2 emissions at a PC power plant. Simulation of the limestone process was performed using ChemCAD, as a “proof-of-concept” study with the goal of estimating the best-case energy use of the process at a PC power plant. The IECM study showed that the most cost-effective case scenario for PC power plants without CO2 capture, at the 2007 market coal costs, is an Illinois mine-mouth coal for a 650 MWe (gross) plant ($67.0/MWh) and a 70/30 PRB/Illinois coal blend for a 175 MWe (gross) plant ($95.0/MWh). The Illinois mine-mouth coal is most cost-effective for the 650 MWe case due primarily to its lower coal cost compared to the other coal types. The lower coal cost helps compensate for the higher SO2 control cost for the Illinois mine-mouth coal compared to the other coal types. The 70/30 PRB/Illinois coal blend replaces the Illinois mine-mouth as most cost-effective when the plant size is reduced to 175 MWe – even though the Illinois mine-mouth coal still has a lower coal cost compared to the other coal types – for the following reason: the SO2 and PM control costs for the Illinois mine-mouth case have a higher contribution to plant cost of electricity at the 175 MWe plant than at the 650 MWe plant, whereas these control costs for the 70/30 PRB/Illinois coal blend have essentially the same contribution to plant cost at both plant sizes. The most cost-effective case scenario for PC plants seeking to add CO2 capture, at the 2007 market coal costs, is the 70/30 PRB/Illinois coal blend for both a 650 MWe (gross) plant ($133.1/MWh) and a 175 MWe (gross) plant ($177.0/MWh). The CO2 control cost for the 70/30 PRB/Illinois coal blend is higher than the 100% Illinois and Illinois mine-mouth coals, due to the higher CO2 emissions inherent to burning PRB coal. However, the higher SO2 control costs for the 100% Illinois and Illinois mine-mouth coals, compared to the 70/30 PRB/Illinois coal blend, counter the lower CO2 control costs for these coals sufficiently to make the 70/30 PRB/Illinois coal blend most cost-effective for the 650 MWe and 175 MWe cases. The ChemCAD study of the limestone process for CO2 capture at a 533 MWe (gross) PC power plant – 498.5 MWe (net) before installation of CO2 control – showed that the total auxiliary power use for a best-case scenario of limestone adsorption-desorption is 150 MWe, compared to 175 MWe for the MEA process. The power use in the limestone process is attributed primarily to the CO2 compressor, followed by the air separation unit (ASU) required to calcine the limestone, and then the main feed pump. The power use for CO2 compression and the main feed pump in the limestone process is higher than the MEA process, and the ASU is required only for the limestone process. However, the power loss due to steam extraction from the power plant steam cycle for MEA regeneration leads to a higher total auxiliary power use for the MEA process. High quality carbonation reaction heat, along with other additional heat from the high-temperature (650 - 950 °C) limestone process, is recovered for producing steam used for additional electricity generation. This additional generation of electricity contributes to higher net generation efficiency at the power plant for the limestone process (30.8%) compared to the MEA process (27.2%). The IECM portion of this study may be used by managers of coal-fired power plants to assist in determining the most cost-effective approach when burning select coals while simultaneously meeting stack emission regulations. Law- and policy-makers may use results from the IECM study to evaluate mining options to lower free-on-board mine costs, evaluate coal transportation costs, and/or develop policy options concurrent with desired impacts on coal production and sales. Results from the ChemCAD portion of this study can be useful for assessing select CO2 control technologies regarding impact on energy conversion efficiency.

Graduation Semester

2012-05

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Copyright 2012 Jonathan Loftus

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