Haibo Zhai
Carnegie Mellon University, Engineering and Public Policy, Faculty Member
- nnnedit
ABSTRACT The main objective of this study is to investigate the feasibility and costs of ionic liquid (IL)-based CO2 capture systems at pulverized coal-fired (PC) power plants. The IL selected for this assessment is trihexyl-... more
ABSTRACT The main objective of this study is to investigate the feasibility and costs of ionic liquid (IL)-based CO2 capture systems at pulverized coal-fired (PC) power plants. The IL selected for this assessment is trihexyl- (tetradecyl)phosphonium 2-cyanopyrrolide ([P66614][2-CNpyr]), achieving a 1:1 and reversible chemical reaction between [2-CNpyr]− and CO2. A multi-stage equilibrium-based modeling framework is established to simulate the adiabatic absorption process, whereas a single-stage flash drum in equilibrium is employed for the stripping process. The performance model is linked to an engineering-economic model that estimates the capital cost, annual operating and maintenance (O&M) costs, and total levelized annual cost. The technical and cost models are applied to estimate the cost of CO2 captured by an IL-based CCS system. The preliminary results show that for 90% CO2 capture, the capture cost would be higher than the U.S. Department of Energy's target at $40 per metric ton of CO2 captured for new generation technologies, mainly due to a large capital cost. However, current process designs are not yet optimized. Based on the cost of CO2 captured, the most cost-effective capture cost is found to be at a removal efficiency of about 85% for CO2.
Advanced cooling systems can be deployed to enhance the resilience of thermoelectric power generation systems. This study developed and applied a new power plant modeling option for a hybrid cooling system at coal- or natural-gas-fired... more
Advanced cooling systems can be deployed to enhance the resilience of thermoelectric power generation systems. This study developed and applied a new power plant modeling option for a hybrid cooling system at coal- or natural-gas-fired power plants with and without amine-based carbon capture and storage (CCS) systems. The results of the plant-level analyses show that the performance and cost of hybrid cooling systems are affected by a range of environmental, technical, and economic parameters. In general, when hot periods last the entire summer, the wet unit of a hybrid cooling system needs to share about 30% of the total plant cooling load in order to minimize the overall system cost. CCS deployment can lead to a significant increase in the water use of hybrid cooling systems, depending on the level of CO2 capture. Compared to wet cooling systems, widespread applications of hybrid cooling systems can substantially reduce water use in the electric power sector with only a moderate i...
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This study employs a power plant modeling tool to explore the feasibility of reducing unit-level emission rates of CO2 by 30% by retrofitting carbon capture, utilization, and storage (CCUS) to existing U.S. coal-fired electric generating... more
This study employs a power plant modeling tool to explore the feasibility of reducing unit-level emission rates of CO2 by 30% by retrofitting carbon capture, utilization, and storage (CCUS) to existing U.S. coal-fired electric generating units (EGUs). Our goal is to identify feasible EGUs and their key attributes. The results indicate that for about 60 gigawatts of the existing coal-fired capacity, the implementation of partial CO2 capture appears feasible, though its cost is highly dependent on the unit characteristics and fuel prices. Auxiliary gas-fired boilers can be employed to power a carbon capture process without significant increases in the cost of electricity generation. A complementary CO2 emission trading program can provide additional economic incentives for the deployment of CCS with 90% CO2 capture. Selling and utilizing the captured CO2 product for enhanced oil recovery can further accelerate CCUS deployment and also help reinforce a CO2 emission trading market. Thes...
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Water is an integral element of energy production. Future US energy production will increasingly be driven by the need to mitigate climate change, posing complex water challenges. The water impacts of electricity generation in a... more
Water is an integral element of energy production. Future US energy production will increasingly be driven by the need to mitigate climate change, posing complex water challenges. The water impacts of electricity generation in a carbon-constrained future have been a subject of active research. This paper reviews technologies and regulatory policy options for low-carbon electricity generation, including systems that use fossil fuels with carbon capture and storage, renewables such as wind, solar, and biomass, and nuclear energy. We also review cooling technologies in support of thermoelectric power generation, report and discuss current assessment methods and results on water use for low-carbon energy production, and identify adaptive approaches that could reinforce resilience for low-carbon electricity generation. Some recommendations are made for future research.
There has been an increasing interest in the application of membranes to flue gas separation, primarily driven by the need of carbon capture for significantly reducing greenhouse gas emissions. Historically, there has not been general... more
There has been an increasing interest in the application of membranes to flue gas separation, primarily driven by the need of carbon capture for significantly reducing greenhouse gas emissions. Historically, there has not been general consensus about the advantage of membranes against other methods such as liquid solvents for carbon capture. However, recent research indicates that advances in materials and process designs could significantly improve the separation performance of membrane capture systems, which make membrane technology competitive with other technologies for carbon capture. This paper mainly reviews membrane separation for the application to post-combustion CO2 capture with a focus on the developments and breakthroughs in membrane material design, process engineering, and engineering economics.
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We employ an integrated systems modeling tool to assess the water impacts of the new source performance standards recently proposed by the U.S. Environmental Protection Agency for limiting CO2 emissions from coal- and gas-fired power... more
We employ an integrated systems modeling tool to assess the water impacts of the new source performance standards recently proposed by the U.S. Environmental Protection Agency for limiting CO2 emissions from coal- and gas-fired power plants. The implementation of amine-based carbon capture and storage (CCS) for 40% CO2 capture to meet the current proposal will increase plant water use by roughly 30% in supercritical pulverized coal-fired power plants. The specific amount of added water use varies with power plant and CCS designs. More stringent emission standards than the current proposal would require CO2 emission reductions for natural gas combined-cycle (NGCC) plants via CCS, which would also increase plant water use. When examined over a range of possible future emission standards from 1100 to 300 lb CO2/MWh gross, new baseload NGCC plants consume roughly 60–70% less water than coal-fired plants. A series of adaptation approaches to secure low-carbon energy production and improve the electric power industry’s water management in the face of future policy constraints are discussed both quantitatively and qualitatively.
This study investigates the feasibility of polymer membrane systems for postcombustion carbon dioxide (CO2) capture at coal-fired power plants. Using newly developed performance and cost models, our analysis shows that membrane systems... more
This study investigates the feasibility of polymer membrane systems for postcombustion carbon dioxide (CO2) capture at coal-fired power plants. Using newly developed performance and cost models, our analysis shows that membrane systems configured with multiple stages or steps are capable of meeting capture targets of 90% CO2 removal efficiency and 95+% product purity. A combined driving force design using both compressors and vacuum pumps is most effective for reducing the cost of CO2 avoided. Further reductions in the overall system energy penalty and cost can be obtained by recycling a portion of CO2 via a two-stage, two-step membrane configuration with air sweep to increase the CO2 partial pressure of feed flue gas. For a typical plant with carbon capture and storage, this yielded a 15% lower cost per metric ton of CO2 avoided compared to a plant using a current amine-based capture system. A series of parametric analyses also is undertaken to identify paths for enhancing the viability of membrane-based capture technology.
State and federal governments are considering performance standards to limit carbon dioxide (CO2) emissions from new fossil-fuel-fired electric-generating units. This study employs a newly developed computational tool to compare the... more
State and federal governments are considering performance standards to limit carbon dioxide (CO2) emissions from new fossil-fuel-fired electric-generating units. This study employs a newly developed computational tool to compare the performance and cost impacts of applying a technology-neutral CO2 emission performance standard to pulverized coal (PC) and natural gas combined cycle (NGCC) power plants and to evaluate the role of CO2 utilization in accelerating carbon capture and storage (CCS) deployment. We explore the impacts of performance standards between 1000 and 300 lb of CO2/MWh gross, a range more stringent than the recently proposed standard by the United States Environmental Protection Agency (U.S. EPA). Meeting such standards would require CO2 emission reductions of roughly 45–85% for new PC baseload plants and 0–65% for new NGCC baseload plants. Adding current amine-based CCS to meet these standards increases the plant levelized cost of electricity by 35–66% for PC plants and 0–26% for NGCC plants. On an absolute basis, meeting the most stringent standard of 300 lb/MWh gross would add $38.9/MWh to the cost of the PC plant but only $16.5/MWh for the NGCC plant. This cost advantage of NGCC plants relative to PC plants is strongly affected by plant capacity factor and natural gas price and could be diminished by gas prices above approximately $9.0/GJ for new baseload plants subject to a range of performance standards. Our analysis of the enhanced oil recovery (EOR) option shows that, at a price of roughly $40/metric ton of CO2, the revenue from selling the captured CO2 for the EOR could fully offset the capture cost for PC plants. Higher CO2 prices would be required to fully pay for CO2 capture at NGCC plants. Using the captured CO2 for EOR thus would facilitate continued coal use for low-carbon electricity generation, even under the most stringent performance standard modeled.
This paper examines the cost of CO2 capture and storage (CCS) for natural gas combined cycle (NGCC) power plants. Existing studies employ a broad range of assumptions and lack a consistent costing method. This study takes a more... more
This paper examines the cost of CO2 capture and storage (CCS) for natural gas combined cycle (NGCC) power plants. Existing studies employ a broad range of assumptions and lack a consistent costing method. This study takes a more systematic approach to analyze plants with an amine-based postcombustion CCS system with 90% CO2 capture. We employ sensitivity analyses together with a probabilistic analysis to quantify costs for plants with and without CCS under uncertainty or variability in key parameters. Results for new baseload plants indicate a likely increase in levelized cost of electricity (LCOE) of $20–32/MWh (constant 2007$) or $22–40/MWh in current dollars. A risk premium for plants with CCS increases these ranges to $23–39/MWh and $25–46/MWh, respectively. Based on current cost estimates, our analysis further shows that a policy to encourage CCS at new NGCC plants via an emission tax or carbon price requires (at 95% confidence) a price of at least $125/t CO2 to ensure NGCC-CCS is cheaper than a plant without CCS. Higher costs are found for nonbaseload plants and CCS retrofits.
Coal-fired power plants account for nearly 50% of U.S. electricity supply and about a third of U.S. emissions of CO2, the major greenhouse gas (GHG) associated with global climate change. Thermal power plants also account for 39% of all... more
Coal-fired power plants account for nearly 50% of U.S. electricity supply and about a third of U.S. emissions of CO2, the major greenhouse gas (GHG) associated with global climate change. Thermal power plants also account for 39% of all freshwater withdrawals in the U.S. To reduce GHG emissions from coal-fired plants, postcombustion carbon capture and storage (CCS) systems are receiving considerable attention. Current commercial amine-based capture systems require water for cooling and other operations that add to power plant water requirements. This paper characterizes and quantifies water use at coal-burning power plants with and without CCS and investigates key parameters that influence water consumption. Analytical models are presented to quantify water use for major unit operations. Case study results show that, for power plants with conventional wet cooling towers, approximately 80% of total plant water withdrawals and 86% of plant water consumption is for cooling. The addition of an amine-based CCS system would approximately double the consumptive water use of the plant. Replacing wet towers with air-cooled condensers for dry cooling would reduce plant water use by about 80% (without CCS) to about 40% (with CCS). However, the cooling system capital cost would approximately triple, although costs are highly dependent on site-specific characteristics. The potential for water use reductions with CCS is explored via sensitivity analyses of plant efficiency and other key design parameters that affect water resource management for the electric power industry.
Thermoelectric power plants require significant quantities of water, primarily for the purpose of cooling. Water also is becoming critically important for low-carbon power generation. To reduce greenhouse gas emissions from pulverized... more
Thermoelectric power plants require significant quantities of water, primarily for the purpose of cooling. Water also is becoming critically important for low-carbon power generation. To reduce greenhouse gas emissions from pulverized coal (PC) power plants, post-combustion carbon capture and storage (CCS) systems are receiving considerable attention. However, current CO2 capture systems require a significant amount of cooling. This paper evaluates and quantifies the plant-level performance and cost of different cooling technologies for PC power plants with and without CO2 capture. Included are recirculating systems with wet cooling towers and air-cooled condensers (ACCs) for dry cooling. We examine a range of key factors affecting cooling system performance, cost and plant water use, including the plant steam cycle design, coal type, carbon capture system design, and local ambient conditions. Options for reducing power plant water consumption also are presented.
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This study presents a methodology for estimating high-resolution, regional on-road vehicle emissions and the associated reductions in air pollutant emissions from vehicles that utilize alternative fuels or propulsion technologies. The... more
This study presents a methodology for estimating high-resolution, regional on-road vehicle emissions and the associated reductions in air pollutant emissions from vehicles that utilize alternative fuels or propulsion technologies. The fuels considered are gasoline, diesel, ethanol, biodiesel, compressed natural gas, hydrogen, and electricity. The technologies considered are internal combustion or compression engines, hybrids, fuel cell, and electric. Road link-based emission models are developed using modal fuel use and emission rates applied to facility- and speed-specific driving cycles. For an urban case study, passenger cars were found to be the largest sources of HC, CO, and CO2 emissions, whereas trucks contributed the largest share of NOx emissions. When alternative fuel and propulsion technologies were introduced in the fleet at a modest market penetration level of 27%, their emission reductions were found to be 3−14%. Emissions for all pollutants generally decreased with an increase in the market share of alternative vehicle technologies. Turnover of the light duty fleet to newer Tier 2 vehicles reduced emissions of HC, CO, and NOx substantially. However, modest improvements in fuel economy may be offset by VMT growth and reductions in overall average speed.
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This paper explores the influence of key factors such as speed, acceleration, and road grade on fuel consumption for diesel and hydrogen fuel cell buses under real-world operating conditions. A Vehicle Specific Power-based approach is... more
This paper explores the influence of key factors such as speed, acceleration, and road grade on fuel consumption for diesel and hydrogen fuel cell buses under real-world operating conditions. A Vehicle Specific Power-based approach is used for modeling fuel consumption for both types of buses. To evaluate the robustness of the modeling approach, Vehicle Specific Power-based modal average fuel consumption rates are compared for diesel buses in the US and Portugal, and for the Portuguese diesel and hydrogen fuel cell buses that operate on the same route. For diesel buses there is similar intra-vehicle variability in fuel consumption using Vehicle Specific Power modes. For the fuel cell bus, the hydrogen fuel consumption rate was found to be less sensitive to Vehicle Specific Power variations and had smaller variability compared to diesel buses. Relative errors between trip fuel consumption estimates and actual fuel use, based upon predictions for a portion of real-world activity data that were not used to calibrate the models, were generally under 10% for all observations. The Vehicle Specific Power-based modeling approach is recommended for further applications as additional data become available. Emission changes based upon substituting hydrogen versus diesel buses are evaluated.
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Heavy-duty diesel vehicles contribute a substantial fraction of nitrogen oxides (NOx) and particulate matter (PM) to the on-road vehicle emission inventory. The objectives of this study are to estimate roadway linkbased emission rates for... more
Heavy-duty diesel vehicles contribute a substantial fraction of nitrogen oxides (NOx) and particulate matter (PM) to the on-road vehicle emission inventory. The objectives of this study are to estimate roadway linkbased emission rates for heavy-duty trucks for use in emission inventory estimation and to quantify the impact of factors affecting truck emissions. A speed-acceleration modal emission approach is developed from a database gathered via a portable emission measurement system for single rear-axle and tandem-axle dump trucks. Second-by-second realworld truck speed profiles on links are analyzed on the basis of observed patterns of time distributions of speed-acceleration modes. Link-based emission rates are estimated as the product of the fraction of time spent in each mode and the corresponding modal average emission rate. The sensitivity of link-based emission rates to key factors including chassis type, vehicle load, and fuel type is discussed. Single rear-axle trucks have lower emission rates than do tandem-axle trucks for carbon dioxide, PM, nitric oxide (NO), and hydrocarbons (HC) but higher carbon monoxide (CO) emission rates. Loaded trucks have higher fuel use and emissions than unloaded trucks. Replacing diesel fuel with biodiesel fuel for heavy-duty trucks may reduce tailpipe NO exhaust emissions and will reduce emissions of PM, CO, and HC. However, both fuels generate similar CO2 emissions. Benchmark comparisons for link-based emission rates show that NO emission rates increase with mean speed. However, link-based CO and HC emission rates were not as sensitive to speed variation as NO emissions. The link-based emission rate approach is recommended to couple heavy-duty vehicle emission inventory estimation with transportation demand models.
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Estimating the emissions consequences of surface transportation operations is a complex process. Decision makers need to quantify the air quality impacts of transportation improvements aimed at reducing congestion on the surface street... more
Estimating the emissions consequences of surface transportation operations is a complex process. Decision makers need to quantify the air quality impacts of transportation improvements aimed at reducing congestion on the surface street network. This often requires the coupling of transportation and emissions models in ways that are sometimes incompatible. For example, most macroscopic transportation demand and land use models, such as TransCAD, TranPlan, and TRANUS, produce average link speed and link vehicle miles traveled (VMT) by vehicle and road class. These values are subsequently used to estimate link-based emissions by using standard emissions models such as the U.S. Environmental Protection Agency's MOBILE6 model. In contrast, recent research with portable emissions monitoring systems indicates that emissions are not directly proportional to VMT but are episodic in nature, with high-emissions events coinciding with periods of high acceleration and speed. This research represents an attempt to bridge the gap in transportation and emissions models through the use of the real-world distributions of vehicle-specific power bins that are associated with average link speeds for various road classes. A successful effort in this direction would extend the use of transportation models to improve emissions estimation by using the limited output produced by such models. In addition, the variability of emissions and emissions rates over average speeds for a given facility type is explored, and recommendations are made to extend the methodology to additional facility types.