• Energy Research

Abstract We performed a study to determine whether flue gas bypass and solvent storage can increase the profitability of a power plant equipped with post-combustion carbon capture technology. By increasing flexibility, these technologies allow increased output when electric energy prices are high. We used the Integrated Environmental Control Model to characterize cost and operational parameters of a pulverized coal (PC) plant with both amine and ammonia carbon-capture systems, as well as a natural gas combined cycle plant with amine capture. We constructed profit-maximization operating models with both perfect and imperfect information about electric energy prices in a large electricity market in the Eastern United States. We optimized the size of the regenerator and solvent storage vessels to maximize profitability. Results indicate that the profitability benefits of flexible CCS range from 0 to 35%. Most of the potential benefit is capital savings from allowing the regenerator to be undersized. The benefits of flexible CCS were found to decline with increasing CO 2 prices, with steady-state units preferable above a CO 2 emissions price of $40/tonne. Flexible CCS was never optimal when the overall plant was profitable. While flexible CCS can boost profitability under policies that force plants with CCS to be built even where they are not profitable, it is less relevant under market-based policies that incentivize CCS through CO 2 prices.

Replacing current generation with wind energy would help reduce the emissions associated with fossil fuel electricity generation. However, integrating wind into the electricity grid is not without cost. Wind power output is highly variable and average capacity factors from wind farms are often much lower than conventional generators. Further, the best wind resources with highest capacity factors are often located far away from load centers and accessing them therefore requires transmission investments. Energy storage capacity could be an alternative to some of the required transmission investment, thereby reducing capital costs for accessing remote wind farms. This work focuses on the trade-offs between energy storage and transmission. In a case study of a 200 MW wind farm in North Dakota to deliver power to Illinois, we estimate the size of transmission and energy storage capacity that yields the lowest average cost of generating and delivering electricity ($/MW h) from this farm. We find that transmission costs must be at least $600/MW-km and energy storage must cost at most $100/kW h in order for this application of energy storage to be economical.

AbstractThe objective of carbon capture and sequestration (CCS) is to reduce emissions to the atmosphere through the sequestration of carbon dioxide (CO2) in deep geologic formations. Recent studies of life-cycle emissions from CCS projects that sequester CO2 captured from coal-fired power generation through EOR show that net emissions from this process are positive due to the CO2 emissions embodied in produced oil. For geologic sequestration through enhanced oil recovery (GS-EOR) to be effective, life cycle GHG emissions from the system must be small and consumption of the energy produced should not result in larger emissions than would otherwise happen in the absence of the GS-EOR project. In the best case, where relatively high emissions intensity oil and electrical generation are being displaced, the emissions reduction potential is greater than the amount of CO2 purchased by the project; however, where a relatively light crude and carbon free marginal generation is being displaced, the GS-EOR project results in an emissions increase. As a matter of public policy, if reducing emissions of CO2 is of great importance, encouraging GS-EOR will not be as effective as geologic sequestration in deep saline aquifers, or other means of reducing emissions that do not result in increased production of fossil fuels. Nonetheless, it is likely that GS-EOR projects will happen in the absence of emissions reduction incentives because they bring other benefits. The nature and scope of a GHG reduction program will determine the accounting approach needed to accurately estimate the emissions from GS-EOR, but in general, components that do not fall under an emissions cap will need to be accounted for via life cycle assessment. While further study is needed, it appears that allocating the emissions reduction to an electric power generator would be less complex and more effective that allocating it to the oil or fuels producer.

The electric power sector in the United States faces many challenges related to climate change. On the demand side, climate change could shift demand patterns due to increased air temperatures. On the supply side, climate change could lead to deratings of thermal units due to changes in air temperature, water temperature, and water availability. Past studies have typically analyzed these risks separately. Here, we developed an integrated, multimodel framework to analyze how compounding risks of climate-change impacts on demand and supply affect long-term planning decisions in the power system. In the southeast U.S., we found that compounding climate-change impacts could result in a 35% increase in installed capacity by 2050 relative to the reference case. Participation of renewables, particularly solar, in the fleet increased, driven mostly by the expected increase in summertime peak demand. Such capacity requirements would increase investment costs by approximately 31 billion (USD 2015) over the next 30 years, compared to the reference case. These changes in investment decisions align with carbon emission mitigation strategies, highlighting how adaptation and mitigation strategies can converge.

As the growth of renewable energy continues, it is imperative that adequate funds are secured to successfully decommission projects at the end of their useful life. Additionally, it is important to ensure that regulatory decommissioning obligations do not disproportionately burden any generation resource.

We assess the economic value of life-cycle air emissions and oil consumption from conventional vehicles, hybrid-electric vehicles (HEVs), plug-in hybrid-electric vehicles (PHEVs), and battery electric vehicles in the US. We find that plug-in vehicles may reduce or increase externality costs relative to grid-independent HEVs, depending largely on greenhouse gas and SO2emissions produced during vehicle charging and battery manufacturing. However, even if future marginal damages from emissions of battery and electricity production drop dramatically, the damage reduction potential of plug-in vehicles remains small compared to ownership cost. As such, to offer a socially efficient approach to emissions and oil consumption reduction, lifetime cost of plug-in vehicles must be competitive with HEVs. Current subsidies intended to encourage sales of plug-in vehicles with large capacity battery packs exceed our externality estimates considerably, and taxes that optimally correct for externality damages would not close the gap in ownership cost. In contrast, HEVs and PHEVs with small battery packs reduce externality damages at low (or no) additional cost over their lifetime. Although large battery packs allow vehicles to travel longer distances using electricity instead of gasoline, large packs are more expensive, heavier, and more emissions intensive to produce, with lower utilization factors, greater charging infrastructure requirements, and life-cycle implications that are more sensitive to uncertain, time-sensitive, and location-specific factors. To reduce air emission and oil dependency impacts from passenger vehicles, strategies to promote adoption of HEVs and PHEVs with small battery packs offer more social benefits per dollar spent.

Plastics production is responsible for 1% and 3% of U.S. greenhouse gas (GHG) emissions and primary energy use, respectively. Replacing conventional plastics with bio-based plastics (made from renewable feedstocks) is frequently proposed as a way to mitigate these impacts. Comparatively little research has considered the potential for green energy to reduce emissions in this industry. This paper compares two strategies for reducing greenhouse gas emissions from U.S. plastics production: using renewable energy or switching to renewable feedstocks. Renewable energy pathways assume all process energy comes from wind power and renewable natural gas derived from landfill gas. Renewable feedstock pathways assume that all commodity thermoplastics will be replaced with polylactic acid (PLA) and bioethylene-based plastics, made using either corn or switchgrass, and powered using either conventional or renewable energy. Corn-based biopolymers produced with conventional energy are the dominant near-term biopolymer option, and can reduce industry-wide GHG emissions by 25%, or 16 million tonnes CO _2 e/year (mean value). In contrast, switching to renewable energy cuts GHG emissions by 50%–75% (a mean industry-wide reduction of 38 million tonnes CO _2 e/year). Both strategies increase industry costs—by up to $85/tonne plastic (mean result) for renewable energy, and up to $3000 tonne ^−1 plastic for renewable feedstocks. Overall, switching to renewable energy achieves greater emission reductions, with less uncertainty and lower costs than switching to corn-based biopolymers. In the long run, producing bio-based plastics from advanced feedstocks (e.g. switchgrass) and/or with renewable energy can further reduce emissions, to approximately 0 CO _2 e/year (mean value).