Stuart M. Cohen

Turning CO2 Capture On and Off in Response to Electric Grid Demand: A Baseline Analysis of Emissions and Economics

Coal consumption accounted for 36% of America’s CO2 emissions in 2005, yet because coal is a relatively inexpensive, widely available, and politically secure fuel, its use is projected to grow in the coming decades (USEIA, 2007, “World Carbon Dioxide Emissions From the Use of Fossil Fuels,” International Energy Annual 2005, http:// www.eia.doe.gov/emeu/iea/carbon.html). In order for coal to contribute to the U.S. energy mix without detriment to an environmentally acceptable future, implementation of carbon capture and sequestration (CCS) technology is critical. Techno-economic studies establish the large expense of CCS due to substantial energy requirements and capital costs. However, such analyses typically ignore operating dynamics in response to diurnal and seasonal variations in electricity demand and pricing, and they assume that CO2 capture systems operate continuously at high CO2 removal and permanently consume a large portion of gross plant generation capacity. In contrast, this study uses an electric grid-level dynamic framework to consider the possibility of turning CO2 capture systems off during peak electricity demands to regain generation capacity lost to CO2 capture energy requirements. This practice eliminates the need to build additional generation capacity to make up for CO2 capture energy requirements, and it might allow plant operators to benefit from selling more electricity during high price time periods. Postcombustion CO2 absorption and stripping is a leading capture technology that, unlike many other capture methods, is particularly suited for flexible or on/off operation. This study presents a case study on the Electric Reliability Council of Texas (ERCOT) electric grid that estimates CO2 capture utilization, system-level costs, and CO2 emissions associated with different strategies of using on/off CO2 capture on all coal-fired plants in the ERCOT grid in order to satisfy peak electricity demand. It compares base cases of no CO2 capture and “always on” capture with scenarios where capture is turned off during: (1) peak demand hours every day of the year, (2) the entire season of peak system demand, and (3) system peak demand hours only on seasonal peak demand days. By eliminating the need for new capacity to replace output lost to CO2 capture energy requirements, flexible CO2 capture could save billions of dollars in capital costs. Since capture systems remain on for most of the year, flexible capture still achieves substantial CO2 emissions reductions. DOI: 10.1115/1.4001573

Energy return on investment for algal biofuel production coupled with wastewater treatment

This study presents a second-order energy return on investment analysis to evaluate the mutual benefits of combining an advanced wastewater treatment plant (WWTP) (with biological nutrient removal) with algal biofuel production. With conventional, independently operated systems, algae production requires significant material inputs, which require energy directly and indirectly, and the WWTP requires significant energy inputs for treatment of the waste streams. The second-order energy return on investment values for independent operation of the WWTP and the algal biofuels production facility were determined to be 0.37 and 0.42, respectively. By combining the two, energy inputs can be reduced significantly. Consequently, the integrated system can outperform the isolated system, yielding a second-order energy return on investment of 1.44. Combining these systems transforms two energy sinks to a collective (second-order) energy source. However, these results do not include capital, labor, and other required expenses, suggesting that profitable deployment will be challenging.

Comparing post-combustion CO2 capture operation at retrofitted coal-fired power plants in the Texas and Great Britain electric grids

This work analyses the carbon dioxide (CO2) capture system operation within the Electric Reliability Council of Texas (ERCOT) and Great Britain (GB) electric grids using a previously developed first-order hourly electricity dispatch and pricing model. The grids are compared in their 2006 configuration with the addition of coal-based CO2 capture retrofits and emissions penalties from 0 to 100 US dollars per metric ton of CO2 (USD/tCO2). CO2 capture flexibility is investigated by comparing inflexible CO2 capture systems to flexible ones that can choose between full- and zero-load CO2 capture depending on which operating mode has lower costs or higher profits. Comparing these two grids is interesting because they have similar installed capacity and peak demand, and both are isolated electricity systems with competitive wholesale electricity markets. However, differences in capacity mix, demand patterns, and fuel markets produce diverging behaviours of CO2 capture at coal-fired power plants. Coal-fired facilities are primarily base load in ERCOT for a large range of CO2 prices but are comparably later in the dispatch order in GB and consequently often supply intermediate load. As a result, the ability to capture CO2 is more important for ensuring dispatch of coal-fired facilities in GB than in ERCOT when CO2 prices are high. In GB, higher overall coal prices mean that CO2 prices must be slightly higher than in ERCOT before the emissions savings of CO2 capture offset capture energy costs. However, once CO2 capture is economical, operating CO2 capture on half the coal fleet in each grid achieves greater emissions reductions in GB because the total coal-based capacity is 6 GW greater than in ERCOT. The market characteristics studied suggest greater opportunity for flexible CO2 capture to improve operating profits in ERCOT, but profit improvements can be offset by a flexibility cost penalty.

The system-wide economics of a carbon dioxide capture, utilization, and storage network: Texas Gulf Coast with pure CO2-EOR flood

This letter compares several bounding cases for understanding the economic viability of capturing large quantities of anthropogenic CO2 from coal-fired power generators within the Electric Reliability Council of Texas electric grid and using it for pure CO2 enhanced oil recovery (EOR) in the onshore coastal region of Texas along the Gulf of Mexico. All captured CO2 in excess of that needed for EOR is sequestered in saline formations at the same geographic locations as the oil reservoirs but at a different depth. We analyze the extraction of oil from the same set of ten reservoirs within 20- and five-year time frames to describe how the scale of the carbon dioxide capture, utilization, and storage (CCUS) network changes to meet the rate of CO2 demand for oil recovery. Our analysis shows that there is a negative system-wide net present value (NPV) for all modeled scenarios. The system comes close to breakeven economics when capturing CO2 from three coal-fired power plants to produce oil via CO2-EOR over 20 years and assuming no CO2 emissions penalty. The NPV drops when we consider a larger network to produce oil more quickly (21 coal-fired generators with CO2 capture to produce 80% of the oil within five years). Upon applying a CO2 emissions penalty of 60

Utilizing Solar Thermal Energy for Post-Combustion CO2 Capture

2009/tCO2 to fossil fuel emissions to ensure that coal-fired power plants with CO2 capture remain in baseload operation, the system economics drop significantly. We show near profitability for the cash flow of the EOR operations only; however, this situation requires relatively cheap electricity prices during operation.

The Effect of Fossil Fuel Prices on Flexible CO2 Capture Operation

There is broad scientific agreement that anthropogenic greenhouse gases are contributing to global climate change and that carbon dioxide (CO2 ) is the primary contributor. Coal-based electricity generation produces over 30% of U.S. CO2 emissions; however, coal is also an available, secure, and low cost fuel that currently provides roughly half of U.S. electricity. As the world transitions from the existing fossil fuel-based energy infrastructure to a sustainable energy system, carbon dioxide capture and sequestration (CCS) will be a critical technology to allow continued use of coal-based electricity in an environmentally acceptable manner. Post-combustion amine absorption and stripping is one leading CO2 capture technology that is relatively mature, available for retrofit, and amenable to flexible operation. However, standard system designs have high capital costs and can reduce plant output by approximately 30% due to energy requirements for solvent regeneration (stripping) and CO2 compression. A typical design extracts steam from the power cycle to provide CO2 capture energy, reducing net power output by 11–40%. One way to reduce the CO2 capture energy penalty while developing renewable energy technologies is to provide some or all CO2 capture energy with a solar thermal energy system. Doing so would allow greater power plant output when electricity demand and prices are the highest. This study presents an initial review of solar thermal technologies for supplying energy for CO2 capture with a focus on high temperature solar thermal systems. Parabolic trough and central receiver (power tower) technology appear technically able to supply superheated steam for CO2 compression or saturated steam for solvent stripping, but steam requirements depend strongly on power plant and CO2 capture system design. Evacuated tube and compound parabolic collectors could feasibly supply heat for solvent stripping. A parabolic trough system supplying the energy for CO2 compression and solvent stripping at a gross 500 megawatt-electrical coal-fired power plant using 7 molal MEA-based CO2 capture would require a total aperture area on the order of 2 km2 or more if sized for an average direct normal solar insolation of 561 W/m2 . The solar system’s capital costs would be roughly half that of the base coal-fired plant with CO2 capture. This analysis finds that irrespective of capital costs, relatively high electricity prices are required for additional electricity sales to offset the operating and maintenance costs of the solar thermal system, and desirable operational periods will be further limited by the availability of sunlight and thermal storage. At CO2 prices near 50 dollars per metric ton of CO2 , bypassing CO2 capture yields similar operating economics as using solar energy for CO2 capture with lower capital cost. Even at high CO2 prices, any operating profit improvement from using solar energy for CO2 capture is unlikely to offset system capital costs. For high temperature solar systems such as power towers and parabolic troughs, direct electricity generation is likely a more efficient way to use solar energy to replace output lost to CO2 capture energy. However, low temperature solar systems might integrate more seamlessly with solvent stripping equipment, and more rigorous plant design analysis is required to definitively assess the technical and economic feasibility of using solar energy for CO2 capture.Copyright

THE IMPACT OF ELECTRICITY MARKET CONDITIONS ON THE VALUE OF FLEXIBLE CO2 CAPTURE

Coal consumption for electricity generation produces over 30% of U.S. carbon dioxide (CO2 ) emissions, but coal is also an available, secure, and low cost fuel that is currently utilized to meet roughly half of America’s electricity demand. While the world transitions from the existing fossil fuel-based energy infrastructure to a sustainable energy system, carbon dioxide capture and sequestration (CCS) will be a critical technology that will allow continued use of coal in an environmentally acceptable manner. Techno-economic analyses are useful in understanding the costs and benefits of CCS. However, typical techno-economic analyses of post-combustion CO2 capture systems assume continuous operation at a high CO2 removal, which could use 30% of pre-capture electricity output and require new capacity installation to replace the output lost to CO2 capture energy requirements. This study, however, considers the inherent flexibility in post-combustion CO2 capture systems by modeling power plants that vary CO2 capture energy requirements in order to increase electricity output when economical under electricity market conditions. A first-order model of electricity dispatch and a competitive electricity market is used to investigate flexible CO2 capture in response to hourly electricity demand variations. The Electric Reliability Council of Texas (ERCOT) electric grid is used as a case study to compare plant and grid performance, economics, and CO2 emissions in scenarios without CO2 capture to those with flexible or inflexible CO2 capture systems. Flexible CO2 capture systems can choose how much CO2 to capture based on the competition between CO2 and electricity prices and a desire to either minimize operating costs or maximize operating profits. Coal and natural gas prices have varying degrees of predictability and volatility, and the relative prices of these fuels have a major impact on power plant operating costs and the resulting plant dispatch sequence. Because the chosen operating point in a flexible CO2 capture system affects net power plant efficiency, fuel prices also influence which CO2 capture operating point may be the most economical and the resulting dispatch of power plants with CO2 capture. Several coal and natural gas price combinations are investigated to determine their impact on flexible CO2 capture operation and the resulting economic and environmental impacts at the power plant and electric grid levels. This study investigates the costs and benefits of flexible CO2 capture in a framework of a carbon-constrained future where the effects of major energy infrastructure changes on fuel prices are not entirely clear.Copyright

Comparing Flexible CO2 Capture in Gas- and Coal-Dominated Electricity Markets

Carbon dioxide (CO2) capture with amine scrubbing at coal-fired power plants can remove 90% of the CO2 from flue gas, but operational energy requirements reduce net electrical output by 20–30%. Temporarily reducing the load on energy intensive components of the amine scrubbing process could temporarily increase power output and allow additional electricity sales when prices are high. Doing so could entail additional CO2 emissions, or amine solvent storage can be utilized to allow increased power output without additional CO2 emissions. Price-responsive flexible capture is studied for

Analysis of Flexible CO2 Capture Over an Investment Life Using a Dynamic Electric Grid Model

0–200/tCO2 and

Dynamic operation of amine scrubbing in response to electricity demand and pricing

2–11/MMBTU natural gas using a nominal 500 MW coal-fired facility in the 2010 Electric Reliability Council of Texas (ERCOT) grid. CO2 capture systems use a 7 molal monoethanolamine (MEA) solvent. Venting additional CO2 while increasing electrical output provides significant benefit only at