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The withdrawal and consumption of water at electricity generation plants, mainly for cooling purposes, is a significant component of the energy water nexus in the US. The existing field data on US power plant water use, however, is of limited granularity and poor quality, hampering efforts to track industry trends and project future scenarios. Furthermore, there is a need for a common quantitative framework on which to evaluate the potential of the many technologies that have been proposed to reduce water use at power plants. To address these deficiencies, we have created a systemlevel generic model (S-GEM) of water use at power plants that applies to fossil, nuclear, geothermal and solar thermal plants, using either steam or combined cycles. The S-GEM is a computationally inexpensive analytical model that approximately reflects the physics of the key processes involved and requires a small number of input parameters; the outputs are water withdrawal and consumption intensity in liters per kilowatt-hour. © 2011 by ASME., British Petroleum Company

Coal--CO[subscript 2] slurry feed has been suggested as an attractive alternative to coal–water slurry feed for single-stage, entrained-flow gasifiers. Previous work demonstrated the system-level advantages of gasification-based plants equipped with CO[subscript 2] capture and CO[subscript 2] slurry feed, under the assumption that carbon conversion remains unchanged. However, gasification in carbon dioxide has been observed to be slower than that in steam. In view of this, the impact of CO[subscript 2] slurry feeding on gasification kinetics and ultimately on carbon conversion and oxygen consumption in a pressurized, single-stage entrained-flow gasifier processing bituminous coal is studied here using a 1-D reduced order model. Results show that the CO[subscript 2] gasification reaction plays a dominant role in char conversion when the feeding system is CO[subscript 2] slurry, increasing the CO content in the products by up to a factor of two. CO inhibition of the gasification reaction and a higher degree of internal mass transport limitations lead to an up to 60% slower gasification rate, when compared to a system based on coal-water slurry. Accordingly, a gasifier with CO[subscript 2] slurry feed has 15% less oxygen consumption but a 7%-point lower carbon conversion for a given reactor outlet temperature. The gasifier outlet temperature must be raised by 90 K in order to achieve the same conversion as in a water slurry-fed reactor; the peak reactor temperature increases by 220 K as a result. Net oxygen savings of 8% are estimated for a system with a CO[subscript 2] slurry-fed gasifier relative to one with water slurry and the same level of conversion., BP (Firm)

Cost-effective, large-scale carbon dioxide capture is a critical technology for mitigating greenhouse gas emissions, and current capture technologies are energy intensive and difficult to deploy in existing power plants. We have previously introduced a novel electrochemically-mediated process for amine regeneration, and demonstrated its feasibility with a proof-of-concept system that can efficiently modulate amine affinity to carbon dioxide under the effect of redox-responsive molecules. The electrochemical process is simple to install, obviating the need for expensive retrofits. In addition, due to its targeted nature, the process has the potential for lower energy consumption as compared with the thermal amine capture process. In this work, we analyze the energy consumption of the electrochemical process, building from thermodynamic lower bounds, and addressing electrochemical kinetics, transport requirements as well compression and pumping energy. The analysis suggests that the electrochemical process can generate carbon dioxide at the conditions required for transportation with an electrical energy consumption of less than 50 kJ per mole of carbon dioxide captured and compressed. The electrochemical process efficiency can be further improved by optimizing flow design and utilizing additives to reduce activation overpotentials., United States. Dept. of Energy

Highlights • Power plant and CCS capital costs have increased significantly since the SRCCS. • Levelized CCS costs show smaller increases due to changes in other cost factors. • Current CO2 avoidance costs are similar to index-adjusted SRCCS levels. • Selling CO2 for enhanced oil recovery can significantly reduce CCS costs. • Based on current cost ranges all major CCS pathways remain competitive. The objective of this paper is to assess the current costs of CO2 capture and storage (CCS) for new fossil fuel power plants and to compare those results to the costs reported a decade ago in the IPCC Special Report on Carbon Dioxide Capture and Storage (SRCCS). Toward that end, we employed a similar methodology based on review and analysis of recent cost studies for the major CCS options identified in the SRCCS, namely, post-combustion CO2 capture at supercritical pulverized coal (SCPC) and natural gas combined cycle (NGCC) power plants, plus pre-combustion capture at coal-based integrated gasification combined cycle (IGCC) power plants. We also report current costs for SCPC plants employing oxy-combustion for CO2 capture—an option that was still in the early stages of development at the time of the SRCCS. To compare current CCS cost estimates to those in the SRCCS, we adjust all costs to constant 2013 US dollars using cost indices for power plant capital costs, fuel costs and other O&M costs. On this basis, we report changes in capital cost, levelized cost of electricity, and mitigation costs for each power plant system with and without CCS. We also discuss the outlook for future CCS costs.

The two major pathways for energy utilization from biomass are conversion to a liquid fuel (i.e., biofuels) or conversion to electricity (i.e., biopower). In the United States (US), biomass policy has focused on biofuels. However, this paper will investigate three options for biopower: low co-firing (co-firing scenarios refer to combusting a given percentage of biomass with coal) (5%–10% biomass), medium co-firing (15%–20% biomass), and dedicated biomass firing (100% biomass). We analyze the economic and greenhouse gas (GHG) emissions impact of each of these options, with and without CO[subscript 2] capture and storage (CCS). Our analysis shows that in the absence of land use change emissions, all biomass co-combustion scenarios result in a decrease in GHG emissions over coal generation alone. The two biggest barriers to biopower are concerns about carbon neutrality of biomass fuels and the high cost compared to today’s electricity prices. This paper recommends two policy actions. First, the need to define sustainability criteria and initiate a certification process so that biomass providers have a fixed set of guidelines to determine whether their feedstocks qualify as renewable energy sources. Second, the need for a consistent, predictable policy that provides the economic incentives to make biopower economically attractive.

Adding post-combustion capture technology to existing coal-fired power plants is being considered as a near-term option for mitigating CO[subscript 2] emissions. To supply the thermal energy needed for CO[subscript 2] capture, much of the literature proposes thermal integration of the existing coal plant’s steam cycle with the capture process’ stripper reboiler. This paper examines the option of using an auxiliary natural gas turbine plant to meet the energetic demands of carbon capture and compression. Three different auxiliary plant technologies were compared to integration for 90% capture from an existing, 500 MW supercritical coal plant. CO[subscript 2] capture (via a monoethylamine (MEA) absorption process) and compression is simulated using Aspen Plus. Thermoflow software is used to simulate three gas plant technologies. In some circumstances, it is found that using an auxiliary natural gas turbine may make retrofits more attractive compared to using thermal integration. The most important factors affecting desirability of the auxiliary plant retrofit are the cost of natural gas, the full cost of integration, and the potential for sale of excess electricity., Research Council of Norway (Statoil (Firm: Norway), Massachusetts Institute of Technology. Carbon Sequestration Initiative

The focus of this study is the analysis of an integrated reforming combined cycle (IRCC) with natural gas as fuel input. This IRCC consisted of a hydrogen-fired gas turbine (GT) with a single-pressure steam bottoming cycle for power production. The reforming process section consisted of a pre-reformer and an air-blown auto thermal reformer (ATR) followed by water-gas shift reactors. The air to the ATR was discharged from the GT compressor and boosted up to system pressure by an air booster compressor. For the CO[subscript 2] capture sub-system, a chemical absorption setup was modeled. The design case model was modeled in GT PRO by Thermoflow, and in Aspen Plus. The Aspen Plus simulations consisted of two separate models, one that included the reforming process and the water-gas shift reactors. In this model were also numerous heat exchangers including the whole pre-heating section. Air and CO[subscript 2] compression was also incorporated into the model. As a separate flow sheet the chemical absorption process was modeled as a hot potassium carbonate process. The models were linked by Microsoft Excel. For the CO[subscript 2] capture system the model was not directly linked to Excel but instead a simple separator model was included in the reforming flow sheet with inputs such as split ratios, temperatures, and pressures from the absorption model. Outputs from the potassium model also included pump work and reboiler duty. A main focal point of the study was off-design simulations. For these steady-state off-design simulations GT MASTER by Thermoflow in conjunction with Aspen Plus were used. Also, inputs such as heat exchanger areas, compressor design point, etc., were linked in from the Aspen Plus reforming design model. Results indicate a net plant efficiency of 43.2% with approximately a 2%-point drop for an 80% part load case. Another off-design simulation, at 60% load, was simulated with a net plant efficiency around 39%. The CO[subscript 2] capture rate for all c, Research Council of Norway, StatoilHydro

This paper presents results from a survey on stakeholder attitudes towards Carbon Capture and Storage (CCS). The survey is the first to make a global comparison across three major regions; USA, Japan, and Europe. The 30-question survey targeted individuals working at stakeholder organizations that seek to shape, and will need to respond to, policy on CCS, including electric utilities, oil & gas companies, CO2-intensive industries and non-governmental organizations (NGOs). The results show generally small differences across the regions and between the different groups of stakeholders. All believed that the challenge of significant reductions in emissions using only current technologies was severe. There is a widespread belief both that renewable technologies such as solar power and CCS will achieve major market entry into the electricity sector within the next 10 to 20 years, whereas there is more skepticism about the role of hydrogen and especially nuclear fusion in the next 50 years. All groups were generally positive towards renewable energy. Yet, there were some notable areas of disagreement in the responses, for example, as expected, NGOs considered the threat of climate change to be more serious than the other groups. North Americans respondents were more likely to downplay the threat compared to those of the other regions. The Japanese were more concerned about the burden that would be placed on industry in the coming decade as a result of emissions constraints and NGOs were more likely to believe that the burden would be light or very light. NGOs believed CCS to be far more attractive than nuclear fusion power but much less than renewables. As expected, the risk for leakage from reservoirs was ranked number one of the risk options given., Alliance for Global Sustainability, National Institute of Advanced Industrial Science and Technology (Japan), Carbon Sequestration Initiative, Alliance for Global Sustainability (AGS project “Pathways to Sustainable European Energy Systems” funding)

Post combustion absorption technologies represent one of the most commercially ready technologies for CO2 capture. Solvent selection is the critical consideration in post-combustion absorption capture technology. In order to compare the performance of different solvents, it is necessary to perform simulations on a consistent basis and perform a process analysis of the system. The focus of this work was to develop consistent simulations for MEA and K2CO3 systems in ASPEN. The simulations have been developed within the ASPEN RateSep framework and are valid for both natural gas and coal fired power plants. This paper describes the methodology of the simulations and some results from the two systems. The MEA base case was validated with reported values in literature. Potassium carbonate was found to be particularly useful for pressurized combustion and for CO2 removal from product gases of reforming of natural gas or coal., Research Council of Norway, Statoil ASA

This paper provides a financial analysis for new supercritical pulverized coal plants with carbon capture and sequestration (CCS) that compares the effects of two relevant climate policies. First, an updated cost estimate is presented for new supercritical pulverized coal plants, both with and without CCS. The capital cost escalation of recent years can be attributed to rising materials, plant supply, and plant contractor constraints. This estimate is then compared with recent estimates from public sources. Second, several current and proposed public policies relevant to CCS are presented. Finally, a financial analysis is performed to evaluate the effectiveness of two likely US carbon regulations on deploying Nth-plant CCS technology. The major conclusion is that the leading US carbon cap-and-trade bills will likely not be sufficient to deploy CCS technology in a manner consistent with a 550 ppm CO[subscript 2] stabilization scenario. A more aggressive carbon policy including CCS research, development, and demonstration must be considered to achieve this goal with significant CCS deployment., Massachusetts Institute of Technology. Carbon Sequestration Initiative, MIT Industrial Performance Center

Electrochemically mediated amine regeneration is a new post-combustion capture technology with the potential to exploit the excellent removal efficiencies of thermal amine scrubbers while reducing parasitic energy losses and capital costs. The improvements result from the use of an electrochemical stripping cycle, in lieu of the traditional thermal swing, to facilitate CO[subscript 2] desorption and amine regeneration; metal cations generated at an anode react with the amines, displacing the CO[subscript 2], which is then flashed off, and the amines are regenerated by subsequent reduction of the metal cations in a cathode cell. The advantages of such a process include higher CO[subscript 2] desorption pressures, smaller absorbers, and lower energy demands. Several example chemistries using different polyamines and copper are presented. Experimental results indicate an open-circuit efficiency of 54% (15 kJ per mole CO[subscript 2]) is achievable at the tested conditions and models predict that 69% efficiency is possible at higher temperatures and pressures. A bench scale system produced 1.6 mL min[superscript −1] CO[subscript 2] while operating at 0.4 volts and 42% Faradaic efficiency; this corresponds to a work of less than 100 kJ per mole., United States. Advanced Research Projects Agency-Energy (Grant DE-AR0000083)