Environmental Gains and Impacts of a CCS Technology – Case Study of Post-combustion CO2 Separation by Ammonia Absorption

Carbon dioxide has been identified as a major greenhouse gas responsible for a large part of the enhancement of global warming. CO <inf xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink">2</inf> capture and storage (CCS) from power plants is drawing increasing interest as a potential method for the control of greenhouse gas emissions. Technically, the capture of CO <inf xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink">2</inf> from the flue gas of power plants, using a monoethanolamine (MEA) absorption process is a viable shortcut to medium term strategy for the mitigation of the atmospheric CO <inf xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink">2</inf> emissions from large point sources. An economical performance study for a CO <inf xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink">2</inf> removal plant from flue gas of a NGCC syngas-fired power plant was performed, based on absorption/regeneration process with MEA solutions, using ASPEN Plus. The conclusion is that the efficiency drop due to CO <inf xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink">2</inf> removal plant is approximately 12.9%; and the cost of CO <inf xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink">2</inf> captured and the cost of CO <inf xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink">2</inf> avoided are respectively 13 euros/tCO <inf xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink">2</inf> and 18 euros/tCO <inf xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink">2</inf> . In order to popularize large-scale CCS to power plants, technology improvement is greatly needed.

Carbon dioxide has been identified as a major greenhouse gas responsible for a large part of the enhancement of global warming. CO2 capture and storage (CCS) from power plants is drawing increasing interest as a potential method for the control of greenhouse gas emissions. Technically, the capture of CO2 from the flue gas of power plants, using a monoethanolamine (MEA) absorption process is a viable shortcut to medium term strategy for the mitigation of the atmospheric CO2 emissions from large point sources. Specific consumption analysis was performed on a CO2 recovery process, which was firstly simulated in ASPEN PLUSE. And the simulation results were valid based on the experimental data. The conclusion is that the energy consumption is 4.25 MJ/kg CO2, and the stripper accounts for the most energy loss. Measures can be taken to lower the energy consumption. In order to popularize large-scale CCS to power plants, technology improvement is greatly needed.

ADA's Solid Sorbent CO2 Capture process: Developing Solid Sorbent Technology to Provide the Necessary Flexible CO2 Capture Solutions for a Wide Range of Applications

The production of six regionally important cellulosic biomass feedstocks, including pine, eucalyptus, unmanaged hardwoods, forest residues, switchgrass, and sweet sorghum, was analyzed using consistent life cycle methodologies and system boundaries to identify feedstocks with the lowest cost and environmental impacts. Supply chain analysis models were created for each feedstock calculating costs and supply chain requirements for the production 453,592 dry tonnes of biomass per year. Cradle-to-gate environmental impacts from these supply systems were quantified for nine mid-point indicators using SimaPro 7.2 LCA software. Conversion of grassland to managed forest for bioenergy resulted in large reductions in GHG emissions, due to carbon sequestration associated with direct land use change. However, converting forests to energy cropland resulted in large increases in GHG emissions. Production of forest-based feedstocks for biofuels resulted in lower delivered cost, lower greenhouse gas (GHG) emissions and lower overall environmental impacts than the studied agricultural feedstocks. Forest residues had the lowest environmental impact and delivered cost per dry tonne. Using forest-based biomass feedstocks instead of agricultural feedstocks would result in lower cradle-to-gate environmental impacts and delivered biomass costs for biofuel production in the southern U.S.

Advanced bibliometric analysis on the development of natural gas combined cycle power plant with CO2 capture and storage technology

The objective of this project was to assess the feasibility of using a membrane process to capture CO2 from coal-fired power plant flue gas. During this program, MTR developed a novel membrane (Polaris™) with a CO2 permeance tenfold higher than commercial CO2-selective membranes used in natural gas treatment. The Polaris™ membrane, combined with a process design that uses a portion of combustion air as a sweep stream to generate driving force for CO2 permeation, meets DOE post-combustion CO2 capture targets. Initial studies indicate a CO2 separation and liquefaction cost of $20 - $30/ton CO2 using about 15% of the plant energy at 90% CO2 capture from a coal-fired power plant. Production of the Polaris™ CO2 capture membrane was scaled up with MTR’s commercial casting and coating equipment. Parametric tests of cross-flow and countercurrent/sweep modules prepared from this membrane confirm their near-ideal performance under expected flue gas operating conditions. Commercial-scale, 8-inch diameter modules also show stable performance in field tests treating raw natural gas. These findings suggest that membranes are a viable option for flue gas CO2 capture. The next step will be to conduct a field demonstration treating a realworld power plant flue gas stream. The first such MTR fieldmore » test will capture 1 ton CO2/day at Arizona Public Service’s Cholla coal-fired power plant, as part of a new DOE NETL funded program.« less

Life-cycle GHG assessment of carbon capture, use and geological storage (CCUS) for linked primary energy and electricity production

Limits to Paris compatibility of CO2 capture and utilization

Evaluating the effects of CO2 capture benchmarks on efficiency and costs of membrane systems for post-combustion capture: A parametric simulation study

Life cycle environmental impact assessment of fuel mix-based biomass co-firing plants with CO2 capture and storage

Energy-related activities are a major contributor of greenhouse gas (GHG) emissions. A growing body of knowledge clearly depicts the links between human activities and climate change. Over the last century the burning of fossil fuels such as coal and oil and other human activities has released carbon dioxide (CO2) emissions and other heat-trapping GHG emissions into the atmosphere and thus increased the concentration of atmospheric CO2 emissions. The main human activities that emit CO2 emissions are (1) the combustion of fossil fuels to generate electricity, accounting for about 37% of total U.S. CO2 emissions and 31% of total U.S. GHG emissions in 2013, (2) the combustion of fossil fuels such as gasoline and diesel to transport people and goods, accounting for about 31% of total U.S. CO2 emissions and 26% of total U.S. GHG emissions in 2013, and (3) industrial processes such as the production and consumption of minerals and chemicals, accounting for about 15% of total U.S. CO2 emissions and 12% of total ...

The topic of global warming as a result of increased atmospheric CO2 concentration is arguably the most important environmental issue that the world faces today. It is a global problem that will need to be solved on a global level. The link between anthropogenic emissions of CO2 with increased atmospheric CO2 levels and, in turn, with increased global temperatures has been well established and accepted by the world. International organizations such as the United Nations Framework Convention on Climate Change (UNFCCC) and the Intergovernmental Panel on Climate Change (IPCC) have been formed to address this issue. Three options are being explored to stabilize atmospheric levels of greenhouse gases (GHGs) and global temperatures without severely and negatively impacting standard of living: (1) increasing energy efficiency, (2) switching to less carbon-intensive sources of energy, and (3) carbon sequestration. To be successful, all three options must be used in concert. The third option is the subject of this review. Specifically, this review will cover the capture and geologic sequestration of CO2 generated from large point sources, namely fossil-fuel-fired power gasification plants. Sequestration of CO2 in geological formations is necessary to meet the President’s Global Climate Change Initiative target of an 18% reduction in GHG intensity by 2012. Further, the best strategy to stabilize the atmospheric concentration of CO2 results from a multifaceted approach where sequestration of CO2 into geological formations is combined with increased efficiency in electric power generation and utilization, increased conservation, increased use of lower carbonintensity fuels, and increased use of nuclear energy and renewables. This review covers the separation and capture of CO2 from both flue gas and fuel gas using wet scrubbing technologies, dry regenerable sorbents, membranes, cryogenics, pressure and temperature swing adsorption, and other advanced concepts. Existing commercial CO2 capture facilities at electric power-generating stations based on the use of monoethanolamine are described, as is the Rectisol process used by Dakota Gasification to separate and capture CO2 from a coal gasifier. Two technologies for storage of the captured CO2 are reviewed—sequestration in deep unmineable coalbeds with concomitant recovery of CH4 and sequestration in deep saline aquifers. Key issues for both of these techniques include estimating the potential storage capacity, the storage integrity, and the physical and chemical processes that are initiated by injecting CO2 underground. Recent studies using computer modeling as well as laboratory and field experimentation are presented here. In addition, several projects have been initiated in which CO2 is injected into a deep coal seam or saline aquifer. The current status of several such projects is discussed. Included is a commercial-scale project in which a million tons of CO2 are injected annually into an aquifer under the North Sea in Norway. The review makes the case that this can all be accomplished safely with off-the-shelf technologies. However, substantial research and development must be performed to reduce the cost, decrease the risks, and increase the safety of sequestration technologies. This review also includes discussion of possible problems related to deep injection of CO2 . There are safety concerns that need to be addressed because of the possibilities of leakage to the surface and induced seismic activity. These issues are presented along with a case study of a similar incident in the past. It is clear that monitoring and verification of storage will be a crucial part of all geological sequestration practices so that such problems may be avoided. Available techniques include direct measurement of CO2 and CH4 surface soil fluxes, the use of chemical tracers, and underground 4-D seismic monitoring. Ten new hypotheses were formulated to describe what happens when CO2 is pumped into a coal seam. These hypotheses provide significant insight into the fundamental chemical, physical, and thermodynamic phenomena that occur during coal seam sequestration of CO2 .

Conventional coal-burning power plants are major contributors of excess CO2 to the atmospheric inventory. Because such plants are stationary, they are particularly amenable to CO2 capture and disposal by deep injection into confined geologic formations. However, the energy penalty for CO2 separation and compression is steep, and could lead to a 30-40 percent reduction in useable power output. Integrated gas combined cycle (IGCC) plants are thermodynamically more efficient, i.e.,produce less CO2 for a given power output, and are more suitable for CO2 capture. Therefore, if CO2 capture and deep subsurface disposal were to be considered seriously, the preferred approach would be to build replacement IGCC plants with integrated CO2 capture, rather than retrofit existing conventional plants. Coal contains minor quantities of sulfur and nitrogen compounds, which are of concern, as their release into the atmosphere leads to the formation of urban ozone and acid rain, the destruction of stratospheric ozone, and global warming. Coal also contains many trace elements that are potentially hazardous to human health and the environment. During CO2 separation and capture, these constituents could inadvertently contaminate the separated CO2 and be co-injected. The concentrations and speciation of the co-injected contaminants would differ markedly, depending on whether CO2 is captured during the operation of a conventional or an IGCC plant, and the specific nature of the plant design and CO2 separation technology. However, regardless of plant design or separation procedures, most of the hazardous constituents effectively partition into the solid waste residue. This would lead to an approximately two order of magnitude reduction in contaminant concentration compared with that present in the coal. Potential exceptions are Hg in conventional plants, and Hg and possibly Cd, Mo and Pb in IGCC plants. CO2 capture and injection disposal could afford an opportunity to deliberately capture environmental pollutants in the gaseous state and co-inject them with the CO2, in order to mitigate problems associated with solid waste disposal in surface impoundments. Under such conditions, the injected pollutant concentrations could be roughly equivalent to their concentrations in the coal feed. The fate of the injected contaminants can only be determined through further testing and geochemical modeling. However, the concentrations of inadvertent contaminants in the injected CO2 would probably be comparable to their ambient concentrations in confining shales of the injection zone. In general, the aqueous concentrations of hazardous constituents in distal parts of the injection zone, regardless of source, are likely to be limited by equilibrium with respect to coexisting solid phases under the acid conditions induced by the dissolved high pressure CO2, rather than by the initial concentrations of injected contaminants. Therefore, even if a deliberate policy of contaminant recovery and injection were to be pursued, water quality in USDWs would more likely depend on thermodynamic controls governing aqueous contaminant concentrations in the presence of high pressure CO2 rather than in the injected CO2. The conclusions reached in this report are preliminary, and should be confirmed through more comprehensive data evaluation and supporting geochemical modeling.

▪ Abstract Increases in greenhouse gas emissions and concerns about potential global climate change are stimulating worldwide interest in the feasibility of capture, disposal, and utilization of CO2 from large energy systems. Technology to capture CO2 from power plant flue gas, while energy intensive and expensive, is commercially available. Capture from advanced combustion systems offers a further opportunity to significantly reduce cost and energy requirements of CO2 capture compared to that from today's pulverized coal power plants. No viable disposal options exist today for large quantities of captured CO2. Ocean disposal of CO2 and geological storage, especially in depleted oil and gas wells, are leading candidates. Although some niche utilization may occur, utilization seems unlikely to become a major sequestration option. Since CO2 capture and sequestration is a relatively expensive mitigation option, it can be regarded as an insurance policy. However, since CO2 mitigation options are few in number, continued research to reduce the costs of CO2 capture and to develop feasible sequestration options is important.

Even though biomass is characterised as renewable energy, it produces anthropogenic greenhouse gas (GHG) emissions, especially from biomass logistics. Lifecycle assessment (LCA) is used as a tool to quantify the GHG emissions from logistics but in the past the majority of LCAs have been steady-state and linear, when in reality, non-linear and temporal aspects (such as weather conditions, seasonal biomass demand, storage capacity, etc.) also have an important role to play. Thus, the objective of this paper was to optimise the environmental sustainability of forest biomass logistics (in terms of GHG emissions) by introducing the dynamic aspects of the supply chain and using the geographical information system (GIS) and agent-based modelling (ABM). The use of the GIS and ABM adds local conditions to the assessment in order to make the study more relevant. In this study, GIS was used to investigate biomass availability, biomass supply points and the road network around a large-scale combined heat and power plant in Naantali, Finland. Furthermore, the temporal aspects of the supply chain (e.g., seasonal biomass demand and storage capacity) were added using ABM to make the assessment dynamic. Based on the outcomes of the GIS and ABM, a gate-to-gate LCA of the forest biomass supply chain was conducted in order to calculate GHG emissions. In addition to the domestic biomass, we added imported biomass from Riga, Latvia to the fuel mixture in order to investigate the effect of sea transportation on overall GHG emissions. Finally, as a sensitivity check, we studied the real-time measurement of biomass quality and its potential impact on overall logistical GHG emissions. According to the results, biomass logistics incurred GHG emissions ranging from 2.72 to 3.46 kg CO2-eq per MWh, depending on the type of biomass and its origin. On the other hand, having 7% imported biomass in the fuel mixture resulted in a 13% increase in GHG emissions. Finally, the real-time monitoring of biomass quality helped save 2% of the GHG emissions from the overall supply chain. The incorporation of the GIS and ABM helped in assessing the environmental impacts of the forest biomass supply chain in local conditions, and the combined approach looks promising for developing LCAs that are inclusive of the temporal aspects of the supply chain for any specific location.