Life cycle assessment of carbon dioxide capture and storage from lignite power plants

In this article, we present a life cycle assessment (LCA) of CO₂ capture and storage (CCS) for several lignite power plant technologies. The LCA includes post-combustion, pre-combustion and oxyfuel capture processes as well as subsequent pipeline transport and storage of the separated CO₂ in a depleted gas field.The results show an increase in cumulative energy demand and a substantial decrease in greenhouse gas (GHG) emissions for all CO₂ capture approaches in comparison with power plants without CCS, assuming negligible leakage within the time horizon under consideration. Leakage will, however, not be zero. Due to the energy penalty, CCS leads to additional production of CO₂. However, the CO₂ emissions occur at a much lower rate and are significantly delayed, thus leading to different, and most likely smaller, impacts compared to the no-sequestration case. In addition, a certain share of the CO₂ will be captured permanently due to chemical reactions and physical trapping.For other environmental impact categories, the results depend strongly on the chosen technology and the details of the process. The post-combustion approach, which is closest to commercial application, leads to sharp increases in many categories of impacts, with the impacts in only one category, acidification, reduced. In comparison with a conventional power plant, the pre-combustion approach results in decreased impact in all categories. This is mainly due to the different power generation process (IGCC) which is coupled with the pre-combustion technology.In the case of the oxyfuel approach, the outcome of the LCA depends highly on two uncertain parameters: the energy demand for air separation and the feasibility of co-capture of pollutants other than CO₂. If co-capture were possible, oxyfuel could lead to a near-zero emission power plant.     

Environmental impacts of absorption-based CO2 capture unit for post-combustion treatment of flue gas from coal-fired power plant

This study assesses potential environmental impacts of the absorption-based carbon dioxide (CO₂) capture unit that is integrated to coal-fired power plant for post-combustion treatment of flue gas. The assessment was performed by identifying potential pollutants and their sources as well as amounts of emissions from the CO₂ capture unit and also by reviewing toxicology, potential implications to human health and the environment, as well as the environmental laws and regulations associated with such pollutants. The assessment shows that, while offering a significant environmental benefit through a reduction of greenhouse gas emissions, the installation of CO₂ capture units for post-combustion treatment might induce unintentional and potential burdens to human health and the environment through four emission pathways, including treated gas, process wastes, fugitive emissions, and accidental releases. Such burdens nevertheless can be predetermined and properly mitigated through a well-established environmental management program and mitigation measures. Recommendations to minimize these impacts are provided in this paper.     

Use of experience curves to estimate the future cost of power plants with CO2 capture

Given the dominance of power plant emissions of greenhouse gases, and the growing worldwide interest in CO₂ capture and storage (CCS) as a potential climate change mitigation option, the expected future cost of power plants with CO₂ capture is of significant interest. Reductions in the cost of technologies as a result of learning-by-doing, R&D investments and other factors have been observed over many decades. This study uses historical experience curves as the basis for estimating future cost trends for four types of electric power plants equipped with CO₂ capture systems: pulverized coal (PC) and natural gas combined cycle (NGCC) plants with post-combustion CO₂ capture; coal-based integrated gasification combined cycle (IGCC) plants with pre-combustion capture; and coal-fired oxyfuel combustion for new PC plants. We first assess the rates of cost reductions achieved by other energy and environmental process technologies in the past. Then, by analogy with leading capture plant designs, we estimate future cost reductions that might be achieved by power plants employing CO₂ capture. Effects of uncertainties in key parameters on projected cost reductions also are evaluated via sensitivity analysis.     

Life cycle assessment of a pulverized coal power plant with post-combustion capture, transport and storage of CO2

In this study the methodology of life cycle assessment has been used to assess the environmental impacts of three pulverized coal fired electricity supply chains with and without carbon capture and storage (CCS) on a cradle to grave basis. The chain with CCS comprises post-combustion CO₂ capture with monoethanolamine, compression, transport by pipeline and storage in a geological reservoir. The two reference chains represent sub-critical and state-of-the-art ultra supercritical pulverized coal fired electricity generation. For the three chains we have constructed a detailed greenhouse gas (GHG) balance, and disclosed environmental trade-offs and co-benefits due to CO₂ capture, transport and storage. Results show that, due to CCS, the GHG emissions per kWh are reduced substantially to 243 g/kWh. This is a reduction of 78 and 71% compared to the sub-critical and state-of-the-art power plant, respectively. The removal of CO₂ is partially offset by increased GHG emissions in up- and downstream processes, to a small extent (0.7 g/kWh) caused by the CCS infrastructure. An environmental co-benefit is expected following from the deeper reduction of hydrogen fluoride and hydrogen chloride emissions. Most notable environmental trade-offs are the increase in human toxicity, ozone layer depletion and fresh water ecotoxicity potential for which the CCS chain is outperformed by both other chains. The state-of-the-art power plant without CCS also shows a better score for the eutrophication, acidification and photochemical oxidation potential despite the deeper reduction of SO_x and NO_x in the CCS power plant. These reductions are offset by increased emissions in the life cycle due to the energy penalty and a factor five increase in NH₃ emissions.     

Effective retrofitting of post-combustion CO2 capture to coal-fired power plants and insensitivity of CO2 abatement costs to base plant efficiency

Existing coal-fired power plants were not designed to be retrofitted with carbon dioxide post-combustion capture (PCC) and have tended to be disregarded as suitable candidates for carbon capture and storage on the grounds that such a retrofit would be uneconomical. Low plant efficiency and poor performance with capture compared to new-build projects are often cited as critical barriers to capture retrofit. Steam turbine retrofit solutions are presented that can achieve effective thermodynamic integration between a post-combustion CO₂ capture plant and associated CO₂ compressors and the steam cycle of an existing retrofitted unit for a wide range of initial steam turbine designs. The relative merits of these capture retrofit integration options with respect to flexibility of the capture system and solvent upgradability will be discussed. Provided that effective capture system integration can be achieved, it can be shown that the abatement costs (or cost per tonne of CO₂ to justify capture) for retrofitting existing units is independent of the initial plant efficiency. This then means that a greater number of existing power plants are potentially suitable for successful retrofits of post-combustion capture to reduce power sector emissions. Such a wider choice of retrofit sites would also give greater scope to exploit favourable site-specific conditions for CCS, such as ready access to geological storage.     

CO2 transportation for carbon capture and storage: Sublimation of carbon dioxide from a dry ice bank

Climate change is being caused by greenhouse gases such as carbon dioxide (CO₂). Carbon capture and storage (CCS) is of interest to the scientific community as one way of achieving significant global reductions of atmospheric CO₂ emissions in the medium term. CO₂ would be captured from large stationary sources such as power plants and transported via pipelines under high pressure conditions to underground storage. If a downward leakage from a surface transportation system module occurs, the CO₂ would undergo a large temperature reduction and form a bank of “dry ice” on the ground surface; the sublimation of the gas from this bank represents an area source term for subsequent atmospheric dispersion, with an emission rate dependent on the energy balance at the bank surface. Gaseous CO₂ is denser than air and tends to remain close to the surface; it is an asphyxiant, a cerebral vasodilator and at high concentrations causes rapid circulatory insufficiency leading to coma and death. Hence a subliming bank of dry ice represents safety hazard. A model is presented for evaluating the energy balance and sublimation rate at the surface of a solid frozen CO₂ bank under different environmental conditions. The results suggest that subliming gas behaves as a proper dense gas (i.e. it remains close to the ground surface) only for low ambient wind speeds.     

Integration of CO2 capture unit using single- and blended-amines into supercritical coal-fired power plants: Implications for emission and energy management

This work provides the essential information and approaches for integration of carbon dioxide (CO₂) capture units into power plants, particularly the supercritical type, so that energy utilization and CO₂ emissions can be well managed in the subject power plants. An in-house model, developed at the University of Regina, Canada, was successfully used for simulating a 500 MW supercritical coal-fired power plant with a post-combustion CO₂ capture unit. The simulations enabled sensitivity and parametric study of the net efficiency of the power plant, the coal consumption rate, and the amounts of CO₂ captured and avoided. The parameters of interest include CO₂ capture efficiency, type of coal, flue gas delivery scheme, type of amine used in the capture unit, and steam pressure supplied to the capture unit for solvent regeneration. The results show that the advancement of MEA-based CO₂ capture units through uses of blended monoethanolamine–methyldiethanolamine (MEA–MDEA) and split flow configuration can potentially make the integration of power plant and CO₂ capture unit less energy intensive. Despite the increase in energy penalty, it may be worth capturing CO₂ at a higher efficiency to achieve greater CO₂ emissions avoided. The flue gas delivery scheme and the steam pressure drawn from the power plant to the CO₂ capture unit should be considered for process integration.     

Derivation of correlations to evaluate the impact of retrofitted post-combustion CO2 capture processes on steam power plant performance

When integrating a post-combustion CO₂ capture process and CO₂ compression into a steam power plant, the three interface quantities heat, electricity and cooling duty must be satisfied by the power plant, leading to a loss in net efficiency. The heat duty shows to be the largest contributor to the overall net efficiency penalty of the power plant. Additional energy penalty results from the cooling and electric power duty of the capture and compression units.In this work, the dependency of the energy penalty on the quantity and quality of the heat duty is analyzed and quantified for a state-of-the-art hard coal fired power plant. Furthermore, the energy penalty attributed to the additional cooling and power duty is quantified. As a result correlations are provided which enable to predict the impact of the heat, cooling and electricity duty of post-combustion CO₂ capture processes on the net output of a steam power plant in a holistic approach.     

Electric Swing Adsorption for CO2 removal from flue gases

One of the most important sources of CO₂ emissions are the fossil-fuel fired plants for production of electricity. Removal of CO₂ from flue gas streams for further sequestration has been proposed by the International Panel on Climate Change experts as one of the most reliable solutions to mitigate anthropogenic greenhouse emissions. When natural gas is employed as fuel, the molar fraction of CO₂ in the flue gas is lower than 5% causing serious problems for capture. The purpose of this work is to present experimental validation of an Electric Swing Adsorption (ESA) technology that may be employed for carbon capture for low molar fractions of CO₂ in the flue gas streams. To improve energy utilization, an activated carbon honeycomb monolith with low electrical resistivity was employed as selective adsorbent. A mathematical model for this honeycomb is proposed as well as different ESA cycles for CO₂ capture.     

Electricity systems with near-zero emissions of CO2 based on wind energy and coal gasification with CCS and hydrogen storage

Emissions from electricity generation will have to be reduced to near-zero to meet targets for reducing overall greenhouse gas emissions. Variable renewable energy sources such as wind will help to achieve this goal but they will have to be used in conjunction with other flexible power plants with low-CO₂ emissions. A process which would be well suited to this role would be coal gasification hydrogen production with CCS, underground buffer storage of hydrogen and independent gas turbine power generation. The gasification hydrogen production and CO₂ capture and storage equipment could operate at full load and only the power plants would need to operate flexibly and at low load, which would result in substantial practical and economic advantages. This paper analyses the performances and costs of such plants in scenarios with various amounts of wind generation, based on data for power demand and wind energy variability in the UK. In a scenario with 35% wind generation, overall emissions of CO₂ could be reduced by 98–99%. The cost of abating CO₂ emissions from the non-wind residual generation using the technique proposed in this paper would be less than 40% of the cost of using coal-fired power plants with integrated CCS.     

A novel process integration,optimization and design approach for large-scale implementation of oxy-fired coal power plants with CO2 capture

The widespread use of fossil fuels within the current energy infrastructure is considered as the largest source of anthropogenic emissions of carbon dioxide, which is largely blamed for global warming and climate change. At the current state of development, the risks and costs of non-fossil energy alternatives, such as nuclear, biomass, solar, and wind energy, are so high that they cannot replace the entire share of fossil fuels in the near future timeframe. Additionally, any rapid change towards non-fossil energy sources, even if possible, would result in large disruptions to the existing energy supply infrastructure. As an alternative, the existing and new fossil fuel-based plants can be modified or designed to be either “capture” or “capture-ready” plants in order to reduce their emission intensity through the capture and permanent storage of carbon dioxide in geological formations. This would give the coal-fired power generation units the option to sustain their operations for longer time, while meeting the stringent environmental regulations on air pollutants and carbon emissions in years to come.Currently, there are three main approaches to capturing CO₂ from the combustion of fossil fuels, namely, pre-combustion capture, post-combustion capture, and oxy-fuel combustion. Among these technology options, oxy-fuel combustion provides an elegant approach to CO₂ capture. In this approach, by replacing air with oxygen in the combustion process, a CO₂-rich flue gas stream is produced that can be readily compressed for pipeline transport and storage. In this paper, we propose a new approach that allows air to be partially used in the oxy-fired coal power plants. In this novel approach, the air can be used to carry the coal from the mills to the boiler (similar to the conventional air-fired coal power plants), while O₂ is added to the secondary recycle flow as well as directly to the combustion zone (if needed). From a practical point of view, this approach eliminates problems with the primary recycle and also lessens concerns about the air leakage into the system. At the same time, it allows the boiler and its back-end piping to operate under slight suction; this avoids the potential danger to the plant operators and equipment due to possible exposure to hot combustion gases, CO₂ and particulates. As well, by integrating oxy-fuel system components and optimizing the overall process over a wide range of operating conditions, an optimum or near-optimum design can be achieved that is both cost-effective and practical for large-scale implementation of oxy-fired coal power plants.     

CO2 capture for refineries,a practical approach

This paper evaluates the opportunities and associated costs for post-combustion capture at a world-scale complex refinery. It is concluded that it is technically feasible to apply post-combustion capture at such a refinery. The costs for capture and sequestration from a gasifier are calculated to be lowest at about 30 Euro per ton; this process currently already produces a concentrated CO₂ stream. Next, the CO₂ source most suited for capture appears to be a combined stack, but there are a number of other sources that may be targeted at comparable costs. In total these sources may form about 40% of the overall refinery emissions. Our evaluations show the costs of capture from such sources based on available amine technology will be in the range of 90–120 Euro per ton, which is about 3–4 times higher than the current carbon trading values. The capture of CO₂ from a large amount of smaller CO₂ sources will bring along even much higher costs. A high-level study of the CO₂ emissions profile of a number of Shell refineries shows that, typically, up to 50% of the emitted CO₂ may be captured at similar costs. About 10–20% of concentrated CO₂ associated with hydrogen manufacturing may be captured at lower costs. The remainder of emitted dilute CO₂ will bring along significantly higher costs. Based on this study, it is concluded for the justification of the implementation of post-combustion capture at refineries, either a significant increase in carbon trading values, mandatory regulations, or a major technological break-through is required.     

Maintaining a neutral water balance in a 450 MWe NGCC-CCS power system with post-combustion carbon dioxide capture aimed at offshore operation

A post-combustion CO₂ capture process intended for offshore operations has been designed and optimised for integration with a natural gas-fired power plant on board a floating structure developed by the Norway-based company Sevan Marine ASA—designated Sevan GTW (gas-to-wire). The concept is constrained by the structure of the floater carrying a SIEMENS modular power system rated at 450 MW_e, with a capture rate of 90% and CO₂ compression (1.47 Mtpa) for pipeline pressure at 12 MPa. A net efficiency of 45% (based on a lower heating value) is estimated for the system with CO₂ capture, thus suggesting that the post-combustion CO₂ capture system is accountable for a fuel penalty of nine percentage points.The rationale behind the technology selection is the urgency of replacing the dispersed aero-derivative gas turbines which power the offshore oil and gas production units in Norwegian waters with near-zero emission power.As (inherently) fresh water usually constitutes a limiting factor in sea operations, efforts are made to obtain a neutral water balance to obtain an optimal design. This is primarily achieved by controlling the cleaned flue gas temperature at the top of the absorber column.     

Oxy-fuel coal combustion—A review of the current state-of-the-art

Carbon dioxide emissions will continue being a major environmental concern due to the fact that coal will remain a major fossil-fuel energy resource for the next few decades. To meet future targets for the reduction of greenhouse gas (GHG) emissions, capture and storage of CO₂ is required. Carbon capture and storage technologies that are currently the focus of research centres and industry include: pre-combustion capture, post-combustion capture, and oxy-fuel combustion. This review deals with the oxy-fuel coal combustion process, primarily focusing on pulverised coal (PC) combustion, and its related research and development topics. In addition, research results related to oxy-fuel combustion in a circulating fluidised bed (CFB) will be briefly dealt with.During oxy-fuel combustion, a combination of oxygen, with a purity of more than 95 vol.%, and recycled flue gas (RFG) referred to as oxidant is used for combusting the fuel producing a gas consisting of mainly CO₂ and water vapour, which after purification and compression, is ready for storage. The high oxygen demand is supplied by a cryogenic air separation process, which is the only commercially available mature technology. The separation of oxygen from air as well as the purification and liquefaction of the CO₂-enriched flue gas consumes significant auxiliary power. Therefore, the overall net efficiency is expected to be decreased by 8–12% points, corresponding to a 21–35% increase in fuel consumption. Alternatively, ion transport membranes (ITMs) are proposed for oxygen separation, which might be more energy efficient. However, since ITMs are far away from becoming a mature technology, it is widely expected that cryogenic air separation will be the selected technology in the near future. Oxygen combustion is associated with higher temperatures compared with conventional air combustion. Both fuel properties as well as limitations of steam and metal temperatures of the various heat exchanger sections of the boiler require a moderation of the temperatures in the combustion zone and in the heat-transfer sections. This moderation in temperature is accomplished by means of recycled flue gas. The interdependencies between the fuel properties, the amount and temperature of the recycled flue gas, and the resulting oxygen concentration in the combustion atmosphere are reviewed.The different gas atmosphere resulting from oxy-fuel combustion gives rise to various questions related to firing, in particular, with respect to the combustion mechanism, pollutant reduction, the risk of corrosion, and the properties of the fly ash or its resulting deposits. In this review, detailed nitrogen and sulphur chemistry was investigated in a laboratory-scale facility under oxy-fuel combustion conditions. Oxidant staging succeeded in reducing NO formation with effectiveness comparable to that typically observed in conventional air combustion. With regard to sulphur, a considerable increase in the SO₂ concentration was measured, as expected. However, the H₂S concentration in the combustion atmosphere in the near-flame zone increased as well. Further results were obtained in a pilot-scale test facility, whereby acid dew points were measured and deposition probes were exposed to the combustion environment. Slagging, fouling and corrosion issues have so far been addressed via short-term exposure and require further investigation.Modelling of PC combustion processes by computational fluid dynamics (CFD) has become state-of-the-art for conventional air combustion. Nevertheless, the application of these models for oxy-fuel combustion conditions needs adaptation since the combustion chemistry and radiative heat transfer is altered due to the different combustion gas atmosphere.CFB technology can be considered mature for conventional air combustion. In addition to its inherent advantages like good environmental performance and fuel flexibility, it offers the possibility of additional heat exchanger arrangements in the solid recirculation system, i.e. the ability to control combustion temperatures despite relatively low flue gas recycle ratios even when combusting in the presence of high oxygen concentrations.     

Exploring the potential for improvement of the energy performance of coal fired power plants with post-combustion capture of carbon dioxide

The application of post-combustion capture (PCC) processes in coal fired power stations can result in large reductions of the CO₂-emissions, but the consequential decrease in generation efficiency is an important draw-back. The leading PCC technology is based on chemical absorption processes as this technology is the one whose scale-up status is closest to full-scale capture in power plants. The energy performance of this process is analysed in this contribution. The analysis shows that the potential for improvement of the energy performance is quite large. It is demonstrated that further development of the capture technology and the power plant technology can lead to generation efficiencies for power plants with 90% CO₂ capture which are equivalent to the current generation efficiencies without CO₂ capture, i.e. 0.4 (HHV), leading to an additional resource consumption of 16%. These improvements are possible throughout a combined improvement for the capture process and power generation processes.     

Intermediate storage of carbon dioxide in geological formations: A technical perspective

Enhanced oil recovery (EOR) through CO₂ flooding has been practiced on a commercial basis for the last 35 years and continues today at several sites, currently injecting in total over 30 million tons of CO₂ annually. This practice is currently exclusively for economic gain, but can potentially contribute to the reduction of emissions of greenhouse gases provided it is implemented on a large scale. Optimal operations in distributing CO₂ to CO₂-EOR or enhanced gas recovery (EGR) projects (referred to here collectively as CO₂-EHR) on a large scale and long time span imply that intermediate storage of CO₂ in geological formations may be a key component. Intermediate storage is defined as the storage of CO₂ in geological media for a limited time span such that the CO₂ can be sufficiently reproduced for later use in CO₂-EHR. This paper investigates the technical aspects, key individual parameters and possibilities of intermediate storage of CO₂ in geological formations aiming at large scale implementation of carbon dioxide capture and storage (CCS) for deep emission reduction. The main parameters are thus the depth of injection and density, CO₂ flow and transport processes, storage mechanisms, reservoir heterogeneity, the presence of impurities, the type of the reservoirs and the duration of intermediate storage. Structural traps with no flow of formation water combined with proper injection planning such as gas-phase injection favour intermediate storage in deep saline aquifers. In depleted oil and gas fields, high permeability, homogeneous reservoirs with structural traps (e.g. anticlinal structures) are good candidates for intermediate CO₂ storage. Intuitively, depleted natural gas reservoirs can be potential candidates for intermediate storage of carbon dioxide due to similarity in storage characteristics.     

Quantitative evaluation of the chilled-ammonia process for CO2 capture using thermodynamic analysis and process simulation

There is strong world-wide interest in developing new and improved processes for post-combustion capture of CO₂, often using chemical absorption. Developers of new processes make positive claims for their proposals in terms of low energy consumption, but these are usually difficult to validate. This paper demonstrates that rigorous application of thermodynamic analysis and process simulation provides a powerful way to quantitatively estimate the energy requirements of CO₂-capture processes by applying the methodology to the analysis and evaluation of the chilled-ammonia process.     

Integration of post-combustion capture and storage into a pulverized coal-fired power plant

Post-combustion CO₂ capture and storage (CCS) presents a promising strategy to capture, compress, transport and store CO₂ from a high volume–low pressure flue gas stream emitted from a fossil fuel-fired power plant. This work undertakes the simulation of CO₂ capture and compression integration into an 800 MW_e supercritical coal-fired power plant using chemical process simulators. The focus is not only on the simulation of full load of flue gas stream into the CO₂ capture and compression, but also, on the impact of a partial load. The result reveals that the energy penalty of a low capture efficiency, for example, at 50% capture efficiency with 10% flue gas load is higher than for 90% flue gas load at the equivalent capture efficiency by about 440 kWh_e/tonne CO₂. The study also addresses the effect of CO₂ capture performance by different coal ranks. It is found that lignite pulverized coal (PC)-fired power plant has a higher energy requirement than subbituminous and bituminous PC-fired power plants by 40.1 and 98.6 MW_e, respectively. In addition to the investigation of energy requirement, other significant parameters including energy penalty, plant efficiency, amine flow rate and extracted steam flow rate, are also presented. The study reveals that operating at partial load, for example at half load with 90% CO₂ capture efficiency, as compared with full load, reduces the energy penalty, plant efficiency drop, amine flow rate and extracted steam flow rate by 9.9%, 24.4%, 50.0% and 49.9%, respectively. In addition, the effect of steam extracted from different locations from a series of steam turbine with the objective to achieve the lowest possible energy penalty is evaluated. The simulation shows that a low extracted steam pressure from a series of steam turbines, for example at 300 kPa, minimizes the energy penalty by up to 25.3%.     

Life cycle assessment of natural gas combined cycle power plant with post-combustion carbon capture,transport and storage

Hybrid life cycle assessment has been used to assess the environmental impacts of natural gas combined cycle (NGCC) electricity generation with carbon dioxide capture and storage (CCS). The CCS chain modeled in this study consists of carbon dioxide (CO₂) capture from flue gas using monoethanolamine (MEA), pipeline transport and storage in a saline aquifer.Results show that the sequestration of 90% CO₂ from the flue gas results in avoiding 70% of CO₂ emissions to the atmosphere per kWh and reduces global warming potential (GWP) by 64%. Calculation of other environmental impacts shows the trade-offs: an increase of 43% in acidification, 35% in eutrophication, and 120–170% in various toxicity impacts. Given the assumptions employed in this analysis, emissions of MEA and formaldehyde during capture process and generation of reclaimer wastes contributes to various toxicity potentials and cause many-fold increase in the on-site direct freshwater ecotoxicity and terrestrial ecotoxicity impacts. NO_x from fuel combustion is still the dominant contributor to most direct impacts, other than toxicity potentials and GWP. It is found that the direct emission of MEA contribute little to human toxicity (HT < 1%), however it makes 16% of terrestrial ecotoxicity impact. Hazardous reclaimer waste causes significant freshwater and marine ecotoxicity impacts. Most increases in impact are due to increased fuel requirements or increased investments and operating inputs.The reductions in GWP range from 58% to 68% for the worst-case to best-case CCS system. Acidification, eutrophication and toxicity potentials show an even large range of variation in the sensitivity analysis. Decreases in energy use and solvent degradation will significantly reduce the impact in all categories.     

Near-surface monitoring for the ZERT shallow CO2 injection project

As part of a collaborative effort operated by the Zero Emission Research and Technology Center (ZERT), a series of two shallow releases of CO₂ was performed at a test site in Bozeman, MT. The purpose of the experiment was to simulate possible leakage scenarios from a carbon capture and storage operation in order to further develop and verify monitoring technologies used to characterize and quantify the release of CO₂. The project included collaboration with several research groups and organizations. Presented here are the results of soil–gas monitoring conducted by researchers from the National Energy Technology Laboratory, including CO₂ flux measurement, soil–gas analysis, perfluorocarbon tracer monitoring, and soil resistivity measurements. Together, these methods proved to be effective in detecting and characterizing leakage in the near-surface.