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AbstractCapture conditions for cement plant flue gas differ substantially from other industrial flue gases due to the high partial pressure of CO2, presenting an opportunity for polymeric membranes to compete with other capture technologies. In this work, two membrane processes are designed by applying a recently developed graphical methodology to identify promising membrane properties, number of stages and operating points for each stage. The net present values of cost and the CO2 avoidance costs are compared with an MEA based capture unit when applied to a 0.7 MtCO2/year cement plant. The membrane designs are shown to have a significantly lower investment cost (32.6 M€ vs. 294 M€) and CO2 avoidance cost (27 €/t vs 55 €/t) than the reference MEA based capture process. The investment cost for turbomachinery and the operating cost for electricity are also shown, in this particular case, to be more important than the membrane investment and replacement costs over the lifetime of the membrane capture plant. The present work underlines the importance of using a cost-based approach to balance the trade-offs in membrane process design.

We consider the feasibility of a novel Carbon Capture, Utilization and Storage (CCUS) concept that consists in producing oil and gas from hydrocarbon-rich shales overlying deep saline aquifers that are candidates for CO2 storage. Such geological overlapping between candidate aquifers for CO2 storage and shale plays exists in several sedimentary basins across the continental US. Since CO2 reaches the storage formation at a lower temperature than the in-situ temperature, a thermal stress reduction occurs, which may lead to hydraulic fracturing of the caprock overlying the aquifer. In this work, we use a thermo-hydro-mechanical approach for modelling a caprock-aquifer-baserock system. We show that hydraulic fracturing conditions are induced within the aquifer by thermal stress reduction caused by cooling and that hydraulic fractures eventually propagate into the lower portion of the shale play. Nonetheless, fracture height of penetration in the caprock is considerably short after 10 years of injection, so the overall caprock sealing capacity is maintained. To maximize the benefit of the proposed CCUS method, CO2 injection should be maintained as long as possible to promote the penetration depth of cooling-induced hydraulic fractures into organic-rich shales. Though drilling a horizontal well in the lower portion of the shale to produce hydrocarbons from the induced hydraulic fractures may not be technically feasible, hydrocarbons can still be produced through the injection well. The production of hydrocarbons at the end of the CO2 storage project will partly compensate the costs of CCS operations. © 2017 The Authors. This study was partially supported by the Louisiana Board of Regents — Research Competitiveness Subprogram (RCS) under contract #43950. V.V. acknowledges financial support from the “TRUST" project (European Community's Seventh Framework Programme FP7/2007-2013 under grant agreement n 309607) and from “FracRisk" project (European Community's Horizon 2020 Framework Programme H2020-EU.3.3.2.3 under grant agreement n 640979). Peer reviewed

AbstractCarbon dioxide capture using aqueous ammonia is a post-combustion technology that has shown a good potential. Therefore this process is studied by measuring the rate of absorption of carbon dioxide by aqueous ammonia and by performing process simulation. The rate of absorption of carbon dioxide by aqueous ammonia solvent has been studied by applying a wetted wall column apparatus. The rate of absorption is crucial regarding the sizing of the absorber columns. The overall mass transfer coefficient has been measured at temperatures from 279 to 304 K for 1 to 10 wt% ammonia solutions at loadings up to 0.6. The results were compared with those found for 30 wt% mono-ethanolamine (MEA) solutions.The capture process was simulated successfully using the simulator Aspen Plus coupled with the extended UNIQUAC thermodynamic model available for the NH3–CO2–H2O system. For this purpose, a user model interface was developed. The heat and electricity requirements were analyzed for a base case configuration, and a preliminary sensitivity analysis was performed on the heat and the electricity requirements and on the ammonia slip from the absorber.

AbstractShallow aquifer monitoring is likely to be a required aspect to any geologic CO2 sequestration operation. Collecting groundwater samples and analyzing for geochemical parameters such as pH, alkalinity, total dissolved carbon, and trace metals has been suggested by a number of authors as a possible strategy to detect CO2 leakage. The effectiveness of this approach, however, will depend on the hydrodynamics of the leak-induced CO2 plume and the spatial distribution of the monitoring wells relative to the origin of the leak. To our knowledge, the expected effectiveness of groundwater sampling to detect CO2 leakage has not yet been quantitatively assessed. In this study we query hundreds of simulations developed for the National Risk Assessment Project (US DOE) to estimate risks to drinking water resources associated with CO2 leaks. The ensemble of simulations represent transient, 3-D multi-phase reactive transport of CO2 and brine leaked from a sequestration reservoir, via a leaky wellbore, into an unconfined aquifer. Key characteristics of the aquifer, including thickness, mean permeability, background hydraulic gradient, and geostatistical measures of aquifer heterogeneity, were all considered uncertain parameters. Complex temporally-varying CO2 and brine leak rate scenarios were simulated using a heuristic scheme with ten uncertain parameters. The simulations collectively predict the spatial and temporal evolution of CO2 and brine plumes over 200 years in a shallow aquifer under a wide range of leakage scenarios and aquifer characteristics.Using spatial data from an existing network of shallow drinking water wells in the Edwards Aquifer, TX, as one illustrative example, we calculated the likelihood of leakage detection by groundwater sampling. In this monitoring example, there are 128 wells available for sampling, with a density of about 2.6 wells per square kilometer. If the location of the leak is unknown a priori, a reasonable assumption in many cases, we found that the leak would be detected in at least one of the monitoring wells in less than 10% of the scenarios considered. This is because plume sizes are relatively small, and so the probability of detection decreases rapidly with distance from the leakage point. For example, 400m away from the leakage point there is less than 20% chance of detection.We then compared the effectiveness of groundwater quality sampling to shallow aquifer and/or reservoir pressure monitoring. For the Edwards Aquifer example, pressure monitoring in the same monitoring well network was found to be even less effective that groundwater quality monitoring. This is presumably due to the unconfined conditions and relatively high permeability, so pressure perturbations quickly dissipate. Although specific results may differ from site to site, this type of analysis should be useful to site operators and regulators when selecting leak detection strategies. Given the spatial characteristics of a proposed monitoring well network, probabilities of leakage detection can be rapidly calculated using this methodology.Although conditions such as these may not be favorable for leakage detection in shallow aquifers, leakage detection could be much more successful in the injection reservoir. We demonstrate proof-of-concept for this hypothesis, presenting a simulation where there is measurable pressure change at the injection well due to overpressurization, fault rupture, and consequent leakage up the fault into intermediate and shallow aquifers. The size of the detectible pressure change footprint is much larger in the reservoir than in either of the overlying aquifers. Further exploration of the range of conditions for which this technique would be successful is the topic of current study.

AbstractThe paper describes experimental results obtained with CO2 capture from a coal fired power plant in Wilhelmshaven. After giving some basic information on the power and the pilot-scale carbon capture unit, findings on stress corrosion cracking in the Reclaimer, impact of SO3 on solvent emission and energy efficiency, which can be improved by applying lean vapour recompression. The paper highlight the learnings achieved when moving from lab scale testing to pilot scale testing.

Abstract The Area of Review is one of the most important aspects of a geologic CO 2 storage site permit application and regulatory requirement. The US Environmental Protection Agency (EPA) has implemented an Area of Review (AoR) requirement for Class VI CO 2 injection wells for geologic sequestration. Reservoir permeability is one of the most important parameters controlling AoR evolution but is generally highly heterogeneous and difficult to constrain. We have used a numerical model for Rock Springs Uplift in Wyoming as an example site to characterize how the heterogeneity in reservoir permeability affects AoR. We have performed multiple reservoir simulations using multiple, equally-likely realizations of heterogeneous permeability. We considered multiple CO 2 injection scenarios with varying injection rates as well as varying injection and post-site durations. Results of our study demonstrate that uncertainty in permeability heterogeneity can significantly influence AoR for both CO 2 saturation and pressure. In our example, the CO 2 AoR varied by as much as 2-3 times while the pressure AoR varied over 1.5 – 2 times. Such type of variability can have significant implications in defining AoR for site permit applications.

AbstractThe Gorgon Project is an LNG Project under development, located offshore of the Northwest coast of Australia. Gas supplied from offshore gas fields in the Greater Gorgon Area will be used to manufacture LNG at a facility on Barrow Island. Carbon dioxide (CO2) is present in the reservoir fluids of the Greater Gorgon Area Fields, and will be extracted from produced fluids prior to gas liquefaction into LNG. The Gorgon Joint Venture participants plan to geologically dispose of the produced reservoir CO2. The Dupuy Formation, a deep saline formation beneath Barrow Island, has been selected for disposal of Gorgon Project reservoir CO2. Subsurface evaluation of the Dupuy Formation for CO2 disposal has focused on reservoir characterisation and narrowing subsurface uncertainty ranges. A seismic pilot to assess acquisition methods and a comprehensive appraisal well have been used to reduce subsurface uncertainty. A suite of robust subsurface models have been used to gauge the impact of CO2 injection on development decisions. Key objectives for the Gorgon CO2 development include well injectivity, surveillance and containment of injected CO2 within the reservoir. A flexible development plan for CO2 disposal for the Gorgon Project has been developed to meet these objectives.