New polyalkylated imidazoles tailored for carbon dioxide capture Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-07-14 Sigvart Evjen, Anne Fiksdahl, Diego D.D. Pinto, Hanna K. Knuutila
Aqueous polyalkylated imidazoles have gained interest as potential CO2 capture solvents due to their high oxidative stability and low vapor pressures compared to traditional amines. In this work, 21 aqueous solutions of polyalkylatedimidazoles were screened as absorbents for CO2 capture and four solvent candidates were further characterized by measuring the vapor-liquid equilibria and the heat of absorption of CO2. The pKa values of the imidazoles were measured and a positive correlation between the absorption capacity and pKa of polyalkylated imidazoles was found. Increasing the pKa of imidazoles to 9 by alkylation improved the CO2 absorption capacity significantly. Based on the equilibrium experiments, the cyclic capacities of the selected solvents varied from 0.8 to 2 mol CO2/kg solvent. Furthermore, the heat of absorption of CO2 of the studied imidazoles was lower compared to primary amines. In general, the tested polyalkylated imidazoles are more feasible for processes with partial pressures of CO2 above 50 kPa. Trimethylimidazole that forms bicarbonate precipitate might be applicable for post combustion CO2 capture as a high cyclic capacity is obtained even at CO2 partial pressures around 10 kPa. The present study gives new important knowledge of the absorption properties of polyalkylated imidazoles.
Seismic amplitude analysis provides new insights into CO2 plume morphology at the Snøhvit CO2 injection operation Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-07-13 James C. White, Gareth Williams, Andy Chadwick
CO2 has been injected at the Snøhvit Field since 2008, with the storage operation split between two distinct injection phases. Until 2011, CO2 was sequestered in the deeper Tubåen Formation before problems with increasing pressure necessitated moving the injection to the overlying Stø Formation.A comprehensive time-lapse seismic monitoring programme has been undertaken over the injection site throughout this period. Uniquely, this study examines four separate seismic vintages starting with the 2003 baseline data and ending with the 2012 repeat survey. The 3D seismic reflection data reveal the seismic character of the anomalies imaged in the Tubåen and Stø Formations to be dissimilar. Time domain analysis and spectral decomposition are used to investigate the CO2 plume morphology in both cases.The seismic response during the initial phase is complex, showing contributions from both fluid and pressure changes. The majority of the reflectivity is ascribed to a build-up of pore-water pressure in the wider reservoir. Seismic analysis of the second phase reveals a simpler distribution, consistent with a conical plume formed by buoyancy-driven upward advection of CO2. The thickness of the spreading layer is calculated, and a maximum temporal thickness of 22 ms is derived from both time and frequency analysis. Direct comparison of the two methodologies reveals good agreement over the central parts of the layer where spectral techniques are applicable. Results are then used to determine the total mass of CO2 in the Stø Formation as 0.51 million tonnes. This is consistent with the true injected mass of 0.55 million tonnes.
Life cycle assessment of hydrogen production via iron-based chemical-looping process using non-aqueous phase bio-oil as fuel Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-06-28 Lijun Heng, Rui Xiao, Huiyan Zhang
This study is conducted to quantify the fossil energy input (FEI) and the global warming potential (GWP) of hydrogen production through iron-based chemical-looping process with CO2 capture using non-aqueous phase bio-oil (NAPB) from biomass fast pyrolysis as fuel. The eBalance software with Chinese Life Cycle Database is employed to implement this work based on the method of life cycle assessment (LCA). The LCA results indicate NAPB production consumes the largest fossil energy and contributes the largest GWP while chemical-looping hydrogen production (CLHP) plays a critical role in lessening greenhouse gas (GHG) emission. The net FEI and the net GWP of hydrogen production is, respectively, 0.597 MJ and −0.0767 kg CO2, eq. per MJ hydrogen gas via the proposed production pathway, far below those of the conventional hydrogen production via natural gas steam reforming and coal gasification. The sensitivity analysis shows the data uncertainty of the discussed parameters except the electricity consumption for NAPB production has no significant impact on the net GWP. The chemical-looping process with CO2 capture may be a more promising option to sustainably produce hydrogen gas especially using renewable biomass as fuel.
Review of reactor for chemical looping combustion of solid fuels Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-06-30 Tao Song, Laihong Shen
Chemical Looping Combustion (CLC) is one of the important techniques used to combine fuel combustion and almost pure CO2 production. Significant progress has been made with respect to the utilization of solid fuels in CLC in the last ten years. The key technical challenges of using solid fuels in CLC involve several aspects: reducing unburnt volatiles and gasification products escaping out of fuel reactor, enhancing solid fuel conversion in fuel reactor and minimizing char slip to air reactor, and ash handling. These aspects are closely related to reaction kinetics of oxygen carriers in particulate systems as well as the design and operation of CLC reactors which are widely accepted as interconnected fluidized beds. In this study, an overview of reactor of CLC using solid fuels is given. Detailed descriptions of the bed types and configurations of air reactor, fuel reactor and carbon stripper are illustrated in industrial scale. The available operating experience in the fields of energy and chemical engineering such as deciding solid fuel feeding position and bed internals is demonstrated to address the existing operational problems.
CO2-induced release of copper and zinc from model soil in water Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-07-10 Christos D. Tsakiroglou, Katerina Terzi, Christos Aggelopoulos, Maria Theodoropoulou
The eventual leakage of CO2 from storage sites into shallow aquifers may degrade the quality of potable groundwater, due to acidification caused by the intrusion of gas CO2. Experiments in continuous-stirred tank reactors (CSTRs) seems to be a fast and cost-effective way to quantify the kinetics of heavy metal release from soil material to groundwater. The goal of the present work is to evaluate the capability of a model to provide reliable values for the kinetic parameters of metal release from CSTR tests with reference to results from soil column and batch tests. Well-sorted silica sand is used as model soil with its composition being modified with the pH-controlled precipitation of Cu or Zn. Gas CO2 is dissolved in distilled water, and the carbonated water is fed at constant flow rate in a CSTR containing soil grains suspended in water. The concentration of dissolved metals in effluents is measured with atomic absorption spectroscopy (AAS). A dynamic mathematical model of the operation of CSTRs is developed by regarding the metal release as a pH-controlled two-site adsorption/desorption process. A sensitivity analysis is done, and the kinetic parameters of the sorption model are estimated, separately for each metal, with inverse modeling of the transient response of metal concentration in CSTR. In addition, the model validity is assessed by comparing the transient response of pH and redox potential with numerical predictions. In general, a significant uncertainty is embedded in estimated parameters of the 2-site sorption model. Compared to the corresponding kinetic parameter values estimated from soil column and batch tests, any differences should be interpreted in the light of the different experimental conditions and assumptions.
Both carbamates and monoalkyl carbonates are involved in carbon dioxide capture by alkanolamines Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-07-08 Zuzana Cieslarova, Vagner Bezerra dos Santos, Claudimir Lucio do Lago
Among the amines that have been systematically applied for CO2 capture, several alkanolamines have been proved to be very effective. Although the formation of carbamates – the reaction product of CO2 and the amine group – is recognized as the most important process, the behavior of a tertiary alkanolamine cannot be explained, because a carbamate cannot be formed. In such a case, the formation of a monoalkyl carbonate (MAC) – a hemiester of carbonic acid and the alcohol group of the alkanolamine – is the most important process. In the present study, we demonstrate that the MAC is formed not only for tertiary alkanolamines, but also for the simpler ones, and that this reaction takes place even in aqueous medium. The species were detected by 13C NMR, which allowed the estimation of the formation constant of MACs for choline, triethanolamine, diethanolamine, and monoethanolamine as 0.44, 2.6, 0.72, and 0.66, respectively. These values are similar to those ones for MACs of aliphatic alcohols and sugars. Although the formation constants are much higher for carbamates, MAC formation becomes a more significant process as the pH is lowered during CO2 capture. A brief review of previous works demonstrated that MACs could be detected in other experiments whether the authors would aware of this class of compounds.
Toward an adaptive monitoring design for leakage risk – Closing the loop of monitoring and modeling Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-07-07 Ya-Mei Yang, Robert M. Dilmore, Grant S. Bromhal, Mitchell J. Small
Monitoring is a key component of risk management at geologic carbon storage (GCS) sites, serving both to help operators understand and manage site performance, and to assure the public and other stakeholders that effective containment is maintained and impacts avoided. Potential leakage of CO2 and/or brine through wellbores, faults, and fractures to potable groundwater resources is a primary risk concern at onshore GCS sites. In this paper, we present an adaptive methodology for leakage risk-based monitoring design. The methodology uses a risk event tree to predict the likelihood of leakage occurrence, with detection probabilities of risk events estimated for multiple monitoring plans. The overall detection probability of a proposed monitoring plan incorporates baseline data, stochastically simulated leakage events, and the likelihood that a set of technologies will detect the changes in baseline conditions induced by the simulated leakage events. The adaptive monitoring design methodology is demonstrated with a representative case study of CO2 and brine leaking from a well to a potable groundwater aquifer using simulated data at the High Plains aquifer in the United States. Groundwater quality parameters, pH, total dissolved solids and benzene concentrations, were used to calculate the corresponding detection probabilities of conventional groundwater sampling and fixed sensor monitoring for selected leakage scenarios. The overall detection probability considering all monitoring information was then calculated to evaluate proposed monitoring plan designs. Finally, a simple optimization problem to maximize detection probability with constrained monitoring resources was presented as an application example to close the loop of monitoring and modeling.
Investment costs and CO2 reduction potential of carbon capture from industrial plants – A Swedish case study Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-07-06 Stefanía Ósk Garðarsdóttir, Fredrik Normann, Ragnhild Skagestad, Filip Johnsson
In this work, the investment required to apply CO2 capture to large-scale industrial sources is assessed and discussed in a case study of Sweden - a highly industrialized region with relative proximity to large and well-documented storage sites in the Norwegian North Sea. The Swedish process industry is characterized by a large share of biogenic emissions, and therefore has a considerable Bio-Energy with Carbon Capture and Storage (BECCS) potential. The capital cost for CO2 capture is estimated for a standard MEA-based CO2 absorption process. The CO2 absorption process is applied to several industries – pulp and paper, oil and gas, steel, cement and chemical production – and dimensioned using process modeling. The equipment cost is subsequently estimated using a detailed individual factor estimation method. The capture costs are compared to estimates of the cost for transport and storage.
The potential for implementation of Negative Emission Technologies in Scotland Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-06-30 Juan Alcalde, Pete Smith, R. Stuart Haszeldine, Clare E. Bond
The reduction of anthropogenic greenhouse gas emission rates alone appears insufficient to limit the rise in global temperatures. Negative Emission Technologies (NETs) can be helpful in this critical goal by actively removing CO2 from the atmosphere. Industrialised countries like Scotland will require NETs to address their climate targets and reach net-zero carbon emissions in a timely manner. However, the implementation of NETs has varied energy, economic and environmental implications that need to be analysed in detail. In this paper, we explore the potential energy and economic costs for implementation of land-based NETs in Scotland. This analysis is based on the calculated averaged costs of the different technologies and the availability of resources for its implementation in Scotland. We found that the country has a maximum technical potential to abate 90–100% of its annual CO2 emissions by means of land-based NETs, thanks to its low annual emissions and large land area for implementation of NETs. Even in less optimistic scenarios, Scotland is exceptionally well suited for land NETs, which can complement and enhance the potential of more conventional technologies, like renewable energy resources. Our results show that Scotland could lead the transformation towards a carbon-neutral society.
Improving the energy cost of an absorber-stripper CO2 capture process through economic model predictive control Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-07-10 Lester Lik Teck Chan, Junghui Chen
Carbon dioxide (CO2) is the major source of greenhouse gas and its capture and recovery is the key to effective reduction of CO2 emissions. Optimization of the CO2 capture process plays a critical role in the reduction of energy cost. The current strategy only deals with the steady state optimization of the CO2 capture process but the CO2 concentration in the plant varies with time and as a result a dynamic study of the economic assessment will reflect the true cost better. The economic model predictive control (EMPC) that combines real-time economic process optimization and feedback control is applied to the optimization of CO2 capture process. The large energy requirement for solvent regeneration is optimized in dynamic settings. Unlike the conventional steady state consideration of the economic performance assessment, the proposed method allows the cost to be adjusted to the volatile market conditions that varies rapidly. Case studies are then presented to show the benefits of the EMPC optimization for CO2 capture process.
Implications of fault structure heterogeneities, dissolution and capillary trapping mechanisms for CO2 storage integrity Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-06-28 Muhammad Zulqarnain, Mehdi Zeidouni, Richard G. Hughes
Estimation of faults leakage potential is an essential component of CO2 storage integrity analysis. The selection of deep saline aquifers for CO2 storage in these settings mandates the modeling of fault-related fluid flow to estimate the most probable leakage rates. Faults usually have complex structures with heterogeneities and anisotropies over a range of scales because of which local capillary trapping becomes significantly important. We quantitatively investigate the implications of local capillary trapping for storage integrity and monitoring. Reservoir simulation results for a representative normal fault in a potential storage site in southern Louisiana with three possible damage zone configurations of homogenous, heterogeneous with fragmented core, and heterogeneous with intact core are presented. For each configuration, three cases are modeled to study the sensitivity of dissolution and local capillary trapping. Our results show that dissolution and local capillary trapping impede the upward migration of CO2, and may reduce leaked volume by more than 19% in some of the cases. It is also noted that presence of high permeability connected streaks may lessen the positive contributions of dissolution and local capillary trapping in reducing CO2 leakage. Moreover, capillary trapping significantly alters the pressure and saturation gradients locally and it may complicate monitoring strategies if extrapolation is required over larger length scales.
Modeling of time-lapse seismic monitoring using CO2 leakage simulations for a model CO2 storage site with realistic geology: Application in assessment of early leak-detection capabilities Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-06-28 Zan Wang, William P. Harbert, Robert M. Dilmore, Lianjie Huang
Time-lapse surface seismic surveys have been widely used at carbon sequestration sites for site characterization, monitoring subsurface CO2 plume migration, and detecting potential CO2 leakage from a storage reservoir. Monitoring in the first permeable unit directly above the primary seal is important for early detection of CO2 leakage. Forward modeling of time-lapse seismic data can be used to assess the utility of the seismic method for CO2 leakage detection. We develop a workflow for forward modeling of time-lapse seismic data, including constructing seismic velocity models using flow simulation outputs, modeling of pre-stack and post-stack synthetic seismic data following seismic data processing sequence and analysis of processed synthetic time-lapse seismic data. We apply the forward modeling and analysis workflow to assessing the detectability and the earliest detection time of seismic monitoring using the hypothetical CO2 leakage scenarios for a model geologic storage site with realistic geology. We derive the detection thresholds using the simulated normalized root-mean-square (NRMS) differences for the no-leakage case at a range of signal-to-noise ratios, representing the background noise levels in seismic data. We then compare NRMS differences triggered by the CO2 leakage to the detection thresholds at each time step to quantify the detectability and the earliest detection time of seismic monitoring. We analyze the effects of the acquisition parameters and elastic parameters on the produced synthetic seismic data and earliest detection time. Our modeling results indicate that high signal-to-noise ratio is needed to detect the CO2 leakage at the model site. Minimizing the background noise in seismic data is crucial for improving the detectability of the seismic method. Increasing the shot density or increasing the dominant frequency of the source wavelet is likely to increase the possibility of the leakage detection and reduce the time needed for the detection. The elastic parameters used in the rock physics modeling have significant effects on the resultant seismic velocity models and synthetic seismic data, highlighting their critical roles in understanding and interpreting time-lapse seismic reflection data associated with CO2 monitoring, verification and accounting activities.
Structure, stability, and storage capacity of CO2+N2O mixed hydrates for the storage of CO2+N2O mixture gas Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-06-27 Daeseung Kyung, Woojin Lee
Numerical estimations of storage efficiency for the prospective CO2 storage resource of shales Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-06-24 Evgeniy M. Myshakin, Harpreet Singh, Sean Sanguinito, Grant Bromhal, Angela L. Goodman
Hydrocarbon-bearing shale formations might be an attractive geologic reservoir for permanent carbon dioxide (CO2) storage. Shale formations applicable for storage require previous hydrocarbon production to deplete a reservoir, hydraulic fracturing to provide a highly-permeable stimulated zone, sufficient depths (generally > 800 m or 2600 feet) to maintain CO2 in a supercritical state, and an overlying seal to prevent CO2 migration to underground sources of drinking water and into the atmosphere. CO2 is stored in shale as a free phase within fractures and matrix pores, and as a sorbed phase on organic matter and clay minerals. Recently in our previous work, we presented a screening-level assessment methodology for CO2 storage in shales using a volumetric approach. The approach deals with reduction of CO2 storage through estimations of efficiency factors based on petrophysical properties (i.e., bulk volume, porosity, sorption, etc.) and their limitations on fluid transport. Here, we conducted numerical simulations using the FRACGEN/NFFLOW simulator to study the CO2 injection into a depleted hydro-fractured shale reservoir to estimate storage efficiencies using a range of reservoir parameters and injection scenarios. Specifically, the ranges for two efficiency factors, E ϕ and E S , measure the effectiveness of free and sorbed CO2 storage. These efficiency factors were estimated to have P10 to P90 probability ranges of 0.15 to 0.36 for E ϕ and 0.11 to 0.24 for E S , reported after 60 years of CO2 injection.
Numerical study of CO2-enhanced coalbed methane recovery Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-06-22 Yongpeng Fan, Cunbao Deng, Xun Zhang, Fengqi Li, Xinyang Wang, Ling Qiao
Although CO2-enhanced coalbed methane (CO2-ECBM) recovery has been comprehensively investigated, fewer scholars have taken the effect of temperature into account, which brought a large deviation for the study of the influence of CO2-ECBM. In this work, a hydraulic-mechanical-thermal coupled model of CO2-ECBM is established, it combines binary gases (CO2 and CH4) infiltration and diffusion, where non-isothermal adsorption is also considered. The effect of injection pressure and reservoir initial temperature on CO2-ECBM was simulated by the finite element simulation software COMSOL Multiphysics, results show that: the injection of CO2 into coalbed has a good effect on enhancing the production of CH4, and both the CO2 storage rate and CH4 production rate increase with the increase of injection pressure. The effect of initial reservoir temperature on CO2-ECBM is obvious. Since the amount of adsorbed gas in coal decreases with the increase of temperature, the CO2 storage rate and CH4 production rate decrease with the increase of initial reservoir temperature. In the gas extraction process without CO2 injection, the variation of permeability is competition result of two types of factors: the coal matrix shrinkage caused by temperature reduction and gas desorption increase, the other is the coal matrix expansion caused by gas pressure decrease, so the permeability follows the rule of first decreasing and then increasing with the extraction time. The injection of CO2 has a great influence on the permeability of coalbed, adsorption of CO2 by the coal matrix causes the permeability to drop rapidly.
Process simulation and parametric sensitivity study of CO2 capture from 115 MW coal–fired power plant using MEA–DEA blend Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-06-21 Chikezie Nwaoha, David W. Smith, Raphael Idem, Paitoon Tontiwachwuthikul
This study used ProMax® 4.0 process simulator (rate–based model) to conduct a parametric sensitivity of carbon dioxide (CO2) capture from a 115 MW coal–fired power plant (Boundary Dam 3 power plant) using monoethanolamine (MEA) and diethanolamine (DEA) blend. Saskatchewan Power Corporation (SaskPower), Canada provided the flue gas composition used in this study. The validated simulation was used to determine the effects of some process variables (independent process variables) on different dependent process variables. The independent process variables are flue gas temperature (TFG, oC), lean amine temperature (TLA, oC), lean amine flow rate (FLA, tonne/day), lean amine concentration difference (CMEA–DEA, kmol/m3) and reboiler temperature (TREB, oC). The dependent process variables are MEA and DEA vaporization from the absorber, CO2 absorption efficiency (%), regeneration energy (GJ/tonne CO2), rich amine loading (RAL, mol CO2/mol amine) and lean amine loading (LAL, mol CO2/mol amine). Amine degradation was investigated by the O2 absorption rate (tonne O2/day), NO absorption rate (tonne NO/day) and NO2 absorption rate (tonne NO2/day). The vaporization rates of MEA (tonne MEA/day) and DEA (tonne DEA/day) were also investigated. The contribution of amine and water make–up costs, regeneration energy, pump electrical energy, blower electrical energy and compressor electrical energy towards variable operating expenditure (V–OPEX) were also investigated. Results showed that NO also contributes to amine degradation. From the parametric analysis it was observed that TREB has the greatest influence on most of the dependent process variables. It was also discovered that the regeneration energy, compressor electrical energy and amine, water make–up cost and cooling water contributed 82.5%, 12.3%, 1.1%, 0.9% and 0.5% of the V–OPEX respectively.
Study of operational dynamic data in Aquistore project Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-06-28 Si-Yong Lee, Lee Swager, Lawrence Pekot, Mark Piercey, Robert Will, Wade Zaluski
Mapping of paleo residual oil zones on the NCS and the potential for production by CO2-EOR Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-07-06 Per E.S. Bergmo, Alv-Arne Grimstad, Kuncho Kurtev
Existence of paleo residual oil zones (PROZ) on the Norwegian Continental Shelf (NCS) has been observed in a number of exploration wells where thickness of the PROZ vary between a few meters and several hundred meters. In a study for Statoil the existence and extent of resources in PROZs have been mapped, and the potential for CO2-EOR in these zones investigated. The main objective of the study was to reveal the magnitude of the resources, how and how much of the PROZ oil that can be recovered and how much CO2 that can be stored. Knowledge of these issues will be important both for management of the petroleum production on the NCS and for future CO2 storage operations. The study has identified 20 Statoil-operated fields with indications of a PROZ below the oil-water contact (OWC). Estimates of in-place volumes are presented for each of the fields, adding up to a total amount of PROZ oil in the identified fields in the order of 1 GSm3. Simulation of tertiary CO2-EOR on naturally water-flooded oil reservoirs with an underlying PROZ has been performed on generic North Sea oil reservoir models to investigate the potential for oil recovery from PROZs. CO2 storage capacity for the identified fields has been estimated based on results from the simulations.
Using simplified methods to explore the impact of parameter uncertainty on CO2 storage estimates with application to the Norwegian Continental Shelf Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-06-16 Rebecca Allen, Halvor M. Nilsen, Knut-Andreas Lie, Olav Møyner, Odd Andersen
We use simplified methods to investigate how uncertainty in geological models affects practical CO2 storage capacities in large-scale saline aquifers. Our focus is on uncertainties in top-surface elevation, rock properties (porosity, permeability), fault transmissibility, and aquifer conditions (pressure and temperature). To quantify the statistical characteristics of static trapping capacity and dynamic estimates of plume migration, we create hundreds of possible realizations of the geomodel by applying Gaussian-type perturbations to the spatially correlated properties. Two different simplified methods are introduced to reduce the computational cost of simulating migration over thousands of years in all the model realizations, which each spans hundreds of kilometers. First, we use vertical-equilibrium (VE) modelling, which is orders of magnitude faster than solving the 3D flow equations. Second, we introduce a fast look-ahead algorithm that enables us to exit the VE simulation once a pseudo-steady state is reached. This algorithm uses a spill-point analysis of the top-surface's trapping structure to forecast how much CO2 will eventually become trapped and how much will leak through open boundaries of the formation. This reduces the computational cost significantly, since we seldom need to simulate long-term migration past a few hundred or thousand years.
Performance of a 50 kWth coal-fuelled chemical looping combustor Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-05-31 Jinchen Ma, Xin Tian, Chaoquan Wang, Xi Chen, Haibo Zhao
A 50 kWth chemical looping combustion (CLC) reactor for coal has been successfully constructed and operated. A turbulent fluidized bed acts as the air reactor (AR) to achieve high solid circulation rate, while a bubbling fluidized bed operates as the fuel reactor (FR) to guarantee sufficient solid residence time. Two risers are separately connected to the AR and FR to provide the driving force for oxygen carrier (OC) circulation. A four-chamber loop seal (LS) is installed between AR and FR, playing the roles of a gas-sealing configuration and also a carbon stripper to convert unreacted char. Low-cost natural hematite was used as OC and Shenhua bituminous coal was used as fuel. A series of tests was conducted to investigate the performance of the newly constructed CLC reactor under different operational parameters. Effects of temperature, inlet gas velocity and H2O concentration in fluidizing agent, on the performance of the CLC reactor were investigated. The relatively stable pressure drop attained in the FR indicated successful operation of the CLC system. During 120 min continuous running with a bed inventory of 100 kg in FR, the highest CO2 yield reached to 0.91 and the combustion efficiency was 0.86 at 1000 °C.
Characterization of combined Fe-Cu oxides as oxygen carrier in chemical looping gasification of biomass Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-05-30 Tianxu Shen, Huijun Ge, Laihong Shen
Chemical looping gasification (CLG) of biomass is an innovative biomass gasification technology, where oxygen carrier (OC) has the effects of oxygen supply, heat transfer and catalyst for syngas production. In order to integrate the synergistic effect between Fe and Cu oxides, a novel combined OC containing Fe2O3 and CuO was produced for biomass gasification and investigated in a batch fluidized bed reactor in this work. At first, an OC with 50 wt.% Fe2O3 and 10 wt.% CuO (Fe50Cu10) was selected as the representative OC to evaluate the superiority of combined OC. The mono-metallic OC of CuO is unsuitable as oxygen carrier in the CLG of biomass due to its too low syngas yield, although CuO can greatly accelerate biomass gasification process. In addition, combined Fe-Cu oxides OC is also superior to mono-metallic OC of Fe2O3 at enhancing carbon conversion efficiency on the premise that syngas yield tended to be close. Then the blending ratio of Fe/Cu was optimized and Fe50Cu10 had been proven to be the optimal combined Fe-Cu oxides OC in CLG. Next, the influences of the factors including gasification temperature, steam mole fraction and O/C ratio on the performance of Fe50Cu10 were investigated. 900 °C is the best temperature for gasification and higher team mole fraction gave rise to higher carbon conversion efficiency and syngas yield, while O/C ratio was somewhat different. The optimal O/C ratio was deemed to be 0.78. Besides, 10 redox cycles were conducted to investigate the stability of combined OC reactivity. The combined OC after 3 cycles performed worst reactivity, while better performance was demonstrated after 7–10 cycles. Based on the analysis of SEM-EDX, it was found that sintering caused by Cu atomic was the main cause of the reactivity decline. In addition, it was inferred that the distribution of Cu atomic in the combined OC was more uniform with the cycle number.
Coal direct chemical looping hydrogen production with K-Fe-Al composite oxygen carrier Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-05-26 Zhongliang Yu, Tao Liu, Chunyu Li, Shuai Guo, Xing Zhou, Youchuan Chen, Yitian Fang, Jiantao Zhao
Hydrogen production by coal direct chemical looping (CDCL) process with iron-based oxygen carrier is an attractive option to produce H2 with sequestration-ready CO2. However, low reduction rate and high endothermicity are the two main difficulties of this process. In this work, the reduction rate of K-Fe-Al composite oxygen carrier by coal char, and the effect of Al2O3 on the endothermic property and sintering of oxygen carrier during reduction were investigated by thermogravimetric analyzer (TGA), differential scanning calorimetry (DSC), X-ray diffractometer (XRD), and scanning electron microscopy (SEM). The feasibility of this process was preliminary analyzed using a fixed-bed reactor by simulating different reaction steps. It was found that the reduction rate of composite oxygen carrier increased remarkably with higher potassium amount, but decreased with increasing Al2O3 amount. However, the addition of Al2O3 into oxygen carrier could not only mitigate the sintering, but also alleviated the endothermicity of reduction by the exothermic formation of FeAl2O4. This preliminary feasibility analysis suggests that it is possible to produce H2 using CDCL with the K-Fe-Al composite oxygen carrier
A meta-analysis of the surface soil gas measurement monitoring and verification (MMV) program at the Aquistore project Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-06-13 Nadia Tarakki, David Risk, Lynsay Spafford, Chelsea Fougère
Is CO2 injection at Aquistore aseismic? A combined seismological and geomechanical study of early injection operations Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-06-01 A.L. Stork, C.G. Nixon, C.D. Hawkes, C. Birnie, D.J. White, D.R. Schmitt, B. Roberts
Evaluation of recycle gas injection on CO2 enhanced oil recovery and associated storage performance Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-06-14 Lu Jin, Lawrence J. Pekot, Steven B. Hawthorne, Olarinre Salako, Kyle J. Peterson, Nicholas W. Bosshart, Tao Jiang, John A. Hamling, Charles D. Gorecki
An enhanced oil recovery (EOR) technique comprising the alternate injection of gas (CO2) and water, commonly referred to as water alternating gas (WAG) flooding, is currently ongoing at an oil field in the northeastern Powder River Basin (PRB), where 4 million barrels (MMbbl) of oil were produced between May 2013 and September 2017. During WAG flooding, a large amount of CO2, which contains some impurities, is produced at the surface with the recovered oil and reinjected into the reservoir to minimize the amount of purchased CO2. The concentration of these impurities in the CO2, which are dominated by CH4, is a key parameter in the design of miscible CO2 flooding of an oil reservoir and in the quantitative assessment of the associated storage of CO2 that occurs in the reservoir. For a given oil and reservoir temperature, the CO2–oil minimum miscibility pressure (MMP) is strongly and adversely affected by the presence of CH4, the concentration of which varies with time and operational conditions, such as injection pressure, flooding pattern, and injection scheme (i.e., continuous CO2 injection or WAG). To capture the full range of potential variation in the MMP caused by the presence of CH4, a series of laboratory experiments were conducted to determine CO2–oil MMP with different mole percentages of CH4 in the CO2. All of the experiments were performed at reservoir temperature (108 °F) using the VIT (vanishing interfacial tension) method. Results showed that MMP increases from 1403 to 4085 psi as the mole percentage of CH4 in the CO2 increases from 0% to 100%. To assess the impact of this variation in MMP on the oil recovery performance in the field, a history-matched, compositional reservoir simulation model was used to predict the oil production performance for a WAG flood using CO2 that contained a range of CH4 concentrations. The reservoir simulations examined the effects of permeability heterogeneity, fluid crossflow, and phase behavior on the oil displacement performance in three-dimensional space over time. Simulation results indicated that CO2 floods using a limited range of CO2–CH4 mixtures could still maintain multiple-contact miscibility and result in effective EOR. In addition, the ability to reinject produced CO2–CH4 mixtures as is, without removal of the CH4, ensured that this approach to EOR would continue to be cost-effective.
Effects of gas relative permeability hysteresis and solubility on associated CO2 storage performance Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-06-14 Lu Jin, Lawrence J. Pekot, Steven A. Smith, Olarinre Salako, Kyle J. Peterson, Nicholas W. Bosshart, John A. Hamling, Blaise A.F. Mibeck, John P. Hurley, Christopher J. Beddoe, Charles D. Gorecki
CO2 enhanced oil recovery (EOR) has been carried out in the Bell Creek oil field since 2013. Together with the encouraging oil production results, a considerable quantity of CO2 has also been trapped in the reservoir as a normal part of the EOR process, also referred to as associated storage. Because of the complex geologic conditions in the field, a series of experimental and modeling work have been conducted to better understand the CO2 EOR and associated storage performance in the reservoir. Effects of gas relative permeability hysteresis and solubility on associated CO2 storage performance are thoroughly investigated in this study. A proportion of injected CO2 remains behind through residual and solubility trapping mechanisms when CO2 flows through a reservoir during a CO2 EOR process. Over 50 core plugs were collected from the reservoir to characterize the rock properties. Mineralogical analysis and capillary pressure measurements showed that the mineral composition and pore-size distribution in the reservoir are favorable for residual trapping of CO2. The hysteresis of gas relative permeability was measured to assess the effect of residual trapping on associated CO2 storage using steady-state relative permeability tests and reservoir simulation. The reservoir oil was characterized based on pressure–volume–temperature experiments and Peng–Robinson equation of state modeling, which showed that CO2 solubility in oil is much greater (≥5 times) than in water. Results indicated that depleted oil reservoirs have great potential to store a huge quantity of CO2 associated with EOR operations, as residual oil saturation is 0.3 or greater in most conventional oil reservoirs after water flooding.
Statistical analysis of pulsed-neutron well logs in monitoring injected carbon dioxide Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-06-07 Nicholas A. Azzolina, Nicholas W. Bosshart, Matthew E. Burton-Kelly, John A. Hamling, Wesley D. Peck
Pulsed-neutron well logs (PNLs) were acquired to monitor CO2 storage associated with enhanced oil recovery. This work quantifies the precision of repeat PNLs using data from four wells and 15 repeat PNLs. Root-mean-square (RMS) precision for the repeat PNLs was less than 3%, indicating good agreement between the baseline and repeat PNLs. Evaluations of scaled relative difference (Scaled-D) showed variation in precision among individual wells and formations. Analysis of false-positive rates (FPRs) across the entire data set showed that a Scaled-D threshold in sandstone formations of approximately ±8% resulted in a 1% FPR. These Scaled-D precision thresholds were used to estimate the value of CO2 saturation able to be confidently distinguished from baseline. The detection limit for CO2 is lowest for high-porosity formations filled with saline water and is highest for low-porosity formations filled with fresh water. Thus, detection of vertical out-of-zone CO2 migration using repeat PNLs is a function of instrument precision, petrophysical properties, and hydrology, all of which must be taken into account as part of the monitoring program. The results of this work provide insight into how PNLs may be included within monitoring plans to detect vertical out-of-zone CO2 migration along a wellbore or instances of wellbore failure and provide a quantitative basis for establishing detection limits of repeat PNLs to distinguish change from baseline conditions.
A technology review for regeneration of sulfur rich amine systems Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-07-11 Bharti Garg, T. Vincent Verheyen, Pauline Pearson, Paul Feron, Ashleigh Cousins
Reducing the capital cost of post combustion CO2 capture by eliminating flue gas desulfurisation (FGD) pre-treatment, requires management of the amines preferential SO2 absorption. Novel technologies such as CS-Cap restrict the impact of SO2 to only a small fraction of the amine inventory resulting in high sulfate burden amines. Traditional thermal reclamation of these spent absorbents has advantages regarding simplicity, but ranks poorly for industrial ecology around PCC. These amines require low energy regeneration technologies compatible with their physico-chemical properties that also maximise the potential for valorising by-products. This review summarises the sulfur chemistry and outlines several amine reclamation processes. It assesses the status of established and novel regeneration technologies for their applicability to high sulfur loaded amines. Should deep sulfur removal be required, a hybrid approach with initial bulk removal (as product) followed by a polishing step to further reduce sulfur is prospective. A preliminary estimation of the relative cost of using standard reclamation methods for treating Sulfur loaded CS-Cap absorbent revealed the cost would increase due to its higher sulfate burden despite comparable treatment volumes. Research gaps are identified which would enable better comparison between the costs of traditional FGD versus higher reclamation costs for combined capture technologies.
Fully coupled inversion on a multi-physical reservoir model – Part II: The Ketzin CO2 storage reservoir Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-07-06 Florian M. Wagner, Bernd U. Wiese
Reliable monitoring of CO2 storage reservoirs requires a combination of different observation methods. However, history matching is typically limited to CO2 pressure data alone. This paper presents a multi-physical inversion of hydraulic pressure, CO2 pressure, CO2 arrival time and geoelectrical crosshole observations of the Ketzin pilot site for CO2 storage, Germany. Multi-physical inversion has rarely been reported for CO2 storage reservoirs. In contrast to previous studies, there is no need for pre-inversion of geophysical datasets as these are now directly included in a fully coupled manner. The deteriorating impact of structural noise is effectively mitigated by preconditioning of the observation data. A double regularisation scheme provides stability for insensitive parameters and reduces the number of required model runs during inversion. The model shows fast and stable convergence and the results provide a good fit to the multi-physical observation dataset. It has certain predictive power as the known migration direction of the CO2 plume is captured. These results clarify two long discussed issues of the Ketzin CO2 storage reservoir: (1) The pre-existing hypothesis of an existing hydraulic barrier became unsubstantial as the data series suggesting weak hydraulic communication are identified as erroneous. (2) Salt precipitation around the injection well doubles the injection overpressure compared to salt free conditions, which is equivalent to a well skin of 10. The presented framework allows to integrate various types of observations into a single multi-physical model leading to an increased confidence in the spatial permeability distribution and, in perspective, to improved predictive assessments of CO2 storage reservoirs.
Fully coupled inversion on a multi-physical reservoir model – Part I: Theory and concept Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-06-19 Bernd U. Wiese, Florian M. Wagner, Ben Norden, Hansruedi Maurer, Cornelia Schmidt-Hattenberger
State of the art reservoir monitoring delivers numerous property data with high resolution. Especially the consistent interpretation of pressure data with different geophysical methods requires multi-physical modelling and inversion workflows. Such a workflow is developed based on the reservoir monitoring concept of the Ketzin pilot site for CO2 storage, Germany. The workflow consists of three physical models, (i) a single phase hydraulic model, (ii) a multiphase CO2 migration model and (iii) a geoelectrical model. Calibration is carried out to match observation data groups hydraulic pressure, CO2 pressure, CO2 arrival time and geoelectrical cross-hole observations. Calibration parameters are spatially distributed hydraulic permeability and porosity, compressibility, the relative permeability function and the geoelectrical saturation exponent. Geoelectrical measurements with low coverage that cannot be inverted with traditional methods could be included, since the multiphysical reservoir model acts as physical regularisation. The indirect nature of geophysical data is overcome by implementation of petrophysical relations between permeability and porosity and between CO2 saturation and electrical resistivity. Stability against field data is increased by reducing the impact of structural noise through preprocessing the observation data. Stability against the overparameterisation is added by Tikhonov regularisation and singular value decomposition, the latter combined with super parameter definition reducing the problem dimensions and simulation time by three quarters. A synthetic case study demonstrates that the model resolves the spatial permeability and identifies the petrophysical relation between CO2 saturation and electrical resistivity. The weighting scheme balances different observation data groups and measurement intervals. The model to measurement misfit is reduced proprotionally for all observation data groups, while the geoelectrical data are most difficult to match.
Low carbon oil production: Enhanced oil recovery with CO2 from North Sea residual oil zones Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-06-30 R. Jamie Stewart, Gareth Johnson, Niklas Heinemann, Mark Wilkinson, R. Stuart Haszeldine
Residual Oil Zones (ROZ) form when oil has leaked or migrated from a reservoir trap through geological time, leaving a zone of immobile oil. Here we assess the feasibility of ROZ production with CO2 flooding, in a North Sea oil field for the first time. We identify a hydrodynamically produced ROZ, with an oil saturation of 26%, in the Pierce Oil Field of the Central North Sea and adapt established recovery factors for Carbon Dioxide Enhanced Oil Recovery (CO2 EOR) from onshore fields, to estimate oil resource and CO2 storage potential. Our mid case results show that CO2 utilisation increases commercial reserves by 5–20% while storing 15 M t CO2. Based on our calculations CO2 EOR can produce low carbon intensity crude oil from a mature basin and could store more CO2 than is released from the production, transport, refining and final combustion of oil.
Assessment of the operability of a 20 MWth calcium looping demonstration plant by advanced process modelling Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-06-28 Martin Haaf, Jochen Hilz, Martin Helbig, Christoph Weingärtner, Olaf Stallmann, Jochen Ströhle, Bernd Epple
The Calcium Looping (CaL) process is a promising technology for post-combustion CO2 capture from fossil-fired power plants and carbon intense industry. Within a CaL system, a limestone based sorbent stream is forced to circulation between two interconnected circulating fluidized bed (CFB) reactors. The main part of the CO2, contained in the flue gas stream is absorbed by CaO within the carbonator, whereas it is released during regeneration in the oxy-fired calciner. The feasibility of this technology was proven by numerous experimental investigations in semi-industrial scale. The next step in the development of this technology is expected to be a demonstration plant in the scale of approximately 20 MWth. The focus of this paper is the determination of the heat and mass balances and the assessment of the operability of a newly designed 20 MWth CaL demonstration plant. The investigations are based on a steady-state process model, which has been validated by experimental data from 1 MWth pilot tests. The aspect of solid entrainment during part load operation are addressed. In the present design case, a stable operation of the demonstration plant at 40 % equivalent carbonator load is feasible without additional flue gas recirculation.
The study of kinetics of CO2 absorption into 3-dimethylaminopropylamine and 3-diethylaminopropylamine aqueous solution Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-06-18 Yanru Chen, Wusan Jiang, Xiao Luo, Yangqiang Huang, Bo Jin, Hongxia Gao, Wensheng Li, Zhiwu Liang
In this work, the stopped-flow technique is used to determine the kinetics data in terms of pseudo first-order rate constants (k0) for the homogenous reaction of CO2 into aqueous solutions of 3-dimethylaminopropylamine (DMAPA) and 3-diethylaminopropylamine (DEAPA) as amine concentrations ranged from 0.05 kmol/m3 to 0.15 kmol/m3 and temperature ranged from 293 K to 313 K. It is found that k0 increased with increasing temperature and with increasing amine concentration. The mechanism of the pseudo first-order chemical reaction hypothesis is applied to interpret the experimental data. The Arrhenius expressions as k 2 = 8.69 × 10 9 × exp ( − 4226.2 / T ) for DMAPA and k 2 = 7.21 × 10 12 × exp ( − 6162.9 / T ) for DEAPA are obtained. The results show that the experimental CO2 absorption rates exhibited good agreement with predicted CO2 absorption rates with an average relative deviation (ARD) of 2.34% and 7.53%, respectively. Finally, the interaction of tertiary amine groups with primary amine groups and the effect of molecular structure on the interaction are discussed by comparing the CO2 absorption and desorption performances in five different systems (MEA, DEEA, MEA + DEEA, DMAPA, DEAPA). It is found that the intermolecular interaction of amino groups is stronger than that of intramolecular interaction.
CO2-SCREEN tool: Application to the oriskany sandstone to estimate prospective CO2 storage resource Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-06-14 Sean Sanguinito, Angela L. Goodman, James I. Sams
The mechanisms, dynamics, and implications of self-sealing and CO2 resistance in wellbore cements Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-06-14 George D. Guthrie, Rajesh J. Pawar, J. William Carey, Satish Karra, Dylan R. Harp, Hari S. Viswanathan
This study analyzes the dynamics and mechanisms of the interactions of carbonated brine with hydrated-Portland-cement; in particular, the study focuses on self-sealing, a process whereby hydrated-Portland cement reacts with carbonated brine to for silica and calcium carbonate in sufficient quantities to seal the flow pathway. The analysis is based on a comprehensive set of reactive-transport simulations that explore the complex coupled dynamics between the fluid flow and mineral reactions that underlie self-sealing, and it relies heavily on the synthesis of the extensive body of work on wellbore integrity that has been conducted over the past decade. The analysis explores a large chemical and mineralogical diversity and a wide range in physical conditions and flow regimes, attempting to assess the robustness of the analysis. Self-sealing conditions arise over a wide range in cement properties and reservoir conditions. Although some properties and conditions promote a stronger self-sealing response, self-sealing occurs for a wide range of Ca:Si ratios in cement and for various reservoir fluid compositions. Self-sealing conditions move along a wellbore proportional to the flux of the leaking carbonated brine, and the reaction zone spreads out proportional to the fluid velocity, where volumetric flux and velocity are related by porosity (flux = velocity * porosity). However, self-sealing conditions can be maintained in a specific section of a wellbore by controlling the pressure drive and/or effective wellbore permeability, which in turn can limit the flux and velocity of any leaking fluid. Finally, the phases produced by hydrating Portland cement represent a carbonic cement that will react with a carbonated brine to produce end products (calcium carbonate and silica) that can maintain integrity in the presence of carbonic acid. Moreover, the attributes that make hydrated Portland cement phases a carbonic cement are required for self-sealing.
Ionic liquid-based CO2 capture in power plants for low carbon emissions Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-06-07 Yixin Ma, Jun Gao, Yinglong Wang, Jiajing Hu, Peizhe Cui
Carbon capture using an ionic liquid as the solvent has been considered to be an effective way to reduce CO2 emissions. This study aimed to investigate ionic liquid (IL)-based carbon dioxide capture and storage processes compared with the MEA-based process from a power plant’s flue gas. Ionic liquid 1-Butyl-3-methylimidazolium Bis(trifluoromethanesulfonyl) ([bmim][Tf2N]) was used as the solvent. The COSMO-SAC model was selected as the property method for all of the simulations. Based on sensitivity analysis optimization, the optimal process was obtained and the energy saving ratio (ESR) and primary cost saving ratio (PCS) were calculated. The results showed that the ionic liquid-based process performed better than the process using traditional organic solvents monoethanol-amine (MEA) in terms of cost. Due to the non-volatility of ionic liquids, two flash tanks were used instead of the solvent recovery stripper. The ionic liquid process led to 30.01% savings on energy consumption and 29.99% savings on the primary cost. The specific electricity of the CO2 storage was 237 kWh/t (CO2) and 124 kWh/t (CO2) in the two processes. Because the output pressure of CO2 from the IL-based process was lower than that from the MEA-based process, more energy consumption was required.
Technical and environmental study of calcium carbonate looping versus oxy-fuel options for low CO2 emission cement plants Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-05-31 A. Rolfe, Y. Huang, M. Haaf, A. Pita, S. Rezvani, A. Dave, N.J. Hewitt
A comparative study on the design of direct contact condenser for air and oxy-fuel combustion flue gas based on Callide Oxy-fuel Project Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-05-31 Dunyu Liu, Jing Jin, Ming Gao, Zhibo Xiong, Rohan Stanger, Terry Wall
Direct contact condenser is widely used in oxy-fuel combustion capture systems. Unusually high content of water vapor in the flue gas requires rigorous sizing procedures for the condenser design. Non-linear differential equations for humidity, gas and liquid temperatures were set up to understand the evaporation/condensation process in the condenser. A Quasi-Newton method was adopted to simultaneously solve discrete equations to avoid difficulty in convergence. This model was firstly verified with reported experiments in a packed bed condenser. The significant impacts of L/G ratio on condenser height, packing volume, condenser diameter are identified. The optimum L/G range is obtained by the wet bulb temperature and minimal decrease on packing volume, and this results in the L/G range of 2.5–5.2 and 4.3–6.7 for air and oxy-fuel combustion respectively. The condenser diameter and packing volume corresponding to the optimum L/G range for air-fuel combustion are approximately twice and four times of these for oxy-fuel combustion. While the packing height for air-fuel combustion is slightly lower than that for oxy-fuel combustion. By economic analysis, normalized total capital and annual costs for air-fuel combustion are approximately four times and twice of these for oxy-fuel combustion. The decrease of L/G ratio reduces the normalized total capital and annual costs for both air and oxy-fuel combustion and more significant for air-fuel combustion. Therefore, the L/G ratio is preferably obtained by the wet bulb temperature. This paper sheds light on the rigorous design method and the optimization of design parameters for direct contact condenser.
Kinetics and pathways for nitrosamine formation in amino acid-based carbon dioxide capture systems Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-05-28 Kun Yu, Vignesh Peranamallur Rajan, Ning Dai
Time-lapse VSP monitoring for CO2 injection: A case study in ordos, China Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-05-28 Qiang Luo, Yibo Wang, Yongsheng Wang, Maoshan Chen, Yikang Zheng, Shaojiang Wu, Xu Chang, Rongshu Zeng
Carbon dioxide capture and storage (CCS) is considered one of the options for reducing atmospheric emissions of CO2 from human activities. Geological storage, as an important method to reduce CO2 emissions, may lead to a series of geomechanical problems due to the large amounts of gas injected. Starting in 2010, the Shenhua CCS demonstration project in the Ordos Basin, China, which is the first and the largest full-chain saline aquifer storage project in Asia, had injected a total of 0.3 million tons (Mt) of CO2 by 2015. The VSP method was used to monitor seismic properties. Baseline and repeat VSP surveys were conducted in May 2011 and August 2013, respectively. This paper focuses on the techniques of wave field separation and consistency processing. The upgoing P wave was used to image the time-lapse profiles by the VSP-CDP stack. Comparing the results, it was found that the time-lapse VSP method provides accurate and high-resolution images to monitor the CO2 diffusion range. The reliability of the method was then checked by the lithology of the target layer. With this current time-lapse VSP and geological analysis, the results showed that there is no obvious danger of gas leakage in the project, and that CO2 has been sealed in five predetermined reservoirs.
Confining system integrity assessment by detection of natural gas migration using seismic diffractions Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-05-27 Alexander Klokov, Timothy A. Meckel, Ramón H. Treviño
Successful carbon capture and storage (CCS) requires secure CO2 confinement within a geologic reservoir. If associated with a depleted hydrocarbon reservoir, the sealing capability can be determined by examination of the shallow subsurface for hydrocarbon leaks. Numerous seismic signatures have been reported to be hydrocarbon indicators. The interpretation can be advanced by using seismic diffractions, which could indicate subtle hydrocarbon accumulations not detectable by conventional techniques. In this work, we investigate the potential of seismic diffractions for use in shallow gas detection. We extract diffractions from the ultra-high-resolution 3D P-Cable seismic dataset acquired along the Gulf of Mexico inner continental shelf. Interpretation of this dataset revealed numerous seismic signatures associated with hydrocarbon accumulations (e.g., a prominent gas chimney). We analyze scattering features of the detected hydrocarbon accumulations and confirm the correlation between confidently interpreted gas accumulations and seismic diffractions. Based on that, we suggest using diffractions for confining system integrity assessment. Diffraction analysis allows operating with subtle seismic signals that facilitates exploration of reliable CO2 storage sites.
The geospatial and economic viability of CO2 storage in hydrocarbon depleted fractured shale formations Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-05-26 Jeffrey M. Bielicki, Julie K. Langenfeld, Zhiyuan Tao, Richard S. Middleton, Anne H. Menefee, Andres F. Clarens
Hydrocarbon depleted fractured shale (HDFS) formations could be attractive for geologic carbon dioxide (CO2) storage. Shale formations may be able to leverage existing infrastructure, have larger capacities, and be more secure than saline aquifers. We compared regional storage capacities and integrated CO2 capture, transport, and storage systems that use HDFS with those that use saline aquifers in a region of the United States with extensive shale development that overlies prospective saline aquifers. We estimated HDFS storage capacities with a production-based method and costs by adapting methods developed for saline aquifers and found that HDFS formations in this region might be able to store with less cost an estimated ∼14× more CO2 on average than saline aquifers at the same location. The potential for smaller Areas of Review and less investment in infrastructure accounted for up to 84% of the difference in estimated storage costs. We implemented an engineering-economic geospatial optimization model to determine and compare the viability of storage capacity for these two storage resources. Across the state-specific and regional scenarios we investigated, our results for this region suggest that integrated CCS systems using HDFS could be more centralized, require less pipelines, prioritize different routes for trunklines, and be 6.4–6.8% ($5-10/tCO2) cheaper than systems using saline aquifers. Overall, CO2 storage in HDFS could be technically and economically attractive and may lower barriers to large scale CO2 storage if they can be permitted.
Low temperature swing process for CO2 absorption-desorption using phase separation CO2 capture solvent Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-05-25 Hiroshi Machida, Ryuya Ando, Takehiro Esaki, Tsuyoshi Yamaguchi, Hirotoshi Horizoe, Akira Kishimoto, Katsuya Akiyama, Makoto Nishimura
We have developed a phase separation solvent which transforms into two liquid phases after CO2 absorption, in order to establish an energy-saving CO2 capture process. The CO2 loading changes strongly with temperature increase during the phase separation, which enables us to reduce the temperature difference between absorber and desorber. The low temperature swing process economizes the energy requirement for the CO2 capture process with highly-effective reaction-heat recovery. We evaluated the energy consumption of the CO2 capture process with our novel phase separation solvent based on the CO2 solubility. The energy requirement was estimated to be as low as 1.6 GJ/ton-CO2.
Well integrity risk assessment to inform containment risk monitoring for carbon capture, utilization, and storage, applied to the Weyburn-Midale Field, Canada Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2017-03-15 Andrew Duguid, Wade Zaluski, George El-Kaseeh, Si-Yong Lee, Mark Piercy
The existing data for wells in the Weyburn-Midale Field were used in conjunction with publicly available data to create an updated well integrity risk assessment as an aid in establishing CO2 containment risk and developing a guide to selection of monitoring technologies for risk management. The assessment built upon an existing assessment to rank 1424 wells on 13 categories used as a proxy for likelihood of CO2 migration and four categories used as a proxy for severity of impact of migration. The results of the assessment were used to show that both the risk posed by individual wells and risk posed by categories may be significant with respect to CO2 migration. The location of the top of cement, quality of the casing, and type of well categories were ranked high throughout the distribution of wells with respect to likelihood of migration. The assessment of casing integrity and setting of casing through the Midale Evaporite was a differentiating factor between higher-likelihood and lower-likelihood well scores. The aquifer protection category used in assessing the severity of impact ranked high across the distribution of wells. The proximity to a water source category was a differentiating factor between higher-severity and lower-severity rankings. The wells scores and ranking categories were used to assess the value of specific monitoring tools for managing containment risks. The outcome of the study showed that both high risk wells and high-risk categories can be identified and that a monitoring program should be adopted to address both through point and area monitoring.
The impact of gradational contact at the reservoir-seal interface on geological CO2 storage capacity and security Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-03-19 Michael U. Onoja, Seyed M. Shariatipour
The implementation of CO2 storage in sub-surface sedimentary formations can involve decision making using relevant numerical modelling. These models are often represented by 2D or 3D grids that show an abrupt boundary between the reservoir and the seal lithologies. However, in an actual geological formation, an abrupt contact does not always exist at the interface between distinct clastic lithologies such as sandstone and shale. This article presents a numerical investigation of the effect of sediment-size variation on CO2 transport processes in saline aquifers. Using the Triassic Bunter Sandstone Formation (BSF) of the Southern North Sea (SNS), this study investigates the impact a gradation change at the reservoir-seal interface on CO2 sequestration. This is of great interest due to the importance of enhanced geological detail in reservoir models used to predict CO2 plume migration and the integrity of trapping mechanisms within the storage formation. The simplified strategy was to apply the Van Genutchen formulation to establish constitutive relationships for pore geometric properties, which include capillary pressure (Pc) and relative permeability (kr), as a function of brine saturation in the porous media. The results show that the existence of sediment gradation at the reservoir-seal interface and within the reservoir has an important effect on CO2 migration and pressure diffusion in the formation. The modelling exercise shows that these features can lead to an increase in residual gas trapping in the reservoir and localised pore pressures at the caprock’s injection point.
Impact of inner reservoir faults on migration and storage of injected CO2 Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-03-19 Zhijie Yang, Tianfu Xu, Fugang Wang, Yanlin Yang, Xufeng Li, Ningning Zhao
CO2 geological storage (CGS) is an effective way to mitigate greenhouse gas emissions, and geological security is one of the most important issues in CGS. The faults distributed in geological formations make multi-layered reservoirs interconnected systems. A three-dimensional (3D) numerical model was established to evaluate the effects of inner reservoir faults on the CO2 migration and storage capacity of an actual CGS demonstration project in the Ordos Basin of China. The results show that the faults in the layered reservoir system could significantly affect the migration of injected CO2. The cross-layer faults at the bottom of the faulted reservoir could act as preferential passages between the upper and lower geological formations, causing the CO2 in the reservoir formation to move upward to adjacent layers rather than to lateral migration. CO2 migration along the inner-layer faults widely occurred at the top of the reservoir formation, decreasing the pressure accumulation and CO2 saturation around the injection well. Based on the simulation, CO2 will have migrated into the Heshanggou Formation after 300 years, and most of the CO2 will be trapped in the bottom sub-layers, with no CO2 intruding into the upper caprock. The spatial and temporal evolution of the injected CO2 was well presented for the faulted reservoir system, suggesting that the faults inside the multi-layered reservoir are beneficial to CGS.
On the variability of CO2 feed flows into CCS transportation and storage networks Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-05-28 T. Spitz, V. Avagyan, F. Ascui, A.R.W. Bruce, H. Chalmers, M. Lucquiaud
The flexible operation of CO2 injection wells presents significant challenges. To avoid premature degradation of wells or loss of integrity it is imperative to understand the feed flow patterns that future CO2 transportation and storage networks will face. We use a unit commitment economic dispatch (UCED) model to study CCS operating regimes in low carbon energy systems scenarios that are characterised by high shares of weather dependent renewable power generation. Using the case study of Great Britain, we determine the extent to which flexible operation of CCS plants is required, resulting in variable CO2 flows that need to be accommodated by future CO2 transportation and storage networks. We find that around 21% and 12% of the net flow rate changes over 6h-periods in the core scenario have greater amplitudes than 30% and 50% of nominal flow, respectively. When changes are averaged over two consecutive blocks of 6 h, representing the smoothing effect achievable via line-packing over a pipeline of reasonable length and diameter, around 9% of the net changes have greater amplitudes than 40% of nominal flow. Given the high and frequent fluctuations in feed flows across all considered scenarios, further research is urgently required on the capability of transportation and storage networks to accommodate variable CO2 flow rates.
Assessment of shallow subsea hydrocarbons as a proxy for leakage at offshore geologic CO2 storage sites Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-05-26 Jacob S. Anderson, Katherine D. Romanak, Timothy A. Meckel
This study is part of a multi-phase effort to identify and characterize offshore geological carbon storage (GCS) potential along the Texas Gulf Coast. Previous efforts acquired a high-resolution 3D seismic dataset (P-cable™) and interpreted a seismically discontinuous zone as shallow gas pockets (<100 m below seafloor) associated with a vertical chimney structure. Our approach was to measure hydrocarbon concentrations and stable carbon isotopes near the seafloor to assess if gas migrated vertically from seismic anomalies. Deep-sourced thermogenic hydrocarbons would indicate that the structure is transmissive which could indicate an unacceptable risk for GCS at the site. Alternatively, hydrocarbons formed in-situ from biogenic processes would not preclude transmissivity of the structure but would add information to the risk assessment. Gases were extracted from 23 piston core samples recovered between 2.56 and 3.50 m subseafloor. Light hydrocarbons and stable carbon isotopes of methane were used for source attribution. The result was that geochemical signatures were consistent with typical background values observed within the first few meters of subsea sediment and therefore did not indicate leakage from depth. From our analysis, we offer insights into the use of hydrocarbon molecular and isotopic compositions at the seafloor for signal attribution as part of environmental assessments at geological CO2 storage sites.
Thermal regeneration of amines in vertical, inclined and oscillating CO2 packed-bed strippers for offshore floating applications Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-05-26 Ion Iliuta, Faïçal Larachi
CO2-monoethanolamine desorption process performance was studied for standard vertical, static inclined, and symmetric/asymmetric oscillating packed-bed columns via a dynamic three-dimensional model which links the macroscopic volume-averaged continuity, momentum, energy and species balance equations in the liquid and gas phases with the purpose to describe the stripping packed-bed columns aboard floating production, storage and offloading platforms. CO2 thermal desorption process is negatively impacted in static inclined and asymmetric oscillating packed-bed columns because of secondary liquid flow, generated by the buoyancy force in the radial and tangential directions, and its consequence on two-phase flow hydrodynamics and temperature fields. The continual variation of the extent of reverse secondary flow in symmetric oscillating packed-bed columns induces a symmetrical oscillatory two-phase flow follows by time-dependent waves for thermal fields and CO2 thermal desorption performance in the vicinity of the standard vertical stripper steady-state solution. Operation with extra heat allows to obtain higher CO2 desorption rates and avoids the deterioration of CO2 desorption performance in static inclined and asymmetric oscillating packed-bed columns. The extra heat is considerable when the inclined and asymmetric oscillating packed-bed columns are operated at elevated reboiler heat duty in the vertical state.
Design and evaluation of CO2 capture plants for the steelmaking industry by means of amine scrubbing and membrane separation Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-05-26 Wonseok Chung, Kosan Roh, Jay H. Lee
An option considered for reducing carbon emissions in the iron/steel industry is the use of Top-gas recycle blast furnace (TGR-BF), which captures CO2 from the blast furnace gas (BFG) and recycles the remaining CO and H2 back to the blast furnace (BF). This study suggests four different designs of CO2 capture processes suitable for the TGR-BF application: Amine scrubbing, membrane separation, and a hybrid between the amine scrubbing and the membrane separation with and without heat recovery. In particular, the hybrid-with-heat-recovery design recovers the combustion heat of the impurities (e.g., CO and H2) in the captured CO2 stream. The four alternative processes are simulated and evaluated on the basis of multiple criteria including operating cost, capital cost, rate of CO2 avoided, and CO2 avoidance cost with various electricity sources. Furthermore, sensitivity analysis is performed by perturbing the utility prices. Among the four alternatives, the hybrid-with-heat-recovery design is shown to give the best performance with the avoidance cost of $30.4/tonCO2, outperforming the mature technologies.
CO2 plume migration in underground CO2 storage: The effects of induced hydraulic gradients Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-05-26 H. Vosper, R.A. Chadwick, G.A. Williams
The use of water production as a pressure mitigation tool in the context of CO2 storage is widely studied but the impact it might have on the migration behaviour of a buoyant CO2 plume is less well reported. To investigate this further two different scenarios were modelled. In the first, a single water production well was used to draw CO2 along the strike of an open aquifer with a regional dip. Large rates of water production (5–10 times the volume of injected CO2) were required to achieve only small displacements of the CO2 plume. The second scenario investigated to what extent an induced hydraulic gradient might spill CO2 already stored in a structural trap. Here the effects were more pronounced with over 90% of the CO2 being spilled at a water cycling rate of 10 Mt per year (corresponding to a hydraulic gradient of 1.28 bar/km). The modelling was tested by the real case at Sleipner where CO2 migration in the Utsira Sand is potentially impacted by water production at the nearby Volve field. Simulations concluded that the CO2 plume at Sleipner should not be materially affected by water production from Volve and this is supported by the time-lapse seismics.
Characterization of aerosol emissions from CO2 capture plants treating various power plant and industrial flue gases Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-05-26 Hammad Majeed, Hallvard F. Svendsen
Undesired aerosol formation in gas–liquid contact devices has been a well-known phenomenon in the chemical industry for several decades and can cause severe problems in industrial gas cleaning processes. Several studies indicate that aerosols can govern the total amine emissions from amine based CO2 capture (PCCC) plants. Despite the importance of aerosol formation and mitigation for the design of a PCCC plant, very little knowledge is available on the characterization and growth of these aerosols. Four different atmospheric flue gases were modelled in this work, ranging from 4 to 20% in CO2 content and representing natural gas, oil and coal fired power plants, and gas from the cement industry. Inlet droplets of size 0.15 μ were tested in number concentrations from 1 to 107 droplets/cm3. For 20% CO2, the effect of intercooling was studied. The findings are: Aerosol droplets grow from their initial size regardless of their initial composition and type of flue gas processed. The initial composition of the droplets has a significant effect on emissions. With increasing CO2 concentration, more carbamate is formed relative to free MEA. This leads to less effective water wash and significantly higher final emissions. With low droplet number concentration no visible depletion of MEA in the absorber and water wash sections was found for any of the CO2 concentrations. At 107 droplets/cm3, gas phase MEA partial pressure changes are clearly seen, first in the water wash, and then, at higher contents, the effect starts lower and lower down in the absorber. The carry-over of amine into the water wash increases with increasing gas phase CO2 content. However, the effect on the gas phase MEA content in the water wash goes through a maximum caused by strong carbamate formation at high CO2 concentrations. The droplet temperature profiles are unaffected by number concentration and initial composition of aerosol droplets. It is found that the water wash section reduces significantly the aerosol-based, and thereby the total, amine emissions. The effect of the water wash is reduced when the flue gas CO2 content increases. Intercooling lowers the partial pressure of MEA in both absorber and water wash significantly. This reduces the droplet growth and MEA content. The combined effect is a strong reduction in MEA emissions; in the case of 20% CO2 in the flue gas, by a factor of 5–10.
Exploring novel hydrogen production processes by integration of steam methane reforming with chemical-looping combustion (CLC-SMR) and oxygen carrier aided combustion (OCAC-SMR) Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-05-26 Viktor Stenberg, Magnus Rydén, Tobias Mattisson, Anders Lyngfelt
This article discusses the concept of combining steam methane reforming (SMR) with fluidized beds of oxygen carrier particles and presents results from process simulations in Aspen Plus of new process outlines with and without carbon capture. Conventionally, heat to steam reforming tubes is provided by gas-fired burners, which transfer heat to the tube’s surface mainly by radiation. An alternative approach to provide heat to the endothermic SMR reaction is to use fluidized bed technology, utilizing oxygen carrier particles as bed material. Two novel configurations of the steam reforming process are proposed. The first concept incorporates SMR with a single bubbling fluidized bed reactor of oxygen carrier particles, or Oxygen Carrier Aided Combustion (OCAC). The second combines Chemical Looping Combustion (CLC) with an external fluidized bed heat exchanger (FBHE) used for SMR. Here, biomass is used as supplementary fuel in the furnace. The results for the OCAC-based system show that the cold gas efficiency can be increased compared to a reference case describing a conventional process, and at the same time decrease CO2 emissions by 4%. The biomass-fuelled CLC configuration displays surprisingly large negative CO2 emissions, corresponding to a CO2 emission reduction by 151% compared to the reference case.
Cost estimation of heat recovery networks for utilization of industrial excess heat for carbon dioxide absorption Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-05-11 Hassan Ali, Nils Henrik Eldrup, Fredrik Normann, Viktor Andersson, Ragnhild Skagestad, Anette Mathisen, Lars Erik Øi
The absorption of CO2 using solvents (e.g., amines) is considered a state-of-the-art, albeit energy-intensive process for CO2 capture. While it is generally recognized that the utilization of waste heat has potential to reduce the energy-associated costs for CO2 capture, the cost of waste heat recovery is seldom quantified. In this work, the cost of heat-collecting steam networks for waste heat recovery for solvent regeneration is estimated. Two types of networks are applied to waste heat recovery from the flue gases of four process industries (cement, silicon, iron & steel, and pulp & paper) via a heat recovery steam generator (HRSG). A novel approach is presented that estimates the capital and operational expenditures for waste heat recovery from process industries. The results show that the overall cost (CAPEX + OPEX) of steam generated from one hot flue gas source is in the range of 1.1–4.1 €/t steam. The cost is sensitive to economic parameters, installation factors, the overall heat transfer coefficient, steam pressure, and to the complexity of the steam network. The cost of steam from an existing natural gas boiler is roughly 5–20-times higher than that of steam generated from recovered waste heat. The CAPEX required to collect the heat is the predominant factor in the cost of steam generation from waste heat. The major contributor to the CAPEX is the heat recovery steam generator, although the length of the steam pipeline (when heat is collected from two sources or over long distances) is also important for the CAPEX.
Using sodium thiosulphate for carbon steel corrosion protection against monoethanolamine and methyldiethanolamine Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-05-10 Samara A. Sadeek, Daryl R. Williams, Kyra L. Sedransk Campbell
Corrosion resistance against amine solvent monoethanolamine (MEA) and mixtures of MEA with methyldiethanolamine (MDEA) was studied. Stainless steel (SS316L) was tested as a baseline to compare with carbon steel (C1018) alone and with the inhibitor sodium thiosulphate (STS). Immersion testing used mass change, Fe ion concentration in solution (ICP–OES), surface imaging (SEM), and analytical techniques (EDX, XRD) to assess the corrosion. Generally, the use of STS improved C1018 resilience relative to C1018 alone, though SS316L was superior to both. Multiple inhibition mechanisms were observed, and are a function of temperature and solution composition. Whilst the surface adsorption mechanism was demonstrated in some cases, reactions between solution reactants and STS resulted in different outcomes.
Modeling and simulation of CO2 capture using semipermeable elastic microcapsules Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-05-10 Justin R. Finn, Janine E. Galvin
Development of a facile reclaiming process for degraded alkanolamine and glycol solvents used for CO2 capture systems Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-05-10 Huitian Ju, Walid ElMoudir, Ahmed Aboudheir, Nader Mahinpey
The importance of shale caprock damage for well integrity Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-05-10 N. Opedal, A. Lavrov, J. Todorovic, M. Torsæter
Well integrity is crucially dependent on the bonding quality between cement and rock. Several studies have been made of this in the past, but none have taken into account that the drilled rock can be fractured and damaged during drilling. Especially a caprock fractured in the near-well zone can jeopardize well integrity. In this paper we have investigated the effect of shale caprock damage on the quality of well cement bonding to shale. Both intact and fractured rock has been cemented under realistic conditions, and the degree of the bonding (e.g. contact surface between the shale and cement) has been studied by X-ray computed tomography (CT) scanning. It was found that in the shale samples with fractured borehole, partial cement slurry penetration into the fracture network resulted in larger volume of leakage pathways than in the intact shale samples. The leakage potential through each of the samples was estimated based on connected cracks found by numerical calculations from three-dimensional (3D) reconstruction of CT data.
Development of an analytical simulation tool for storage capacity estimation of saline aquifers Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-05-08 Reza Ganjdanesh, Seyyed A. Hosseini
An enhanced analytical simulation tool (EASiTool) was developed to estimate CO2 storage capacity in saline aquifers. The tool provides a quantitative estimate of storage capacity for multi-well injection/extraction systems by applying novel analytical models for both closed- and open-boundary saline aquifers and analyzes the potential of enhancing storage efficiency by integrating active brine management (brine extraction technology). EASiTool includes a user-friendly interface and can be used to provide reservoir and basin-scale storage capacity estimates. The software and user manual are available for download at: http://www.beg.utexas.edu/gccc/EASiTool/.
A comprehensive modeling of the hybrid temperature electric swing adsorption process for CO2 capture Int. J. Greenh. Gas. Con. (IF 4.078) Pub Date : 2018-05-08 S. Lillia, D. Bonalumi, C. Grande, G. Manzolini
Adsorption technologies provide high selectivity and low energy consumption making this technique very attractive to be employed in post-combustion carbon capture. In this publication, a material made of activated carbon and zeolite 13X is considered for a hybrid process termed Temperature Electric Swing Adsorption (T/ESA). This hybrid T/ESA can work as a traditional Temperature Swing Adsorption (TSA) heated by hot gas, but can also increase the temperature of the adsorbent very fast by Joule effect as long as the activated carbon provides a continuous conductive matrix for electricity. This paper discusses a detailed modeling of the T/ESA process when applied to three cases. The first case is the simulation of the T/ESA process with exhaust with 12% of CO2 concentration, which has been chosen to validate the model against literature results. The second and third case studies consider the T/ESA application in a natural gas combined cycle (NGCC) traditional power plant, and in a NGCC plant with exhaust gas recycle (EGR). These cases were selected to investigate the adsorption technology at low CO2 concentration and quantify the benefit of the EGR for carbon capture applications. Starting from an NGCC overall electric efficiency of 58.3% LHV based, the efficiency of the NGCC with T/ESA technology reduces to 35.3% while with EGR is 38.9% against the 49.9% with the MEA absorption plant. The same results are confirmed by the SPECCA index 13.05 MJLHV/kgCO2 to 9.64 MJLHV/kgCO2 against the reference of 3.36 MJLHV/kgCO2. The energy penalty of the T/ESA is significant because of electric consumptions required for the heating and fast cooling of the adsorbent.
Some contents have been Reproduced by permission of The Royal Society of Chemistry.
- Acc. Chem. Res.
- ACS Appl. Mater. Interfaces
- ACS Biomater. Sci. Eng.
- ACS Catal.
- ACS Cent. Sci.
- ACS Chem. Biol.
- ACS Chem. Neurosci.
- ACS Comb. Sci.
- ACS Earth Space Chem.
- ACS Energy Lett.
- ACS Infect. Dis.
- ACS Macro Lett.
- ACS Med. Chem. Lett.
- ACS Nano
- ACS Omega
- ACS Photonics
- ACS Sens.
- ACS Sustainable Chem. Eng.
- ACS Synth. Biol.
- Acta Biomater.
- Acta Crystallogr. A Found. Adv.
- Acta Mater.
- Adv. Colloid Interface Sci.
- Adv. Electron. Mater.
- Adv. Energy Mater.
- Adv. Funct. Mater.
- Adv. Healthcare Mater.
- Adv. Mater.
- Adv. Mater. Interfaces
- Adv. Opt. Mater.
- Adv. Sci.
- Adv. Synth. Catal.
- AlChE J.
- Anal. Bioanal. Chem.
- Anal. Chem.
- Anal. Chim. Acta
- Anal. Methods
- Angew. Chem. Int. Ed.
- Annu. Rev. Anal. Chem.
- Annu. Rev. Biochem.
- Annu. Rev. Environ. Resour.
- Annu. Rev. Food Sci. Technol.
- Annu. Rev. Mater. Res.
- Annu. Rev. Phys. Chem.
- Appl. Catal. A Gen.
- Appl. Catal. B Environ.
- Appl. Clay. Sci.
- Appl. Energy
- Aquat. Toxicol.
- Arab. J. Chem.
- Asian J. Org. Chem.
- Atmos. Environ.
- Carbohydr. Polym.
- Catal. Commun.
- Catal. Rev. Sci. Eng.
- Catal. Sci. Technol.
- Catal. Today
- Cell Chem. Bio.
- Cem. Concr. Res.
- Ceram. Int.
- Chem. Asian J.
- Chem. Bio. Drug Des.
- Chem. Biol. Interact.
- Chem. Commun.
- Chem. Educ. Res. Pract.
- Chem. Eng. J.
- Chem. Eng. Sci.
- Chem. Eur. J.
- Chem. Mater.
- Chem. Phys.
- Chem. Phys. Lett.
- Chem. Phys. Lipids
- Chem. Rev.
- Chem. Sci.
- Chem. Soc. Rev.
- Chin. J. Chem.
- Combust. Flame
- Compos. Part A Appl. Sci. Manuf.
- Compos. Sci. Technol.
- Compr. Rev. Food Sci. Food Saf.
- Comput. Chem. Eng.
- Constr. Build. Mater.
- Coordin. Chem. Rev.
- Corros. Sci.
- Crit. Rev. Food Sci. Nutr.
- Crit. Rev. Solid State Mater. Sci.
- Cryst. Growth Des.
- Curr. Opin. Chem. Eng.
- Curr. Opin. Colloid Interface Sci.
- Curr. Opin. Environ. Sustain
- Curr. Opin. Solid State Mater. Sci.
- Ecotox. Environ. Safe.
- Electrochem. Commun.
- Electrochim. Acta
- Energy Environ. Sci.
- Energy Fuels
- Energy Storage Mater.
- Environ. Impact Assess. Rev.
- Environ. Int.
- Environ. Model. Softw.
- Environ. Pollut.
- Environ. Res.
- Environ. Sci. Policy
- Environ. Sci. Technol.
- Environ. Sci. Technol. Lett.
- Environ. Sci.: Nano
- Environ. Sci.: Processes Impacts
- Environ. Sci.: Water Res. Technol.
- Eur. J. Inorg. Chem.
- Eur. J. Med. Chem.
- Eur. J. Org. Chem.
- Eur. Polym. J.
- J. Acad. Nutr. Diet.
- J. Agric. Food Chem.
- J. Alloys Compd.
- J. Am. Ceram. Soc.
- J. Am. Chem. Soc.
- J. Am. Soc. Mass Spectrom.
- J. Anal. Appl. Pyrol.
- J. Anal. At. Spectrom.
- J. Antibiot.
- J. Catal.
- J. Chem. Educ.
- J. Chem. Eng. Data
- J. Chem. Inf. Model.
- J. Chem. Phys.
- J. Chem. Theory Comput.
- J. Chromatogr. A
- J. Chromatogr. B
- J. Clean. Prod.
- J. CO2 UTIL.
- J. Colloid Interface Sci.
- J. Comput. Chem.
- J. Cryst. Growth
- J. Dairy Sci.
- J. Electroanal. Chem.
- J. Electrochem. Soc.
- J. Environ. Manage.
- J. Eur. Ceram. Soc.
- J. Fluorine Chem.
- J. Food Drug Anal.
- J. Food Eng.
- J. Food Sci.
- J. Funct. Foods
- J. Hazard. Mater.
- J. Heterocycl. Chem.
- J. Hydrol.
- J. Ind. Eng. Chem.
- J. Inorg. Biochem.
- J. Magn. Magn. Mater.
- J. Mater. Chem. A
- J. Mater. Chem. B
- J. Mater. Chem. C
- J. Mater. Process. Tech.
- J. Mech. Behav. Biomed. Mater.
- J. Med. Chem.
- J. Membr. Sci.
- J. Mol. Catal. A Chem.
- J. Mol. Liq.
- J. Nat. Gas Sci. Eng.
- J. Nat. Prod.
- J. Nucl. Mater.
- J. Org. Chem.
- J. Photochem. Photobiol. C Photochem. Rev.
- J. Phys. Chem. A
- J. Phys. Chem. B
- J. Phys. Chem. C
- J. Phys. Chem. Lett.
- J. Polym. Sci. A Polym. Chem.
- J. Porphyr. Phthalocyanines
- J. Power Sources
- J. Solid State Chem.
- J. Taiwan Inst. Chem. E.
- Macromol. Rapid Commun.
- Mass Spectrom. Rev.
- Mater. Chem. Front.
- Mater. Des.
- Mater. Horiz.
- Mater. Lett.
- Mater. Sci. Eng. A
- Mater. Sci. Eng. R Rep.
- Mater. Today
- Meat Sci.
- Med. Chem. Commun.
- Microchem. J.
- Microchim. Acta
- Micropor. Mesopor. Mater.
- Mol. Biosyst.
- Mol. Cancer Ther.
- Mol. Catal.
- Mol. Nutr. Food Res.
- Mol. Pharmaceutics
- Mol. Syst. Des. Eng.
- Nano Energy
- Nano Lett.
- Nano Res.
- Nano Today
- Nano-Micro Lett.
- Nanomed. Nanotech. Biol. Med.
- Nanoscale Horiz.
- Nat. Catal.
- Nat. Chem.
- Nat. Chem. Biol.
- Nat. Commun.
- Nat. Energy
- Nat. Mater.
- Nat. Med.
- Nat. Methods
- Nat. Nanotech.
- Nat. Photon.
- Nat. Prod. Rep.
- Nat. Protoc.
- Nat. Rev. Chem.
- Nat. Rev. Drug. Disc.
- Nat. Rev. Mater.
- Natl. Sci. Rev.
- Neurochem. Int.
- New J. Chem.
- NPG Asia Mater.
- npj 2D Mater. Appl.
- npj Comput. Mater.
- npj Flex. Electron.
- npj Mater. Degrad.
- npj Sci. Food
- Pharmacol. Rev.
- Pharmacol. Therapeut.
- Photochem. Photobiol. Sci.
- Phys. Chem. Chem. Phys.
- Phys. Life Rev.
- PLOS ONE
- Polym. Chem.
- Polym. Degrad. Stabil.
- Polym. J.
- Polym. Rev.
- Powder Technol.
- Proc. Combust. Inst.
- Prog. Cryst. Growth Ch. Mater.
- Prog. Energy Combust. Sci.
- Prog. Mater. Sci.
- Prog. Photovoltaics
- Prog. Polym. Sci.
- Prog. Solid State Chem.
- Sci. Adv.
- Sci. Bull.
- Sci. Rep.
- Sci. Total Environ.
- Sci. Transl. Med.
- Scr. Mater.
- Sens Actuators B Chem.
- Sep. Purif. Technol.
- Small Methods
- Soft Matter
- Sol. Energy
- Sol. Energy Mater. Sol. Cells
- Solar RRL
- Spectrochim. Acta. A Mol. Biomol. Spectrosc.
- Surf. Sci. Rep.
- Sustainable Energy Fuels