CO2 Breakthrough Time Research Articles

Breakthrough curves of H2/CO2 adsorptions on CuBTC and MIL-125(Ti)_NH2 predicted by empirical correlations and deep neural networks

With the continuous emergence of new materials, efficiently screening suitable materials for hydrogen purification by pressure swing adsorption (PSA) technology has become a hot topic. Metal-organic frameworks (MOFs) hold significant promise in gas adsorption and separation due to their unique structure and versatility. Breakthrough curves depict the dynamic adsorption kinetics of multi-components in fixed-bed columns, offering a means to screen adsorbents. In this study, a deep neural network (DNN) model comprising 11 hidden layers is developed to predict the dynamic breakthrough behavior of MOF CuBTC and MIL-125(Ti)_NH2 adsorbents. The training data for the DNN were generated from a non-isothermal model established using Aspen Adsorption software. Results demonstrate that the DNN model effectively predicts the H2/CO2 breakthrough behavior on CuBTC and MIL-125(Ti)_NH2 adsorbents. Compared with empirical mathematical correlation models, the DNN can predict breakthrough profiles under varying operating conditions, exhibiting superior adaptability. Furthermore, parametric studies based on the DNN model reveal that initial temperature, adsorption pressure and feed flow rate play important roles in the dynamic adsorption process, significantly influencing the position and shape of the breakthrough curve. Decreasing the feed flow rate and initial temperature while increasing adsorption pressure can enhance breakthrough times and hydrogen purity. By comparing the breakthrough curves of the two adsorbents under different operating conditions for H2/CO2, the dimensionless breakthrough time of CO2 on the CuBTC adsorbent was longer. Additionally, simulation results of the PSA cycle suggest that CuBTC yields higher hydrogen purity than MIL-125(Ti)_NH2. Consequently, CuBTC is deemed more suitable for hydrogen purification of binary H2/CO2 mixtures than MIL-125(Ti)_NH2.

CO2 injection-based enhanced methane recovery from carbonate gas reservoirs via deep learning

CO2 injection is a promising technology for enhancing gas recovery (CO2-EGR) that concomitantly reduces carbon emissions and aids the energy transition, although it has not yet been applied commercially at the field scale. We develop an innovative workflow using raw data to provide an effective approach in evaluating CH4 recovery during CO2-EGR. A well-calibrated three-dimensional geological model is generated and validated using actual field data—achieving a robust alignment between history and simulation. We visualize the spread of the CO2 plume and quantitatively evaluate the dynamic productivity to the single gas well. We use three deep learning algorithms to predict the time histories of CO2 rate and CH4 recovery and provide feedback on production wells across various injection systems. The results indicate that CO2 injection can enhance CH4 recovery in water-bearing gas reservoirs—CH4 recovery increases with injection rate escalating. Specifically, the increased injection rate diminishes CO2 breakthrough time while concurrently expanding the swept area. The increased injection rate reduces CO2 breakthrough time and increases the swept area. Deep learning algorithms exhibit superior predictive performance, with the gated recurrent unit model being the most reliable and fastest among the three algorithms, particularly when accommodating injection and production time series, as evidenced by its smallest values for evaluation metrics. This study provides an efficient method for predicting the dynamic productivity before and after CO2 injection, which exhibits a speedup that is 3–4 orders of magnitudes higher than traditional numerical simulation. Such models show promise in advancing the practical application of CO2-EGR technology in gas reservoir development.

Mathematical modeling of mass transfer in CO2 injection for confined fluids at near-miscible condition

Complex interaction between fluid and solid in tight formations leads to capillary confinement and interface slip. Mass transfer between oil and CO2 in CO2 flooding is essential to understand the flow complexity. Therefore, the objective of this work is to propose a comprehensive model to analyze the mass transfer during CO2 injection in the confined fluids. The modified Peng-Robinson equation of state considering the fluid-wall interaction and adsorption was established to calculate the properties of hydrocarbons and CO2. Relative permeability for the near-miscible state was then estimated using the new relative permeability model with corner flow effect. Predicted results agree well with the experimental observations. Afterwards, it was integrated with a one-dimension mathematical model to analyze the physical mechanisms of CO2 flooding in tight reservoirs. Results indicate that nanoconfinement increases the relative permeability at near-miscible condition, and confined fluid is more likely to be miscible than the bulk fluid. Additionally, nanoconfinement can reduce the velocity of CO2 front and increase the breakthrough time of CO2, which is favorable to improve the efficiency of CO2 flooding. This model provides a deep understanding of mass transfer between CO2 and hydrocarbons, and it can be integrated with compositional simulators to solve the field-scale cases including the microscale mechanism of tight reservoirs.

An application of a genetic algorithm in co-optimization of geological CO2 storage based on artificial neural networks

Abstract Global warming, driven by human-induced disruptions to the natural carbon dioxide (CO2) cycle, is a pressing concern. To mitigate this, carbon capture and storage has emerged as a key strategy that enables the continued use of fossil fuels while transitioning to cleaner energy sources. Deep saline aquifers are of particular interest due to their substantial CO2 storage potential, often located near fossil fuel reservoirs. In this study, a deep saline aquifer model with a saline water production well was constructed to develop the optimization workflow. Due to the time-consuming nature of each realization of the numerical simulation, we introduce a surrogate aquifer model derived from extracted data. The novelty of our work lies in the pioneering of simultaneous optimization using machine learning within an integrated framework. Unlike previous studies, which typically focused on single-parameter optimization, our research addresses this gap by performing multi-objective optimization for CO2 storage and breakthrough time in deep saline aquifers using a data-driven model. Our methodology encompasses preprocessing and feature selection, identifying eight pivotal parameters. Evaluation metrics include root mean square error (RMSE), mean absolute percentage error (MAPE) and R2. In predicting CO2 storage values, RMSE, MAPE and R2 in test data were 2.07%, 1.52% and 0.99, respectively, while in blind data, they were 2.5%, 2.05% and 0.99. For the CO2 breakthrough time, RMSE, MAPE and R2 in the test data were 2.1%, 1.77% and 0.93, while in the blind data they were 2.8%, 2.23% and 0.92, respectively. In addressing the substantial computational demands and time-consuming nature of coupling a numerical simulator with an optimization algorithm, we have adopted a strategy in which the trained artificial neural network is seamlessly integrated with a multi-objective genetic algorithm. Within this framework, we conducted 5000 comprehensive experiments to rigorously validate the development of the Pareto front, highlighting the depth of our computational approach. The findings of the study promise insights into the interplay between CO2 breakthrough time and storage in aquifer-based carbon capture and storage processes within an integrated framework based on data-driven coupled multi-objective optimization.

Green synthesis approach using deep eutectic solvents to enhance the surface functional groups on porous carbon for CO2 capture

This study explores the potential of green solvents using amino acids-based deep eutectic solvents to alter surface functionality of activated carbon thus enhancing the carbon dioxide (CO2) adsorption capacity. Green solvent is prepared by mixing an amino acid (L-Arginine) with ethylene glycol to form amino acid-based deep eutectic solvents. Amino acid-based deep eutectic solvents were used to modify the surface functionalities of activated carbon derived from palm shell waste. The change in surface functional groups and surface morphology of the modified activated carbon samples were characterized by Fourier-transform infrared spectroscopy and Scanning electron microscopy-energy dispersive X-ray analysis. Then, CO2 removal performance was performed using a packed-bed CO2 adsorption reactor to evaluate CO2 breakthrough time and adsorption capacity. CO2 adsorption experiments were measured at a certain temperature (25–45°C), at a fixed feed flow rate and CO2 concentration of 200 mL/min and 15%. It was observed that modified activated carbon showed the highest breakthrough time (15.2 min) compared to raw palm shell (5.2 min) at an adsorption temperature of 25°C. CO2 breakthrough times significantly decreased with increasing adsorption temperature because of physical adsorption.

Study on SiO2 Nanofluid Alternating CO2 Enhanced Oil Recovery in Low-Permeability Sandstone Reservoirs

Water alternating gas (WAG) flooding is a widely employed enhanced oil recovery method in various reservoirs worldwide. In this research, we will employ SiO2 nanofluid alternating with the CO2 injection method as a replacement for the conventional WAG process in oil flooding experiments. The conventional WAG method suffers from limitations in certain industrial applications, such as extended cycle times, susceptibility to water condensation and agglomeration, and ineffectiveness in low-permeability oil reservoirs, thus impeding the oil recovery factor. In order to solve these problems, this study introduces SiO2 nanofluid as a substitute medium and proposes a SiO2 nanofluid alternate CO2 flooding method to enhance oil recovery. Through the microcharacterization of SiO2 nanofluids, comprehensive evaluations of particle size, dispersibility, and emulsification performance were conducted. The experimental results revealed that both SiO2-I and SiO2-II nanoparticles exhibited uniform spherical morphology, with particle sizes measuring 10–20 nm and 50–60 nm, respectively. The SiO2 nanofluid formulations demonstrated excellent stability and emulsification properties, highlighting their potential utility in petroleum-related applications. Compared with other conventional oil flooding methods, the nanofluid alternating CO2 flooding effect is better, and the oil flooding effect of smaller nanoparticles is the best. Nanofluids exhibit wetting modification effects on sandstone surfaces, transforming their surface wettability from oil-wet to water-wet. This alteration reduces adhesion forces and enhances oil mobility, thereby facilitating improved fluid flow in the rock matrix. In the oil flooding experiments with different slug sizes, smaller gas and water slug sizes can delay the breakthrough time of nanofluids and CO2, thereby enhancing the effectiveness of nanofluid alternate CO2 flooding for EOR. Among them, a slug size of 0.1 PV approaches optimal performance, and further reducing the slug size has limited impact on improving the development efficiency. In oil flooding experiments with different slug ratios, the optimal slug ratio is found to be 1:1. Additionally, in oil flooding experiments using rock cores with varying permeability, lower permeability rock cores demonstrate higher oil recovery rates.

CO2 Injection for Enhanced Gas Recovery and Geo-Storage in Complex Tight Sandstone Gas Reservoirs

With the popularization of natural gas and the requirements for environmental protection, the development and utilization of natural gas is particularly important. The status of natural gas in China’s oil and gas exploration and development is constantly improving, and the country is paying more and more attention to the exploitation and utilization of natural gas. The Upper Paleozoic tight sandstone in the Ordos Basin is characterized by low porosity, low permeability and a large area of concealed gas reservoirs. By injecting carbon dioxide into the formation, the recovery rate of natural gas can be improved, and carbon neutrality can be realized by carbon sequestration. Injecting greenhouse gases into gas reservoirs for storage and improving recovery has also become a hot research issue. In order to improve the recovery efficiency of tight sandstone gas reservoirs, this paper takes the complex tight sandstone of the Upper Paleozoic in the Ordos Basin as the research object; through indoor physical simulation experiments, carried out the influence of displacement rate, fracture dip angle, core permeability, core dryness and wetness on CO2 gas displacement efficiency and storage efficiency; and analyzed the influence of different factors on gas displacement efficiency and storage efficiency to improve the recovery and storage efficiency. The research results show that under different conditions, when the injection pore volume is less than 1 PV, the relationship between the CH4 recovery rate and the CO2 injection pore volume is linear, and the tilt angle is 45°. When the injection pore volume exceeds 1 PV, the CH4 recovery rate increases slightly with the increase in displacement speed, the recovery rate of CO2 displacement CH4 is between 87–97% and the CO2 breakthrough time is 0.7 PV–0.9 PV. In low-permeability and low-speed displacement cores, the diffusion of carbon dioxide molecules is more significant. The lower the displacement speed is, the earlier the breakthrough time is, and the final recovery of CH4 slightly decreases. Gravity has a great impact on carbon sequestration and enhanced recovery. The breakthrough of high injection and low recovery is earlier, and the recovery of CH4 is about 3.3% lower than that of low injection and high recovery. The bound water causes the displacement phase CO2 to be partially dissolved in the formation water, and the breakthrough lags about 0.1 PV. Ultimately, the CH4 recovery factor and CO2 storage rate are higher than those of dry-core displacement. The research results provide theoretical data support for CO2 injection to improve recovery and storage efficiency in complex tight sandstone gas reservoirs.

A Numerical Simulation Study of Temperature and Pressure Effects on the Breakthrough Pressure of CO2 in Unsaturated Low‐permeability Rock Core

AbstractGas breakthrough pressure is a key parameter to evaluate the sealing capacity of caprock, and it also plays important roles in safety and capacity of CO2 geological storage. Based on the published experimental results, we present numerical simulations on CO2 breakthrough pressure in unsaturated low‐permeability rock under 9 multiple P‐T conditions (which can keep CO2 in gaseous, liquid and supercritical states) and thus, a numerical method which can be used to accurately predict CO2 breakthrough pressure on rock‐core scale is proposed. The simulation results show that CO2 breakthrough pressure and breakthrough time are exponential correlated with P‐T conditions. Meanwhile, pressure has stronger effects on experimental results than that of temperature. Moreover, we performed sensitivity studies on the pore distribution index λ (0.6, 0.7, 0.8, and 0.9) in van Genuchten‐Muale model. Results show that with the increase of λ, CO2 breakthrough pressure and breakthrough time both show decreasing trends. In other words, the larger the value of λ is, the better the permeability of the caprock is, and the worse the CO2 sealing capacity is. The numerical method established in this study can provide an important reference for the prediction of gas breakthrough pressure on rock‐core scale and for related numerical studies.

Novel Approach to Enhancing Tight Oil Recovery Using N2-Assisted CO2 Flooding and Its Potential for CO2 Storage

Four types of gas injection experiments─CO2 flooding, N2 flooding, alternating CO2 and N2 flooding, and CO2 pre-slug N2 flooding─were conducted in a 28.42 cm long core plug to study the production performances of a CO2 and N2 flooding model in enhancing the tight oil flooding efficiency. Experimental results indicate that the following. (1) For CO2 and N2 flooding, the highest tight oil flooding efficiency is achieved at a gas injection rate of 0.10 mL/min, with a CO2 flooding efficiency of 68.75%, a gas breakthrough time of 0.33 PV, a CO2 utilization of 11.35 Mscf/stb, an N2 flooding efficiency of 38.46%, and a gas breakthrough time of 0.42 PV. (2) For alternating CO2 and N2 flooding, the highest tight oil flooding efficiency is 56%, and the CO2 utilization is 7.97 Mscf/stb. (3) The highest tight oil flooding efficiency is 53.08% for CO2 pre-slug N2 flooding. A comparison of the experimental results indicates that a larger CO2 slug leads to a higher oil flooding efficiency. The CO2 plug size has less influence on the recovery rate before breakthrough. The larger the CO2 plug after breakthrough, the higher the recovery rate. The optimized N2 injection time is the CO2 breakthrough time (0.33 PV). In the optimized case, flooding efficiency and contribution indicate the optimal CO2 slug size at 0.50 PV. When pure CO2 is injected at 0.50 PV and the gas is switched to N2, the recovery is 5.82%, and the contribution is 9.20%. When pure CO2 is injected at 0.50 PV, followed by the continuous injection of pure CO2, the recovery rate is 8.59% and the contribution rate is 12.49%. The difference between the recovery rates of the two methods is small, so the best injection timing for N2 is 0.17 PV after CO2 breakthrough, and the oil flooding efficiency is 63.27%.

Improvement in CO2 geo-sequestration in saline aquifers by viscosification: From molecular scale to core scale

Carbon dioxide (CO2) storage in the subsurface is a viable approach to mitigate climate change by reducing anthropogenic greenhouse gas emissions. The unfavorable mobility ratio in brine displacement by CO2 would lead to poor sweep efficiency. In this investigation, the efficiency of an engineered CO2 oligomer viscosifier with about twenty repeat units of 1-decene is evaluated in mobility control and sweep efficiency improvement in drainage. We have performed brine displacement experiments in sandstone rock with supercritical CO2. The viscosifier at 1.5 wt% concentration increases the viscosity of supercritical CO2 by 4.8 folds at pressure of 3500 psi and temperature of 194 ˚F. We observe significant delay of CO2 breakthrough time by 2.6 ± 0.1 folds in a large number of experiments by viscosified CO2. The molecule does not have appreciable adsorption on the rock surface. The pressure drop from displacement of neat CO2 by viscosified CO2 at 1 PV injection provides the evidence of low adsorption. Molecular simulations are conducted to investigate adsorption. Low adsorption is a key measure of the effectiveness of the molecule. The results from molecular simulations agree with the experiments. In addition to viscosification, the novelty of the molecule is that there is a significant decrease in the residual brine saturation. Consequently, the residual trapping is also increased. The combination of decrease in residual brine saturation, and mobility control are expected to significantly improve the storage capacity through increase in residual trapping and sweep efficiency in CO2 storage in saline aquifers. As a result, CO2 storage may become more efficient.

Synthesis of grape-seed derived carbon with high specific surface area for CO2 selective adsorption

Nitrogen-doped porous carbons with BET surface area of 1068.2–3314.5 m2/g and nitrogen contents of 3.2–6.5% were prepared with solid waste grape-seed as raw material, NaNH2 as activator and nitrogen source at low activation temperature. Super The activation mechanism of NaNH2 on hydrothermal carbon precursors was first explored by thermodynamic analysis and TG-IR, which provided theoretical support for pore forming of carbon materials. Maximum CO2 and CH4 adsorption capacity at 273 K and pressure of 101 kPa was 5.42 and 1.76 mmol g−1 respectively, which are higher than those of majority of carbon derived from most solid wastes reported in literature. IAST selectivities of GS-3-450 with the largest BET surface area for CO2/CH4 (40v/60v), CO2/N2 (15v/85v), CH4/N2 (50v/50v) were found to be 20.3, 71.4, 6.0 under 101 kPa and 298 K respectively. The competitive adsorption of GS-3-450 for CO2/CH4 (40v/60v), CO2/N2 (15v/85v), CH4/N2 (50v/50v) gases mixture were examined through breakthrough experiments, and the results showed that the breakthrough time of CO2 was longer than that of CH4 and N2, which was beneficial to the separation of CO2 from gases mixture. Eight cycles of CH4 adsorption–desorption studies revealed that the material exhibited excellent recycling stability. Low temperature preparation method, excellent BET specific surface area and total pore volume, as well as excellent adsorption ability of CO2 and CH4 make it have a very great potential for the capture of CO2 and CH4.

The potential of direct air capture using adsorbents in cold climates.

Global warming threatens the entire planet, and solutions such as direct air capture (DAC) can be used to meet net-zero goals and go beyond. This study investigates using DAC in a 5-step temperature vacuum swing adsorption (TVSA) cycle with adsorbents' Li-X and Na-X, readily available industrial zeolites, to capture and concentrate CO2 from air in cold climates. From this study, we report that Na-X in cold conditions has the highest known CO2 adsorption capacity in air of 2.54mmol/g. This combined with Na-X's low CO2 heat of adsorption, and fast uptake-rate in comparison to other benchmark materials, allowed for Na-X operating in cold conditions to have the lowest reported DAC operating energy of 1.1 MWh/tonCO2. These findings from this study show the promise of this process in cold climates of Canada, Alaska, Greenland, and Antarctica to be part of the solution to global warming.

Study on the Ways to Improve the CO2-H2O Displacement Efficiency in Heterogeneous Porous Media by Lattice Boltzmann Simulation.

To improve the efficiency of CO2 geological sequestration, it is of great significance to in-depth study the physical mechanism of the immiscible CO2–water displacement process, where the influential factors can be divided into fluid–fluid and fluid–solid interactions and porous media characteristics. Based on the previous studies of the interfacial tension (capillary number) and viscosity ratio factors, we conduct a thorough study about the effects of fluid–solid interaction (i.e., wettability) and porous media characteristics (i.e., porosity and non-uniformity of granule size) on the two-phase displacement process by constructing porous media with various structural parameters and using a multiphase lattice Boltzmann method. The displacement efficiency of CO2 is evaluated by the breakthrough time characterizing the displacement speed and the quasi-steady state saturation representing the displacement amount. It is shown that the breakthrough time of CO2 becomes longer, but the quasi-steady state saturation increases markedly with the increase in CO2 wettability with the surface, demonstrating an overall improvement of the displacement efficiency. Furthermore, the breakthrough time of CO2 shortens and the saturation increases significantly with increasing porosity, granule size, and non-uniformity, showing the improvement of the displacement efficiency. Therefore, enhancing the wettability of CO2 with the surface and selecting reservoirs with greater porosity, larger granule size, and non-uniformity can all contribute to the efficiency improvement of CO2 geological sequestration.

Amine and fluorine co-functionalized MIL-101(Cr) synthesized via a mixed-ligand strategy for CO2 capture under humid conditions

The selective capture of CO2 in humid conditions on metal–organic frameworks is challenging due to competitive adsorption of H2O and CO2 on the active sites. Herein, amine and fluorine co-functionalized MIL-101(Cr) was synthesized and evaluated for use as CO2 adsorbent to overcome this issue. MIL-101(Cr)–NH2-F0.5 (CrA-F0.5) was prepared using a mixed-ligand strategy, and contains 2.9% nitrogen and 0.5% fluorine while maintaining the MIL-101(Cr) structure. Numerically, one 4F ligand per 20 amino ligands was included in the CrA-F0.5 structure. The calculated selectivity for CO2/N2 of CrA-F0.5 is 108 (CO2/N2 = 15/85) at 20 ℃ and 1 bar, and this value was 3.7 and 2.1 times higher than that of MIL-101(Cr) and MIL-101(Cr)–NH2, respectively. The results of CrA-F0.5 adsorption of CO2 indicated that amine and fluorine groups served as adsorptive sites for CO2 in this structure. The moderate isosteric heat of CO2 adsorption value (45 kJ mol−1) of CrA-F0.5 merits in desorption of CO2. The result of a hydrophobicity index test, indicated that CrA-F0.5 was 2.5 times hydrophobic than MIL-101(Cr)–NH2. In a CO2 and N2 breakthrough test, compared to the dry condition, the CO2 breakthrough time at 30 ℃ and 1 bar was reduced by 40% for MIL-101(Cr)–NH2 and by 10% for CrA-F0.5 in 60% relative humidity. The CO2 and N2 breakthrough results under humid conditions were consistent with the hydrophobicity index value, and the excellent water repellency of CrA-F0.5 was confirmed. CrA-F0.5 is considered a candidate suitable for CO2 adsorbent in an actual post-combustion CO2 adsorption process.

Quantitative investigation of phase characteristic effects on CO2 breakthrough pressures in unsaturated Low-Permeability sandstone

Study on CO2 breakthrough pressures in caprocks under formation temperatures (T) and pressures (P), which can make CO2 in gaseous, liquid and supercritical states, are vital to the seal ability of caprocks for CO2 sequestration. Laboratory testing is necessary to obtain breakthrough pressures as there is no in situ method to accurately estimate the factors that can affect its variability. In this study, we use the step-by-step method to study CO2 breakthrough pressures in unsaturated low-permeability sandstone, and carried out 9 cases of CO2 breakthrough pressure experiments under multiple P-T conditions that can make CO2 in gaseous, liquid and supercritical states, respectively. The variation of CO2 breakthrough pressures (Pbt) were analyzed based on 4 properties of multi-phase flow: CO2-H2O interfacial tension (γ), CO2-H2O-rock wettability, CO2-H2O viscosity ratio (M), and CO2-H2O density difference. The results show that CO2 breakthrough pressure and breakthrough time are positively correlated with experimental temperatures and pressures. The main property affecting CO2 breakthrough pressures is the CO2-H2O viscosity ratio, which is more affected by the P-T conditions (or CO2 phase). Moreover, the breakthrough pressures of CO2 under 9 groups of multiple P-T conditions (which can make CO2 in various phases) is Supercritical CO2 > Liquid CO2 > Gaseous CO2. This study has important guiding significance for the selection of target caprock for CO2 geo-sequestration.

Numerical Simulation and Optimization of CO2-Enhanced Gas Recovery in Homogeneous and Vertical Heterogeneous Reservoir Models

Abstract CO2-enhanced gas recovery (CO2-EGR) is a promising, environment-friendly technology to produce more natural gas from depleted reservoirs and simultaneously sequester CO2. The subsurface flow in the heterogeneous reservoir is usually different from homogenous one, and the heterogeneity significantly affects the gas recovery. The effects of heterogeneity and the optimization of CO2 injection strategy are the key factors in CO2-EGR. Thus, one of the goals of this paper is to conduct simulations of CO2-EGR in both homogeneous and heterogeneous reservoirs to evaluate the effects of reservoir heterogeneity on CO2-EGR. The second goal is to perform optimization studies to determine optimal CO2 injection time and injection rate for achieving optimal natural gas recovery. The CO2-EGR simulations were conducted in a 3D reservoir model with a 'five-spot' well pattern by using the multi-phase simulator TOUGH2. The results show that the layers with low permeability as well as gravity segregation retard upward migration of CO2 and promote horizontal displacement efficiency. The breakthrough time of CO2 and reservoir space of underexploited natural gas directly affect the gas recovery. The optimal injection time is determined as the depleted stage, and the corresponding injection rate is optimized by using a genetic algorithm (GA) integrated with TOUGH2. The optimization of CO2 injection parameters leads to recovery factors (RFs) reaching 62.83% and 64.75% in the homogeneous and heterogeneous cases while simultaneously obtaining the economic benefit of about 8.67 and 8.95 million USD. This study shows significant economic potential as well as environmental benefits of using CO2-EGR in the depleted gas reservoir by optimizing the CO2 injection parameters. The findings of this work could assist in determining the optimal injection strategy for using CO2-EGR in industrial scale gas reservoirs.

Coupled optimization of carbon dioxide sequestration and CO2 enhanced oil recovery

CO2 injection into hydrocarbon reservoirs can simultaneously pave the path for two important processes, namely oil production increase, and CO2 storage. This combined optimization problem can be referred to as carbon capture and storage - enhanced oil recovery (CCS-EOR) problem. CCS-EOR is a challenging task with many opportunities which should be studied in a timely manner. Moreover, the attitude of the management team towards prioritizing CCS or EOR should be considered. Therefore, in the current study, CCS-EOR problem was addressed by utilizing the dynamic well flow settings (bottom-hole pressure and/or flow rate) as the optimization variables with a weighted objective function. This approach was tested on a case study. Its huge simulation time due to high dimensionality remained a serious challenge. One effective approach was to use the underlying applied knowledge of the system and extract that wisdom to reduce the simulation time in a rational manner. CO2 breakthrough time was such a knowledge. Therefore, the importance of CO2 breakthrough time was stressed, and the understanding of the response of the simulator to this event was used to considerably reduce the simulation time in a black box approach. Moreover, a concise sensitivity analysis was performed which helped to schedule the workflow based on the given priority to each process. The optimized case could improve the objective value and gas storage efficiency up to 2.86 % and 12.1 % respectively. The obtained results can be used to analyze a variety of operational matters such as the CO2 distribution map in the reservoir, and the well settings.

A review of research on the dispersion process and CO2 enhanced natural gas recovery in depleted gas reservoir

The dispersion coefficient is a key physical parameter for enhanced gas recovery (EGR) and reflects the degree of mixing between the displacing-fluid CO2 and natural gas. However, no comprehensive overview of existing research on EGR dispersion characteristics has been conducted to date. In this review article, previous experimental and simulation studies are summarized to provide an overview of the current research progress and, hence, to elucidate the limitations of EGR and identify directions for future research. The literature analysis reveals that temperature and flow rate promote CO2–CH4 dispersion, whereas pressure and residual-water salinity inhibit dispersion under supercritical conditions. The CO2–CH4 dispersion coefficient is smaller in porous media with high permeability. However, on the core scale, the effects of residual water on the CO2 dispersion and breakthrough time are controversial and further verification is required. To date, only limited research has been conducted on the effects of impurities under supercritical conditions, such as considering CO2 containing N2, and CH4 containing CO2, N2 and ethane. Existing pilot EGR trials are insufficient to provide standardized field operation instructions, for example, with regard to the wellhead layout. Field-scale simulations have verified the feasibility of EGR technology and economy. However, factors such as the permeability heterogeneity, initial water saturation distribution, connate water salinity, gas-reservoir non-isothermal conditions, and vertical stratification should be considered in simulations of actual gas reservoirs. More in-depth experimental and simulation-based investigations of EGR should be performed on various scales to accurately assess the dispersion characteristics and natural-gas recovery efficiency under gas-reservoir conditions.

Potential of CO2-enhanced oil recovery coupled with carbon capture and storage in mitigating greenhouse gas emissions in the UAE

The potential of adopting CO2-Enhanced Oil Recovery (EOR) coupled with Carbon Capture and Storage (CCS) at a large scale is significant for major oil exporters like the United Arab Emirates. We develop a system dynamics model of the interactions between the demand of CO2-EOR to sustain oil output as reservoirs age, the country's production targets, and the required carbon prices to accelerate the adoption of CO2-EOR with CCS. We simulate 12 scenarios that represents different pathways for oil production, CO2 emissions growth and performance of CO2-EOR. The scenarios consider the sensitivity to key parameters: net utilization factor of CO2 for the marginal barrel of oil produced, the time it takes for injected CO2 to reach the production well (breakthrough time), and the share of EOR wells going to CO2-EOR operation. We find that a carbon price of 10–15 $/t CO2 in the first decade is needed in order to offset the cost of the CCS operations with the potential of breaking even by 2030. The large-scale adoption of CO2-EOR with CCS in the UAE can help in meeting 2.2–39.2% of the UAE 2nd national committed reduction target, i.e., 72.85 million tons of CO2 reduction per year by 2030, depending on CO2 breakthrough time and its net utilization factor. It may also help in freeing natural gas that could supply 12–20% of local energy needs extending its use with the CCS system. This study demonstrates a systematic modeling approach that quantifies complex interactions at the system level towards cleaner production practices.

Amino-functionalized ZIFs-based porous liquids with low viscosity for efficient low-pressure CO2 capture and CO2/N2 separation

Construct permanent porosity into liquids remains challenging, such as preparation, lower viscosity, economical, high-performance gas sorption, and separation. Herein, a general and economical surface engineering strategy has been implemented to construct a novel type Ⅰ porous liquids based on zeolitic imidazolate frameworks (denoted as ZIFs-based PLs) via covalently linking of amino-functionalized ZIFs with the diglycidyl ether-terminated of PDMS. The properties including free pore volume, viscosity, melting temperature (Tm), the gas capture, and CO2/N2 selective separation performance of PLs can be regulated by adjusting the pore structures, the amount of –NH2 introduced into ZIFs and molecular weight of the outer layers of PDMS, etc. Particularly, PLs1(1000)-5%, and PLs2(1000)-5% present viscosity values with 49 mPa⋅S-1 and 59 mPa⋅S-1 at 25 °C, to our best knowledge, which is the lowest viscosity of type I PLs reported previously. Meanwhile, Tm of PLs broke down to −78 °C, showing a wide liquid range. Remarkably, type Ⅰ PLs1(14000)-15.5% exhibits approximately 10 times higher CO2 uptake than that of the polymer in outer layers, which is attributed to the permanent free volume of ZIFs, chemistry sorption, and excellent liquidity. The CO2 breakthrough time of PLs for the CO2/N2 mixture was delayed for 53.7 s, confirming that PLs exhibits efficient CO2/N2 separation performance. Therefore, we envision that such a general and economical strategy will open new insights to construct innovative low viscosity type Ⅰ PLs with high-performance CO2 capture and CO2/N2 separation at low pressure.