Displacement Of CO2 Research Articles

CO2 storage in saline aquifers: A simulation on quantifying the impact of permeability heterogeneity

As one promising technology to mitigate CO2 emission, CO2 capture utilization and storage (CCUS) plays a crucial role in achieving carbon neutrality. The deep saline aquifer is a prime candidate for CO2 geological storage. The subsurface flow and effectiveness of CO2 storage in deep saline aquifer are highly related to the permeability heterogeneity of formations, which needs in-depth study. To bridge the gap, this study focused on quantifying the impact of permeability heterogeneity on the CO2 flow patterns, the well injectivity and the storage efficiency, which aims to enhance the understanding of CO2 storage characteristics in deep saline aquifers. The heterogeneous saline aquifer model was built by using the Sequential Gaussian Simulation (SGSIM) method. A novel classification template was proposed with the CO2 flow patterns classified as “Dispersive”, “Sweeping”, “Fingering”, and “Channeling” for CO2 storage in deep saline aquifers according to the geostatistical parameters (including dimensionless correlation lengths, first and second spatial moment, and Dykstra-Parsons coefficient). For the well injectivity, the results showed that high injectivity occurred when both horizontal and vertical correlation lengths were high or at a favourable connectivity of permeability in the horizontal and vertical directions. In addition, CO2 storage efficiency is higher when both dimensionless horizontal and vertical correlation lengths are in the range of 0.1–0.2. This is because frequent changes between high and low permeability regions led to frequent mutual displacement of water and CO2, resulting in higher residual trapping and slow CO2 front. Therefore, the dimensionless correlation lengths and breakthrough time should be considered simultaneously to achieve safer trapping and maximize the CO2 storage capacity. The findings of this work provide insights into the subsurface flow of CO2 storage in deep saline aquifers with permeability heterogeneity.

CO2-brine interface evolution and corresponding overpressure in high-gravity CO2 storage complex

Technical and economic feasibility of large-scale CO2 geological storage projects (GCS) requires storing the maximum possible amounts of CO2 within a given pore space. However, one limitation is attributed to the overpressure that accompanies CO2 injection. Specifically, reliable estimation of the bottom-hole pressure during CO2 injection is essential to optimize the storage potential of the formation while ensuring the integrity of the rock. Several studies presented analytical/semi-analytical solutions to predict the overpressure accompanying CO2 injection. Nevertheless, they neglect the effects of gravity override on the temporal evolution of the plume and/or the bottom-hole pressure. Effects of gravity can be quantified by the dimensionless group “gravity number” which measures the relative importance of the gravitational-to-viscous forces within system. A lower gravity number expresses a more uniform/cylindrical displacement of CO2. Conversely, biasness of CO2 flow towards the top of the injection zone translates to a larger gravity number. The main objective of this work is to develop an analytical model able to predict the bottom-hole pressure during CO2 injection through a vertical well centered in the middle of a high-gravity thick saline aquifer. While accounting for the effects of gravity, the proposed solution will be developed assuming vertical equilibrium of pressure with a sharp interface separating the injected CO2 and the in-situ brine. First, we develop a closed-form analytical solution to estimate the evolution of CO2/brine interface considering strong gravity effects. The closed-form solution is based on extending the semi-analytical and/or the iterative expressions previously derived in the literature to predict the evolution of the plume during the injection period. Then, the interface model will be coupled with the assumption of the vertical equilibrium to obtain an analytical solution for the pressure field during injection. Next, the proposed solution for the evolution of pressure will be validated against numerical simulations for cases covering wide and practical ranges of gravity numbers and mobility ratios. The solution will be also validated against real field data to determine its robustness. Predictions of the overpressure from our analytical solution indicate a reasonable agreement with the simulations performed using a more complicated multi-phase flow simulator.

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.

Experimental Study on the Hydraulic Fracture Propagation in Inter-Salt Shale Oil Reservoirs

In response to the difficulty of fracture modification in inter-salt shale reservoirs and the unknown pattern of hydraulic fracture expansion, corresponding physical model experiments were conducted to systematically study the effects of fracturing fluid viscosity, ground stress and pumping displacement on hydraulic fracture expansion, and the latest supercritical CO2 fracturing fluid was introduced. The test results show the following. (1) The hydraulic fractures turn and expand when they encounter the weak surface of the laminae. The fracture pressure gradually increases with the increase in fracturing fluid viscosity, while the fracture pressure of supercritical CO2 is the largest and the fracture width is significantly lower than the other two fracturing fluids due to the high permeability and poor sand-carrying property. (2) Compared with the other two conventional fracturing fluids, under the condition of supercritical CO2 fracturing fluid, the increase in ground stress leads to the increase in inter-salt. (3) Compared with the other two conventional fracturing fluids, under the conditions of supercritical CO2 fracturing fluid, the fracture toughness of shale increases, the fracture pressure increases, and the fracture network complexity decreases as well. (4) With the increase in pumping displacement, the fracture network complexity increases, while the increase in the displacement of supercritical CO2 due to high permeability leads to the rapid penetration of inter-salt shale hydraulic fractures to the surface of the specimen to form a pressure relief zone; it is difficult to create more fractures with the continued injection of the fracturing fluid, and the fracture network complexity decreases instead.

Modelling CO2 plume spreading in highly heterogeneous rocks with anisotropic, rate-dependent saturation functions: A field-data based numeric simulation study of Otway

In this field-data-based simulation study, we apply novel rate-dependent, anisotropic saturation functions curve-fitted to match the flow behaviour of laminated sand- and siltstones from the CO2CRC's Otway International Test Centre (Australia), in well-spot simulations of plume spreading at the site. Scenario analysis is conducted by performing simulations on various stochastic model realisations under different conditions, investigating what controls plume migration. Results indicate that high-permeability streaks and intraformational baffles determine plume spreading in flat-lying stratigraphy. Displacement of CO2 is unstable and focussed by high-permeability streaks, leading to multi-layer plumes. In inclined stratigraphy, buoyancy forces control plume migration channelling it up dip. However, high-permeability streaks still influence plume shape. Comparisons for different injection rates show that heterogeneity-induced fingering dominates at high injection rates, whereas gravity override and vertical movement of the plume are prominent at low injection rates. Continuous build-up of fluid pressure in the storage horizon influences the properties of CO2 when no-flow (closed) lateral boundary conditions are applied. By contrast, a marked pressure drop occurs in the near-well region for hydrostatic (open) lateral boundary conditions. These also foster uneven heterogeneity-fingering of the plume. Since flow velocity in the highly heterogeneous Paaratte formation varies over many orders of magnitude, force balances range between the capillary and the viscous limit even at some distance to the injector. A comparison with simulations based on standard Brooks-Corey saturation functions shows that taking flow-rate dependence and anisotropy into account leads to significant differences in the shape of the evolving CO2 plume and the saturation within.

Study on the influence of various factors on dispersion during enhance natural gas recovery with CO2 sequestration in depleted gas reservoir

In CO2 enhanced gas recovery (EGR), physical dispersion occurs between CO2 and natural gas, which can pollute the produced natural gas. Therefore, accurate assessment of the dispersion process is important for the commercialization of EGR. Under reservoir conditions, the effects of gravity, impurities, and other factors on dispersion in porous media were systematically evaluated. Comparison of the apparent dispersion characteristics of sandstone and unconsolidated cores (sandpacks) revealed that the vertically upward dispersion coefficient was smaller owing to the greater permeability and homogeneity of the sandpacks. With horizontal and vertically downward displacement of CO2–CH4, gravity promotes CO2–CH4 dispersion. However, dispersion was suppressed with vertically upward displacement (opposite to the direction of gravity). Under the same experimental conditions, pure N2 exhibited greater dispersion than CO2 as a displacing fluid. Finally, CO2 was used to displace natural gas containing different impurities. The results show that the more impurities (CO2, C2H6) exist in the displaced phase, the greater the mixing degree in the displacement process and the larger the dispersion coefficient.

Geologic Modeling and Ensemble-Based History Matching for Evaluating CO2 Sequestration Potential in Point bar Reservoirs

The target reservoirs in many CO2 projects exhibit point bar geology characterized by the presence of shale drapes that act as barriers preventing the leakage of CO2. However, the extent of the flow barriers can also impede the displacement of CO2 in such reservoirs and restrict the storage volume. Therefore, developing a framework for modeling point bars and their associated heterogeneities is crucial. Yet, for the point bar model to be geologically realistic and reliable for evaluating CO2 sequestration potential, it should be calibrated to reflect historical data (e.g., CO2 injection data). This study is therefore in two parts. The first part focusses on the modeling of point bar heterogeneities (i.e., lateral accretions and inclined heterolithic stratifications). To ensure that the heterogeneities are preserved, we implemented a gridding scheme that generates curvilinear grids representative of the point bar curvilinear geometry. We subsequently incorporated a grid transformation scheme to facilitate geostatistical modeling of reservoir property distributions. The second part of this study is a model calibration step, where the point bar model is updated by assimilating CO2 injection data, in an ensemble framework. Ensemble-Kalman Filter was used first to update ensembles of point bar geometries, to select the geometry that yields the closest match to observed data. Within this geometry, indicator-based ensemble data assimilation was used to perform updates to the ensemble of point bar permeability models. The indicator approach overcomes the Gaussian limitation of the traditional ensemble Kalman filter. The workflow was run on the Cranfield, Mississippi CO2 injection dataset. It was observed, after model calibration, that the final updated ensemble of models yields a reasonable match with the historical data. The updated models were run in a forecast mode to predict the long-term CO2 sequestration potential of the Cranfield point bar reservoir. Results demonstrate that 1) preserving the heterogeneities in the point bar modeling process, and 2) constraining the point bar model to historical data (e.g., CO2 injection data) are essential for accurately evaluating the CO2 sequestration potential in point bar reservoirs.

Experimental Study of Adsorption Characteristics and Deformation of Coal for Different Gases

Coal seam deformation due to gas adsorption affects the stability of the underground structure. Natural coal blocks of the Shanxi Formation were selected to study the dynamic adsorption characteristics of coal samples subjected to CO2, CH4, and N2 gas injections under coaxial pressure and confining pressure (7 MPa), as well as the displacement of CH4 with CO2 and N2 under the same conditions. The results show that, under the same conditions, the strain in the coal samples first increased, followed by a rapid increase along with the increase in pressure, with the transverse strain being always higher than the axial strain. The amount of gas adsorption varied from high to low as CO2 > CH4 > N2, and the final adsorption strains and equilibrium times were different for each gas. Based on the increase in gas pressure, the gas adsorption strain curve can be divided into two stages. The displacement of N2 only uses partial pressure to achieve the desorption of CH4 in the coal sample, leading to shrinkage deformation of the coal sample. In contrast, the displacement of CO2 has the dual effects of competitive adsorption and partial pressure reduction on CH4, leading to the swelling deformation of the coal sample.

Experimental Analysis and Numerical Simulation of the Stability of Geological Storage of CO2: A Case Study of Transforming a Depleted Gas Reservoir into a Carbon Sink Carrier.

Geological storage of CO2 is one of the most economical, feasible, and effective measures to slow down global warming. In this study, a combined long core model was designed to study the seepage characteristics of supercritical CO2 displacement. Moreover, the stability of permanent storage of cushion gas layers formed by supercritical CO2 injection has been systematically studied. The research results showed that in the supercritical temperature and pressure range of CO2, the front edge of CO2 displacement can form a relatively stable seepage zone. Supercritical CO2 displacement can achieve a high gas-storage rate and stable CO2 storage. At the same time, the recovery rate of remaining natural gas has been significantly improved. As the injection pressure increased, supercritical CO2 inhibited the reverse diffusion of natural gas molecules. Therefore, the breakthrough of the supercritical CO2 displacement front under a high pressure lagged behind. However, due to the increase in the density difference of gas molecules, the forward diffusion of supercritical CO2 has been enhanced. Temperature will not significantly affect the displacement and storage effects of supercritical CO2 in gas reservoirs. The increase in injection pressure and reasonable control of the injection rate can delay the breakthrough of supercritical CO2 displacement. These measures are conducive to the stable storage of CO2 and the improvement of remaining natural gas recovery. The implementation of CO2 geological storage is suitable for the later stage of gas reservoir depletion development. The high-density gravitational heterogeneity of supercritical CO2 enables the injected CO2 to form a stable high-density cushion gas layer in the gas reservoir, which can achieve stable CO2 storage for more than 100 years.

Evaluation of CO2 storage of water alternating gas flooding using experimental and numerical simulation methods

The potential of water alternating gas (WAG) flooding in CO2 storage was exploited using experimental and numerical simulation methods in this study. Through comparing experiments results of WAG flooding and continuous CO2 flooding, WAG flooding after water flooding enhanced oil recovery by 39.0%, 2.2% higher than that of continuous CO2 flooding. However, the water slugs in WAG displaced part of the previously stored CO2 out the core. Only 13.1% of the injected CO2 was stored through WAG, 13.4% lower than that of continuous CO2 flooding. Then, numerical simulations of WAG and continuous CO2 flooding were conducted at a water flooded oil reservoir. The field-scale case study showed that the number of rounds of alteration from CO2 slug to water slug in WAG, the duration time of each round, and the CO2 injection time in each round were the main factors influencing CO2 storage. Improper design of influencing parameters led to 118,986 tons lower CO2 storage through WAG than continuous CO2 flooding. Finally, to obtain the maximum CO2 storage, surrogate optimization was applied to adjust the proposed influencing factors. The optimization results showed less rounds of alteration and a pure CO2 slug size at the end improved the CO2 swept area in the reservoir for CO2 storage and inhibited the displacement of CO2 by water slug. After optimization of the proposed factors, 391,000 tons of CO2 were stored in the water flooded oil reservoir through WAG flooding, 65,764 tons more than continuous CO2 flooding. This study provides valuable experimental data and theoretical guidance for CO2 storage in water flooded oil reservoirs.

Dynamics adsorption of the enhanced CH4 recovery by CO2 injection

AbstractThe dynamic adsorption isotherms of CO2‐EGR were measured by using an Intelligent Gravimetric Analysis system. In the initial CO2 injecting stage, all the injected CO2 enters into the adsorbent and the mole fraction of CH4 in the gas phase () is maintained at 1.0. The CH4 recovery factor () increases. The duration of this stage (tCD) depends on the selectivity of CO2 over CH4 (). An adsorbent with large has long tCD. In the second stage, the injected CO2 competes with CH4 for adsorption. The cumulative of the second stage is much larger than that of the initial stage. However, decreases sharply. in the whole CO2 injection is always larger than that before CO2 injection, suggesting that CH4 desorption results from the displacement of CO2 rather than from pressure depletion.

An experimental study on coal damage caused by two-phase displacement of CO2- alkaline solution

Two-phase displacement of CO2- alkaline solution technology was proposed to address the obvious problems existing in the current coal mine gas control technologies, such as the gas enrichment and outburst risk caused by tradition CO2 injection technology, and the poor effect of conventional coal seam water injection technology. In order to investigate the damage characteristics of coal pore structure and permeability caused by two-phase displacement of CO2- alkaline solution, the composition and microstructure of coal after two-phase displacement of CO2- alkaline solution were tested experimentally, and the permeability experiment of two-phase displacement of CO2- alkaline solution was carried out. The results show that the reaction degree and dissolution of CO2-containing coal with alkaline solution are stronger than those with distilled water. The reaming effect of alkaline solution on CO2-containing coal is stronger than that of distilled water, and the two-phase displacement of CO2- alkaline solution has the greatest influence on mesopore and macropore; After two-phase displacement of CO2- alkaline solution, the permeability of coal sample increased by 47.6%–108.6%, and the water content of coal sample increased by 109%. The two-phase displacement of CO2- alkaline solution leads to the secondary development of coal pores, which significantly changes the coal pore structure, increases the permeability and water content of coal body, and thus obviously increases the gas extraction effect to reduce coal seam outburst risk and ensure coal mine safety production.

Experimental Analysis and Numerical Simulation on the Stability of Geological Storage of CO <sub>2</sub>: A Case Study of Transforming a Depleted Gas Reservoir into a Carbon Sink Carrier

Geological storage of CO2 is one of the most economical, feasible and effective measures to slow down global warming. In this paper, a combined long core model was designed to study the seepage characteristics of supercritical CO2 displacement. Moreover, the stability of permanent storage of cushion gas layers formed by supercritical CO2 injection has been systematically studied. The research results showed that in the supercritical temperature and pressure range of CO2, the front edge of CO2 displacement can form a relatively stable seepage zone. Supercritical CO2 displacement can achieve high gas storage rate and stable CO2 storage. At the same time, the recovery rate of remaining natural gas has been significantly improved. As the injection pressure increased, supercritical CO2 inhibited the reverse diffusion of natural gas molecules. Therefore, the breakthrough of the supercritical CO2 displacement front under high pressure laged behind. However, due to the increase in the density difference of gas molecules, the forward diffusion of supercritical CO2 has been enhanced. Temperature will not significantly affect the displacement and storage effects of supercritical CO2 in gas reservoirs. The increase in injection pressure and reasonable control of the injection rate can delay the breakthrough of supercritical CO2 displacement. These measures are conducive to the stable storage of CO2 and the improvement of remaining natural gas recovery. The implementation of CO2 geological storage is suitable for the later stage of gas reservoir depletion development. The high-density gravitational heterogeneity of supercritical CO2 enables the injected CO2 to form a stable high-density cushion gas layer in the gas reservoir, which can achieve stable CO2 storage for more than 100 years.

Molecular simulation of N2 and CO2 injection into a coal model containing adsorbed methane at different temperatures

To research the dynamic mechanism of nitrogen and carbon dioxide displacement of methane, we used the grand canonical Monte Carlo (GCMC) simulation method to determine the lowest energy coal model containing adsorbed methane. The desorption behavior of CH4 after the injection of N2 and CO2 at different temperatures was studied. Results show that CO2 and N2 were mainly used to drive off methane gas by occupying adsorption sites. The total energy of the CH4-CO2 model was lower than that of the CH4-N2 model. With the increased of temperature, the average relative concentration and motion velocity of CH4 in the vacuum layer increased. The relationship of the average relative concentration and average velocity distribution of the three gases in the vacuum layer was CH4>CO2>N2. Under the same time conditions, the relationship between the mean square displacement and diffusion coefficient of CH4, CO2, and N2 in different models was CH4>CO2>N2, and they all increased with temperature. The diffusion activation energy of CH4 in the model injected with CO2 was reduced by 20.53%, and the effect of injecting CO2 to promote the desorption of methane was better than that of N2.

Experimental study on the CO2-decane displacement front behavior in high permeability sand evaluated by magnetic resonance imaging

CO2 flooding has been proven to be an effective method to improve oil recovery, and the interface characteristics of the displacement front directly affect the oil recovery and CO2 utilization efficiency in reservoirs. In this study, we aimed to investigate the in situ interfacial behavior during CO2 flooding using high-resolution magnetic resonance imaging (MRI). A series of CO2 flooding tests were carried out using upward and downward injection methods consisting of different rates (28, 56 and 112 pore volume (PV)/day) in porous media. The unstable CO2 front is indicated to significantly impact the gas sweep efficiency, which is not favorable for oil recovery and leads to low energy utilization efficiency. For downward injection, subordinate displacement of CO2 was observed after breakthrough, which can improve oil recovery. The optimum oil recovery and CO2 utilization factor were obtained under upward injection at a low rate in the immiscible state, which was controlled by the stable interface behavior. From the perspective of CO2 storage, miscible flooding improved the storage volume by more than 25% compared to immiscible flooding. For high permeability oil reservoirs, the oil recovery and gas sequestration can be synthetically optimized by adjusting the injection rates and phase state.

Improving CO2 storage and oil recovery by injecting alcohol-treated CO2

Oil recovery and CO2 storage related to CO2 enhance oil recovery are dependent on CO2 miscibility. In case of a depleted oil reservoir, reservoir pressure is not sufficient to achieve miscible or near-miscible condition. This extended abstract presents numerical studies to delineate the effect of alcohol-treated CO2 injection on enhancing miscibility, CO2 storage and oil recovery at immiscible and near-miscible conditions. A compositional reservoir simulator from Computer Modelling Group Ltd. was used to examine the effect of alcohol-treated CO2 on the recovery mechanism. A SPE-5 3D model was used to simulate oil recovery and CO2 storage at field scale for two sets of fluid pairs: (1) pure CO2 and decane and (2) alcohol-treated CO2 and decane. Alcohol-treated CO2 consisted of a mixture of 4 wt% of ethanol and 96 wt% of CO2. All simulations were run at constant temperature (70°C), whereas pressures were determined using a pressure-volume-temperature simulator for immiscible (1400 psi) and near-miscible (1780 psi) conditions. Simulation results reveal that alcohol-treated CO2 injection is found superior to pure CO2 injection in oil recovery (5–9%) and CO2 storage efficiency (4–6%). It shows that alcohol-treated CO2 improves CO2 sweep efficiency. However, improvement in sweep efficiency with alcohol-treated CO2 is more pronounced at higher pressures, whereas improvement in displacement efficiency is more pronounced at lower pressures. The proposed methodology has potential to enhance the feasibility of CO2 sequestration in depleted oil reservoirs and improve both displacement and sweep efficiency of CO2.

Gaseous CO2 behaviour during water displacement in a sandstone core sample

CO2 injection into subsurface formations involves the flow of CO2 through a porous medium that also contains water. The injection, displacement, migration, storage capacity and security of CO2 is controlled mainly by the interfacial interactions and capillary, viscous, and buoyancy forces which are directly influenced by changes in subsurface conditions of pressure and temperature; investigation the impact of bouncy forces is beyond the scope of this study. In this study, gaseous CO2 is injected into a water-saturated sandstone core sample to explore the impact of fluid pressure (40–70 bar), temperature (29–45 °C), and CO2 injection rate (0.1–2 ml/min) on the dynamic pressure evolution and displacement efficiency. This study highlights the impact of capillary or viscous forces on the two-phase flow characteristics and shows the conditions where capillary or viscous forces become more influential. The results reveal a moderate to considerable impact of the parameters investigated on the differential pressure profile, endpoint CO2 relative permeability (KrCO2max), and irreducible water saturation (Swr). Overall, the increase in fluid pressure, temperature, and CO2 injection rate cause an increase in the maximum and final differential pressures, an increase in the KrCO2max, a reduction in the Swr. Swr was in the range of around 0.38–0.45 while KrCO2max was less than 0.25. The data show a significant influence for the capillary forces on the pressure and production behaviour. The capillary forces produce high oscillations in the pressure and production data while the increase in viscous forces impedes the appearance of these oscillations. The appearance and frequency of the oscillations depend on the fluid pressure, temperature, and CO2 injection rate but to different extents.

Investigation of gas displacement efficiency and storage capability for enhanced CH4 recovery and CO2 sequestration

Injecting gas into coal seam is an effective technique for enhanced coalbed methane recovery and CO2 sequestration. Displacement efficiency of various gas injections was investigated by experimental measurements. Experimental results show that any factor of adsorption amount, back pressure, displacement pressure and displacement time can have a significant influence on methane recovery. Displacement efficiency has a non-monotonic increase with the ascending equilibrium pressure, is enhanced by back pressure reduction and increasing displacement pressure, and tends to reach a higher degree by the mixture rich in nitrogen. Displacement pressure presents a significant influence on displacement efficiency and causes a rapid production response in early injection stage for the rich nitrogen mixture. Displacement dynamics of various gas injections was investigated by the numerical simulation. A good consistency of displacement efficiency by displacement experiment and numerical simulation is found. For the mixture rich in nitrogen, the higher displacement efficiency is obtained and the breakthrough time of N2 and CO2 can be both shortened. Spatial and temporal distribution of adsorbed gas for pure gas injection shows that the displacement and breakthrough time of pure CO2 are both delayed. Based on spatial and temporal distribution of mixed gas displacement, displacement efficiency is controlled by the composition and competitive sorption of the mixture. Gas transport is sensitive to the injection pressure and faster to reach the stable state with the ascending pressure. The result of this study is helpful to realize the mechanism of enhanced coalbed methane recovery by gas injection and design the scheme of gas injection.

Post-synthesis annealing of coprecipitated CoFe2O4 nanoparticles in silica matrix

Cobalt ferrite nanoparticles (d ∼ 11 nm, σd = 0.5) produced by coprecipitation at room temperature are heat treated up to 1000 °C after a preliminary dispersion in a sol-gel silica matrix to avoid aggregation and coarsening. This protected annealing allows for a significant increase of the crystallinity of the particles, as demonstrated by combined x-ray diffraction and transmission electron microscopy experiments. A large increase in the coercive field value is reported, from 1.0 to 1.6 Tesla after annealing at 600 °C. This enhanced coercivity can be explained by the cumulative effect of an increased magnetic anisotropy and of a decreased saturation magnetization (Ms). Mössbauer spectroscopy experiments show that these evolutions of the Ms and anisotropy constant (K) values originate from a small increase in canting angles and in inversion degree, i.e. a displacement of Co2+ ions from tetrahedral to octahedral sites of the spinel lattice. This study emphasizes the little impact of an improved crystallinity on saturation magnetization and canting angle values in coprecipitated CoFe2O4 nanoparticles and highlights that the main source of magnetic disorder is associated with the distribution of Co and Fe within the cationic sites.

Effect of CO2 phase on its water displacements in a sandstone core sample

CO2 injection into underground formations can reduce CO2 emissions, enhance hydrocarbon and methane recovery, and extract geothermal heat. As the pressure and temperature vary in subsurface formations, the injected CO2 can be in gas, liquid and supercritical phase. The change in CO2 phase is likely to have a significant impact on capillary and viscous forces, which, in turn, will have a considerable influence on injectivity, displacement, migration, storage capacity and integrity of CO2 processes. This study was designed to investigate the effect of CO2 phase, at different injection rates, on the dynamic pressure evolution and the CO2 displacement performance during CO2 injection into a water-saturated sandstone core sample. The results indicate that CO2 phase significantly affects the differential pressure profile and water production profile. The differential pressure profiles measured from the displacement of supercritical CO2 and gas CO2 were significantly different from those measured from liquidCO2 displacements, particularly before CO2 breakthrough. Gas and supercriticalCO2 injection gave a water production rate much higher than the CO2 injection rate at early stages. Liquid CO2 injection yielded a water production rate similar to the CO2 injection rate. This may indicate that the injection of ScCO2or GCO2 (under a pressure higher than 60 bar) could give a high and quick oil production rate. The highest water recovery was obtained after the injection of 0.85, 1.08 and 2.32 pore volumes of scCO2, gCO2, and LCO2, respectively. The residual water saturations for the three CO2 phases were in the range of 30–33% while the endpoint relative permeability was in the range of 18–21%. The endpoint relative permeabilities for gas and liquid CO2 were very similar and higher than that of supercritical CO2 under our experimental conditions. The increase in injection rate caused a slight increase in the endpoint relative permeabilities for the three CO2 phases.