Effects Of CO2 Injection Research Articles

Mechanism of Minerals Action in Reservoir During CCS

Abstract The carbon capture and storage (CCS) is one of the most effective ways to control greenhouse gases emissions and mitigate greenhouse effects. There will be a series of effects on the physical properties and chemical composition of the reservoir after CO2 injection. It is of great significance to study the effect of CO2 injection on reservoir for better CO2 storage. In this paper, Through the mechanism model established by numerical simulation technology and the phase permeability hysteresis simulation method, the whole process of reservoir pH, mineral dissolution and precipitation and porosity change during CO2 storage was accurately described. The results indicate that CO2 firstly dissolves in water to form carbonic acid after injection into the reservoir, which will cause a drastic change acid-base properties of reservoir, manifesting as a significant decrease in pH value. Under the effect of H +, Partia mineral components(for example: anorthite) in the reservoir) are dissolved, however, some other minerals (for example: kaolinite and calcite) are precipitated, which significantly change the composition of underground aqueous solution. The reaction rate of CO2-water-rock is very slow. After stopping CO2 injection, the mineralization of all kinds of minerals still goes on for a long time. In addition, due to the effect of CO2-water-rock reaction, a certain increase of reservoir porosity is more conducive to CO2 migration in the reservoir.

Permeability evolution of sandstone caprock transverse fractures during intermittent CO2 injection in coal-bearing strata

The caprock of coal-bearing strata plays a critical role in CO2 geological storage, with the presence of fractures posing a heightened risk of CO2 leakage. The cyclic effects of CO2 injection and in situ stress influence the permeability of caprock fractures. However, the combined impact of CO2 and in situ stress on fracture permeability remains uncertain. This study conducted cyclic seepage experiments under varying amplitude stresses on fractured sandstone samples soaked in ScCO2 for different times (0, 15, 30, and 60 days). The microstructural characteristics of the fractured sandstone surfaces were analyzed using scanning electron microscopy and x-ray diffraction. The experimental results indicated that soaking in ScCO2 reduces sandstone fracture permeability, but the extent of this reduction is nonlinearly related to the soaking time. During the stress cycling process, due to the effect of plastic deformation, the permeability of sandstone fractures decreases with increasing cyclic amplitude and remains relatively constant with decreasing cyclic amplitude. At the same cyclic amplitude, the permeability of sandstone fractures initially increases and then decreases with prolonged soaking time. The impact of ScCO2 and stress cycling on the permeability of sandstone fractures is the result of a series of combined chemical–mechanical effects. The combined effects of chemical dissolution and mechanical degradation significantly influence the permeability of sandstone fractures, and this impact is notably time-dependent. During short-term soaking, geochemically induced changes in the surface structure of fractures cause fluctuations in permeability, while in long-term soaking, the combined chemical–mechanical effects promote a reduction in fracture permeability.

Giant Effect of CO2 Injection on Multiphase Fluid Adsorption and Shale Gas Production: Evidence from Molecular Dynamics.

Carbon dioxide (CO2) injection in unconventional gas-bearing shale reservoirs is a promising method for enhancing methane recovery efficiency and mitigating greenhouse gas emissions. The majority of methane is adsorbed within the micropores and nanopores (≤50 nm) of shale, which possess extensive surface areas and abundant adsorption sites for the sequestration system. To comprehensively discover the underlying mechanism of enhanced gas recovery (EGR) through CO2 injection, molecular dynamics (MD) provides a promising way for establishing the shale models to address the multiphase, multicomponent fluid flow behaviors in shale nanopores. This study proposes an innovative method for building a more practical shale matrix model that approaches natural underground environments. The grand canonical Monte Carlo (GCMC) method elucidates gas adsorption and sequestration processes in shale gas reservoirs under various subsurface conditions. The findings reveal that previously overlooked pore slits have a significant impact on both gas adsorption and recovery efficiency. Based on the simulation comparisons of absolute and excess uptakes inside the kerogen matrix and the shale slits, it demonstrates that nanopores within the kerogen matrix dominate the gas adsorption while slits dominate the gas storage. Regarding multiphase, multicomponent fluid flow in shale nanopores, moisture negatively influences gas adsorption and carbon storage while promoting methane recovery efficiency by CO2 injection. Additionally, saline solution and ethane further impede gas adsorption while facilitating displacement. Overall, this work elucidates the substantial effect of CO2 injection on fluid transport in shale formations and advances the comprehensive understanding of microscopic gas flow and recovery mechanisms with atomic precision for low-carbon energy development.

Time Lapse Measurement of Reservoir’s Parameters Change due to CO2 Injection in Parigi Carbonate West Java

CO2 injection is a process that involves injecting carbon dioxide gas into various substances or environments for different purposes. This technique, also called Carbon Capture and Storage (CCS) or Carbon Capture, Utilization, and Storage (CCUS), aims to prevent or reduce carbon dioxide emissions from reaching the atmosphere as they would affect climate change and also global warming. CCUS can also use the captured carbon dioxide for various purposes, such as enhancing oil recovery, producing fuels, chemicals, or building materials, or storing it underground or underwater. In this study, we investigated the phenomena of CO2 injection in Parigi carbonate rock from West Java. Our study involved various laboratory measurements of Parigi carbonate rock, focusing on changes in porosity due to CO2 injection. The porosity changes were observed using micro images analysis from microscope time-lapse analysis, CT-Scan, and laboratory helium porosity meter. The laboratory measurements of CO2 injection in brine water showed that the pH of the water can decrease to below 5, creating an acidic environment that induces dissolution of the pore structure. We measure the effect of CO2 injection to the Parigi carbonate samples by time lapse measurement strategy. Results of the laboratory measurements showed that the porosity increased during CO2 injection and the mass of the samples decreased during the CO2 injection process. These phenomena suggest that CO2 may induce dissolution of carbonate rock. Furthermore, the changes in porosity confirm that there is a chemical reaction during CO2 injection processes in Parigi carbonate.

Effect of CO2 injection on the gas desorption and diffusion kinetics: An experimental study

During CO2 displacement, the diffusion characteristics of gas in the coal matrix are among the key factors that affect the gas extraction rate, and discussed the influence mechanism of CO2 injection on the diffusion kinetics of coal seam gas. In this study, we used a self-developed CO2–CH4 displacement experimental platform to study the diffusion characteristics of CH4 under different CO2 injection pressures and temperatures. As the CO2 injection pressure was increased from 0.6 MPa to 1.0 MPa, the CH4 production increased by 9.44 %, the CH4 maximum diffusivity increased by 0.05, the effective diffusion coefficient extreme point increased by 111.45 %. As the gas injection temperature was increased from 40 °C to 60 °C, the CH4 production increased by 4.02 %, the CH4 maximum diffusivity increased by 0.03, the maximum of the effective diffusion coefficient increased by 103.31 %. To better explain the gas diffusion characteristics during CO2 displacement, the influence mechanism of increasing CO2 injection pressure and temperature on the CH4 diffusion kinetics was discussed, and the driving force (fd) and resistance (fr) during the displacement process were studied. The dynamic CO2 injection models were considered to be more effective in ensuring efficient CH4 recovery.

Underground geological sequestration of carbon dioxide (CO2) and its effect on possible enhanced gas and oil recovery in a fractured reservoir of Eastern Potwar Basin, Pakistan

Due to concerns over rising emissions of carbon dioxide (CO2) from fossil fuel utilization, there has been a strong emphasis on the development of a safe, economical, practical method of carbon capture utilization and storage (CCUS). One way to reduce these CO2 emissions is underground geological sequestration in depleted oil fields or exhausted reservoirs. CO2 injection into oil reservoirs is an established technology, these reservoirs not only offer the potential for high storage of CO2 but this process could also target a large amount of oil and gas recovery through a technique called enhanced oil recovery (EOR). The main objective of this research was to evaluate the storage potential of CO2 in the depleted oil field while also investigating the effect of CO2 injection on reservoir pressure maintenance, and additional oil and gas recovery, in the same field. This paper presented the model of CO2 flooding based on the CO2 displacement mechanism with different scenarios of natural depletion, CO2 injection, and water injection simulated by the ECLIPSE 300 reservoir simulator, and the results of different scenarios were compared. Results of this study showed the site selected for CO2 injection has the potential to store more than 9 billion cubic feet (BCF) of CO2 in each case and witnessed improved gas recovery, while also having a major effect on reservoir pressure maintenance where pressure increased from 2120 psi to 6584 psi. The finding of this work ought to help in preparing for future improvement in underground geological sequestration of CO2 in depleted fields with the same field specifications.

Chemo-hydro-mechanical effects of CO2 injection into a permeable limestone

CO2 storage in carbonate aquifers is a way to mitigate atmospheric CO2 emissions, but it leads to acid-producing reactions that may induce alterations in the rock pore structure and hydromechanical properties. To gain a better understanding of these changes in rock properties, percolation experiments under constant flow-rate conditions with (i) CO2-saturated water (PCO2 = 100 bar and T = 60 °C) and (ii) HCl solutions (P = 1 bar and T = 60 °C) were performed on centimetric cores of the grain-supported Pont du Gard Limestone (permeability about 10−14–10−13 m2). Effluent chemistry analyses, X-ray imaging, and measurements of the hydromechanical properties of intact and altered specimens were used to quantify acid-induced changes in the two acid-rock systems. Experimental results show that the rock dissolution patterns highly depend on the acid type and pore space heterogeneity. Under the flow conditions of these experiments, complete HCl dissociation (strong acid) and rapid HCl-rock reaction result in a compact dissolution pattern that only affects the hydromechanical properties of the core inlet. Conversely, partial dissociation of H2CO3 (weak acid) produces chemical reactions all along the core. Initial structural heterogeneities localize chemical reactions along preferential flow pathways, causing instabilities in the reaction front and wormhole formation, which markedly enhances permeability. A powerlaw relationship with a very large exponent (as high as 24) accounts for the variation in permeability as a function of porosity. Altered cores render both a significant attenuation in mechanical rock properties and ultrasonic velocities, which is reproduced using a Differential Effective Medium (DEM) homogenization approach. The high-pressure percolation experiments of this study using CO2-saturated water represent an extreme scenario of CO2-brine-rock interactions in carbonate reservoirs, which needs to be considered to improve the prediction and monitoring of the storage performance.

A Simulation Study on Evaluating the Influence of Impurities on Hydrogen Production in Geological Carbon Dioxide Storage

In this study, we examined the effect of CO2 injection into deep saline aquifers, considering impurities present in blue hydrogen production. A fluid model was designed for reservoir conditions with impurity concentrations of 3.5 and 20%. The results showed that methane caused density decreases of 95.16 and 76.16% at 3.5 and 20%, respectively, whereas H2S caused decreases of 99.56 and 98.77%, respectively. Viscosity decreased from 0.045 to 0.037 cp with increasing methane content up to 20%; however, H2S did not affect the viscosity. Notably, CO2 with H2S impacted these properties less than methane. Our simulation model was based on the Gorae-V properties and simulated injections for 10 years, followed by 100 years of monitoring. Compared with the pure CO2 injection, methane reached its maximum pressure after eight years and eleven months at 3.5% and eight years at 20%, whereas H2S reached maximum pressure after nine years and two months and nine years and six months, respectively. These timings affected the amount of CO2 injected. With methane as an impurity, injection efficiency decreased up to 73.16%, whereas with H2S, it decreased up to 81.99% with increasing impurity concentration. The efficiency of CO2 storage in the dissolution and residual traps was analyzed to examine the impact of impurities. The residual trap efficiency consistently decreased with methane but increased with H2S. At 20% concentration, the methane trap exhibited higher efficiency at the end of injection; however, H2S had a higher efficiency at the monitoring endpoint. In carbon capture and storage projects, methane impurities require removal, whereas H2S may not necessitate desulfurization due to its minimal impact on CO2 storage efficiency. Thus, the application of carbon capture and storage (CCS) to CO2 emissions containing H2S as an impurity may enable economically viable operations by reducing additional costs.

Research on the feasibility of storage and estimation model of storage capacity of CO2 in fissures of coal mine old goaf

The concept of the carbon cycle in the old goaf of a coal mine based on CO2 utilization and storage was put forward adhering to the principle of low-carbon development, utilization of space resources in old goafs, and associated gas resources development. Firstly, the evolution characteristics of overburden fissures in the goaf of the case was studied using a two-dimensional physical similarity simulation test, the sealing performance of the caprocks after stabilization was analyzed, and the fissures were counted and classified. Then, the process of gaseous CO2 injection in the connected fissure was simulated by Ansys Fluent software, and the migration law and distribution characteristics of CO2 under the condition of gaseous CO2 injection were analyzed. Finally, the estimation models of free CO2 storage capacity in the old goaf were constructed considering the proportion of connected fissure and the effectiveness of CO2 injection. The CO2 storage capacity in the old goaf of the case coal mine was estimated. The results showed that a caprock group of “hard-thickness low-permeability hard-thickness” was formed after the caprock-fissures system in the goaf of the case tended to be stable vertically. The connected fissure, occlude cracks, and micro-fractures in the goaf accounted for 85.5%, 8.5%, and 6% of the total fissures, respectively. Gaseous CO2 first migrated to the bottom of the connected fissure after CO2 was injected into the goaf, then spread horizontally along the bottom of the connected fissure after reaching the bottom, and finally spread longitudinally after filling the bottom of the entire connected fissure. The theoretical and effective storage capacities of free CO2 at normal temperature and pressure in the old goaf of the case were 9757 and 7477 t, respectively. The effective storage capacity of free CO2 at normal temperature and pressure in the old goaf after all minefield mined was 193404 t. The research can provide some reference for the coal mining industry to help the goal of “carbon peaking and carbon neutrality”.

Polycyclic aromatic hydrocarbons (PAHs) and soot formations under different gasifying agents: Detailed chemical kinetic analysis of a two-stage entrained flow coal gasifier

The injection of CO2 with coal into coal gasifier is a promising approach to achieve CO2 recirculation. Predicting the formation and evolution of polycyclic aromatic hydrocarbons (PAHs) and soot during coal gasification is particularly important as their presence poses challenges to the gasifier operation and environment. However, the effect of CO2 injection on their formation must be elucidated in more detail to optimize the gasifier design. This work investigates PAHs and soot formations in gas-phase reactions under different gasifying agents (Air, O2/CO2, O2/H2O) in a two-stage entrained flow coal gasifier using a detailed chemical kinetic model (DCKM). Under the O2/CO2– and O2/H2O-blown conditions, aromatics reforming was progressed whereas the yields of tar and soot were effectively suppressed. The benzene was observed as the most abundant PAHs species, followed by naphthalene and acenaphthalene. Regarding the relative oxygen concentration, the conversion behavior of aromatics was significantly influenced in the O2/CO2-blown condition, while the somewhat effect was found in the O2/H2O-blown condition. Tar yield peaked at 50% relative oxygen concentration in the O2/CO2-blown condition. The present finding may have practical significance in the O2/CO2-blown gasifier to facilitate CO2 recirculation for the oxy-fuel IGCC system.

Effect of CO2 Injection on the Multiphase Flow Properties of Reservoir Rock

Effect of CO2 Injection on the Multiphase Flow Properties of Reservoir Rock

Characteristics of water alternating CO2 injection in low-permeability beach-bar sand reservoirs

Water flooding can be ineffective in highly heterogeneous low-permeability beach-bar sand reservoirs. The introduction of CO2 flooding helps boost the oil production of the reservoirs but only in an early stage. During the late stage of flooding, gas channeling would occur. Water alternating gas (CO2) (WAG) process can be used to delay gas channeling and improve the effect of CO2 injection, though its adaptability to beach-bar sand reservoirs remains unclear. In order to clarify CO2 injection characteristics in these reservoirs, experiments were carried out in high-temperature high-pressure NMR on-line displacement experiment apparatus to simulate different flooding modes on synthetic cores that can reflect the vertical heterogeneity of beach-bar reservoirs. Different CO2 injection modes were implemented on these cores and the displacement characteristics and residual oil distribution features during both WAG injection and continuous CO2 injection were analyzed quantitatively and qualitatively. The results show that the scheme of WAG injection after continuous CO2 injection can obtain better oil displacement efficiency than that of the scheme of continuous CO2 injection after WAG injection, but there is no significant difference in respect of oil displacement efficiency of WAG flooding between the mode of bar-injection – beach-production (injection into bar sand – production from beach sand) and the mode of beach-injection – beach-production (injection into and production from beach sand), with the former mode having a higher oil recovery rate. The wider pore-size distribution range of microscopic residual oil after WAG injection shows great potential of enhancing oil recovery from subsequent continuous gas injection. When WAG injection is implemented prior to continuous CO2 injection, the displacement effect of the latter is more significant. This research may provide a theoretical basis for CO2 EOR in this type of reservoirs.

Coupled Hydromechanical Modeling of Induced Seismicity From CO2 Injection in the Illinois Basin

AbstractInjection of CO2 for geologic carbon sequestration into deep sedimentary formations involves fluid pressure increases that engage hydromechanical processes that can cause seismicity by activation of existing faults. In this work, we use a coupled multiphase fluid flow and geomechanical simulator to model spatiotemporal fluid pressure and stress changes in order to study the poroelastic effect of CO2 injection on faults in crystalline basement rock below the injection zone. The seismicity rate along features interpreted to be basement faults is modeled using Dieterich's rate‐and‐state earthquake nucleation model. The methodology is applied to microseismicity detected during CO2 injection into the Mount Simon formation during the Illinois Basin—Decatur Project. The modeling accurately captures an observed reduction in seismicity rate when the injection in the second well was into a slightly shallower zone above the base of the Mount Simon formation. Moreover, the modeling shows that it is important to consider poroelastic stress changes, in addition to fluid pressure changes for accurately modeling of the observed seismicity rate.

Geomechanical effects of co2 storage in geological structures: two case studies

Storage of CO2 in subsurface can assist to mitigate CO2 emission without extensively interfering with industrial activity and development. The main reason for geological storage to trap CO2 underground for a long time. However, the injection of CO2 may compromise the sealing characteristics of the caprock and, consequently, the containment of the underground CO2 storage unit as well. For instance, the injection of CO2 into a reservoir resulted in pore pressure and temperature changes leading to deformation and stress changes in the injection target and the rocks that surround it. These changes can influence the hydraulic integrity of the geological storage. The potential hazards could then impose different environmental, health, safety, and economic risks. Therefore, the geomechanical assessment of caprock integrity is critical for the storage of carbon dioxide. This research reviewed two different cases of underground CO2 storage in Canada and the workflows used for the assessment of geomechanical effects of CO2 injection on caprock integrity. It reviewed the processes of data collection, geomechanical characterization, and fluid flow modeling. These reviews highlighted the significance of geomechanical characterization and the fact that it is faced with significance challenges that could be addressed by data integration and geostatistical analysis. These reviewed studies implemented both analytical and numerical geomechanical models. While analytical models seem to be great choices for preliminary geomechanical analysis, numerical models are also necessary for a more detailed analysis. Â

Critical rate analysis for CO2 injection in depleted gas field, Sarawak Basin, offshore East Malaysia

This study aimed to address the challenges and strategies to determine the critical rate of CO2 injection into a carbonate depleted gas field. In this research, the critical rate is the maximum allowable injection rate before formation damage initiation. The cause of formation damage could be due to in-situ mobilization or trapping of migratory fines resulting in plugging the flow path. This study performed a thorough investigation of a different rock-fluid system to evaluate the safe injection limit, as the critical rate is different for each rock-fluid system. The geochemical effect of CO2 injection toward carbonate formation was also investigated in this research. Other than that, the porosity and permeability changes due to CO2-brine-rock multiphase flow characteristics were considered to understand the feasibility of CO2 sequestration into carbonate formation. This research discussed experimental design to mimic the CO2 injection scenario of CO2 into carbonate depleted gas field. Therefore, several core flooding experiments were conducted under reservoir conditions using representative native cores, CO2, and synthetic formation brine. Abrupt changes in differential pressure (ΔP), analysis of effluent collected after CO2 multi-rate flow, and pH reading are the key indicators to consider that the condition has reached a critical rate. The experimental result demonstrated the existence of fines migration, scale formation, and salt precipitation after the core was subjected to supercritical CO2 multi-rate flow. Considering these issues and challenges associated with injectivity, this study recommended a maximum injection rate prior to field scale injection.

Effect of CO2 injection on CH4 desorption rate in poor permeability coal seams: An experimental study

CO2 injection into coal seams is an effective way for reducing greenhouse gas emissions and increasing gas recovery in coal seams. To study the influence rule of CO2 injection on the CH4 desorption rate, an experimental system of CO2 displacing CH4 was used to analyse the changes in gas composition, outlet flow rate, coal seam temperature, and displacement efficiency parameters during CO2 injection. From the perspective of enhancing CH4 recovery, the CO2 critical injection amount (Vinc) is 297.4 L and critical injection time is 188.75 min. When the CO2 injection amount V < Vinc, the amount of CH4 desorption, CO2 storage, and CH4/CO2 gas content all increased. When V > Vinc, except CH4 desorption amount remained almost unchanged, the other parameters increased. In the process of CO2 displacing CH4, the coal seam temperature rises (exothermic process), showing a law of “hierarchical displacement”. With the injection of CO2, the pore pressure first decreased and then increased, the CH4 partial pressure decreased, and the effective diffusion coefficient first increased and then decreased. After the injection of CO2, the desorption time of CH4 was 269.45min earlier and the desorption rate of CH4 was increased by 12.43 %.

Effect of Carbon Dioxide on Paraffinic Bitumen Froth Treatment: Asphaltene Precipitation from a Commercial Bitumen Froth Sample.

In this study, the effect of carbon dioxide in assisting paraffinic bitumen froth treatment was investigated. The work was divided into two parts, the effect of water addition on CO2-assisted asphaltene precipitation from a dry and clean bitumen sample by n-heptane and the effect of CO2 injection to a mixture of n-heptane and a commercial bitumen froth sample. It was found that water addition to the dry and clean bitumen improved the beneficial effect of CO2 on promoting asphaltene precipitation by n-heptane, where asphaltene precipitation increased by 2.5 percentage points (or 19%) with the presence of water and CO2. The asphaltene precipitation enhancement may be due to chemical reactions between injected CO2 and water in the formation of carbonic acid in the aqueous phase, which destabilized asphaltene. On the other hand, no improvement was detected under the control tests (N2). Similar results were observed in the case of CO2 injection to paraffinic solvent (n-heptane) treatment of the commercial bitumen froth sample. The results indicated that when the commercial bitumen froth sample was mixed with n-heptane at a solvent/bitumen ratio of 1.08, the injection of 1.7 MPa CO2 increased the amount of precipitated asphaltene from 10.0 ± 0.1% (without CO2) to 15.2 ± 0.2% (with 1.7 MPa CO2) at 90 °C, indicating a potential reduction of solvent usage by about 66%.

Effect of CO2 injection into blast furnace tuyeres on the pulverized coal combustion

Abstract CO2 injection into blast furnace tuyeres is a new technology to utilize CO2, aiming at expanding the way of CO2 self-absorption in the metallurgical industry. The decisive factor of whether CO2 can be mixed into a blast-furnace hot blast and the proper mixing ratio is the effect of CO2 injection on pulverized coal burnout. To investigate the effect of CO2 injection into tuyeres on pulverized coal burnout, a three-dimensional mathematical model of pulverized coal flow and combustion in the lower part of the pulverized coal injection lance-blowpipe-tuyere-raceway was established, and the effect of CO2 injection into tuyeres on pulverized coal combustion rate and outlet temperature is analyzed. The numerical simulation results show that the delay of pulverized coal combustion in the early stage is caused by the endothermic effect of the reaction of CO2 with carbon, and the burnout of pulverized coal is increased in the later stage due to the oxidation of CO2.

Pore-Scale Grain-Binding Cement Dissolution in Sandstone Rocks and its Effect on CO2 Injectivity

CO2 geological storage in depleted oil and gas reservoirs and saline aquifers is currently one of the most economical methods to mitigate CO2 emissions, mainly because of available geological data from oil and gas exploration and production in the last decades as well as abandoned wellbore facilities. Four main factors dictate the safe and economical CO2 storage and selection of a suitable storage site: while wellbore and cap rock integrity are critical to the security of stored CO2, storage capacity and CO2 injectivity are among the main factors driving the cost of storage per ton of CO2. Low or reduced CO2 injectivity at injection wellbore can significantly increase the compression costs of the project. In worst-case scenarios, a blockage can increase injection pressures above rock fracture pressure, thus critically jeopardising further injection in the same well. The global abundance, high storage capacity and potentially low chemical reactivity of sandstone reservoirs make them great candidates for CO2 geological storage sites. The matrix of siliciclastic rocks is mainly made of quartz grains, and there is negligible chemical reactivity in contact with carbonic acid formed during the injection. However, the most common cementing agents in these rocks (e.g. calcite, dolomite and, to some extent, clays) react with carbonic acid. These reactions lead to mechanisms like cement dissolution, mineral deposition, and sand fine migration (sand mobilisation). Depending on the volumetric percentage of the binding cement, its geometrical distribution within the matrix and pore (and throat) size distribution of the rock, fine migration and binding cement dissolution can enhance or impair CO2 injectivity [1,2]. Despite numerous studies regarding the effect of CO2 injection on fine migration and injectivity, there is still no consensus regarding the impact of intergranular cement dissolution on CO2 injectivity. In this study, we have focused on the effect of binding cement dissolution on pore morphology in a typical sandstone (Berea) and demonstrating how the observations of CO2 injectivity change at the core scale alone could be misleading and explain some apparent discrepancies reported in the literature. We cut three slices of this core for X-ray micro-computed tomography (MicroCT) imaging. The first slice was cut from the original clean core. After performing a coreflood experiment with carbonated water through the rest of the core, two other pieces were cut from the inlet and outlet of the core. To represent the extreme dissolution conditions (lowest pH) during CO2 injection, a batch of North Sea brine fully saturated with CO2 was prepared and injected through the core at typical reservoir conditions (50°C and 2.6×107 Pa). Three 3D models are reconstructed from images of the prepared rock slices to represent the pore structure of the rock before injection and the inlet and outlet of the core subjected to CW injection. Avizo (a commercial software) is used to calculate the permeability and velocity fields in these models. The comparison of results from micro-CT imaging and the coreflood experiment shows how single-scale studies (either core or pore-scale) of CO2 injectivity can lead to a misleading conclusion about the effect of fine migration on permeability at larger scales.

CO2-Fluid-Rock Interactions and the Coupled Geomechanical Response during CCUS Processes in Unconventional Reservoirs

The difficulty of deploying remaining oil from unconventional reservoirs and the increasing CO2 emissions has prompted researchers to delve into carbon emissions through Carbon Capture, Utilization, and Storage (CCUS) technologies. Under the confinement of nanopore in unconventional formation, CO2 and hydrocarbon molecules show different density distribution from in the bulk phase, which leads to a unique phase state and interface behavior that affects fluid migration. At the same time, mineral reactions, asphaltene deposition, and CO2 pressurization will cause the change of porous media geometry, which will affect the multiphase flow. This review highlights the physical and chemical effects of CO2 injection into unconventional reservoirs containing a large number of micro-nanopores. The interactions between CO2 and in situ fluids and the resulting unique fluid phase behavior, gas-liquid equilibrium calculation, CO2 adsorption/desorption, interfacial tension, and minimum miscible pressure (MMP) are reviewed. The pore structure changes and stress distribution caused by the interactions between CO2, in situ fluids, and rock surface are discussed. The experimental and theoretical approaches of these fluid-fluid and fluid-solid reactions are summarized. Besides, deficiencies in the application and safety assessment of CCUS in unconventional reservoirs are described, which will help improve the design and operation of CCUS.