CO2 Sequestration In Saline Aquifers Research Articles

Fully coupled THM modeling of CO2 sequestration in depleted gas reservoirs considering the mutual solubilities in CO2-Hydrocarbon gas-brine systems

In recent years, CO2 geological sequestration has gained significant traction as a viable solution for mitigating global emissions. However, assessing such processes has been challenging due to its inherent complexity. Given the extensive temporal and spatial scales, numerical modeling has emerged as the most efficient and cost-effective means of evaluating them. At present, most existing models are tailored for CO2 sequestration in saline aquifers. There are relatively few models available for depleted gas reservoirs, and only a fraction of them possess the capability to account for geomechanical coupling or complex natural gas compositions.CO2 sequestration in depleted gas reservoirs is considered a promising technique for combating global warming. The use of depleted gas reservoirs has several advantages over saline aquifers, such as the availability of existing facilities and the proven capacity and stability of gas storage. It is believed that CO2 storage in depleted petroleum reservoirs can provide intermediate-scale storage until large-scale storage in saline aquifers becomes mature.Here we propose an Equation of State (EOS) module for CO2 sequestration in depleted gas reservoirs or CO2-enhanced gas recovery. It takes into consideration the mutual solubilities in the CO2-hydrocarbon gas-brine system based on the equality of the chemical potentials of the aqueous and non-aqueous phases. In such a way, it can properly address CO2 dissolution into brine when hydrocarbon gas is present. Hydrocarbon gas includes methane, ethane, and propane. It employs well-recognized approaches to calculate the thermodynamic properties of the gaseous and aqueous phases. This EOS module has been applied to our in-house simulator, TOUGH2-CSM, to enable thermo-hydrological-mechanical modeling. Our research could fill the gap and provide a reference for future studies in this regard.

Application of biopolysaccharide green foam fluid to enhance CO2 sequestration in high-temperature and high-salinity saline aquifer

Saline aquifer, a geological body, is widely distributed in the world and has high CO2 sequestration potential. Due to the large differences in viscosity and density between the CO2 and brine and the micro-heterogeneity of the saline aquifer, CO2 override, and viscous fingering may occur in strata, resulting in low CO2 sequestration efficiency. Following the concept of green chemistry, this study formulated CO2 foam using biopolysaccharides and a green surfactant alkyl polyglycosides (APG), to enhance the CO2 sequestration efficiency in saline aquifers. The ability of three biopolysaccharides (diutan gum, welan gum and xanthan gum) to stabilize CO2 foam was explored. According to the foam drainage activation energy and the Ostwald ripening rate, the CO2 foam with diutan gum as the stabilizer and APG as the foaming agent exhibited the favorable performance. The mechanism of diutan gum stabilizing CO2 foam was analyzed through studies on intermolecular interactions, interfacial properties, rheology, and micromorphology studies. We then investigated the effects of foam quality and flow rate on the CO2 foam rheology in sandstone cores by analyzing the changes in CO2 saturation, the matching relationship between bubble diameters under different conditions and sandstone core pore size, and the variation in foam rheology was explained. Furthermore, the ability of CO2 foam to enhance CO2 sequestration was explored in saline aquifers using core-nuclear magnetic resonance techniques. CO2 foam largely reduces the water saturation of macropores and establishes high-seepage resistance to facilitate CO2 foam diversion to the meso- and micropores. This fully leverages the space in these pores to store CO2 and greatly improves CO2 sequestration in saline aquifers.

Interfacial chemical mechanisms of brine salinity affecting the CO2 foam stability and its effect on the sequestration capacity of CO2 in deep saline aquifer

CO2 foam flooding is an important method to expand the sweep scope of CO2 and significantly improve the ability of sequestrate CO2 in saline aquifer. Salinity is an important factor affecting the CO2 foam stability. In this study, it was found that the stability of CO2 foam prepared by alkyl polyglycoside APG-0810 was effectively improved by increasing the salinity. Molecular dynamics studies showed that increasing salinity promoted the adsorption of APG-0810 molecules at the CO2-water interface and enhanced the degree of inter-entanglement between alkyl chain segments, which dramatically increasing the CO2-water interfacial activity and liquid film strength. The enrichment degree of metal ions around the APG-0810 hydrophilic group also enhanced with the increase of salinity, which improves the disjoining pressure of the bubble liquid film. The binding ability of the hydrophobic groups of APG-0810 on CO2 molecules was enhanced, which inhibited the diffusion process of CO2 molecules inside the bubble. Subsequently, the influence rules of salinity on the CO2 foam rheology in the core were studied, and finds that increasing salinity increase the transition foam quality and the corresponding maximum viscosity. The improvement of liquid film strength reduces the probability of bubble aggregation inside the core, allowing a sufficient number of small-sized bubbles to be trapped by the pores, strengthening the superposition of Jamin effect and expanding the CO2 sweep scope in saline aquifer. In addition, we found that the zero-shear viscosity and yield stress of CO2 foam are positively correlated with salinity, which means that CO2 foam has a higher blocking ability for preferential channel for high-salinity saline aquifer, and the bubble cluster trapped by the capillary force will have a higher starting-pressure, improving the safety of CO2 sequestration in saline aquifer.

A Study on the Dissolution Behavior of Typical Minerals in Continental Deposited Reservoirs during CO2 Geological Storage

CO2 sequestration in saline aquifers is one of the most potential sequestration modes, and saline aquifers are ideal sites for CO2 geological sequestration. After CO2 is injected into a saline aquifer, it will have a long-term complex geochemical reaction with the formation of minerals and water, and the minerals will undergo multiple reactions such as dissolution and reprecipitation. Therefore, an in-depth study of the geochemical reaction mechanisms between CO2 and formation minerals is of great significance to the accurate calculation and prediction of CO2 storage volume and the safety evaluation of long-term CO2 sequestration. In China, continental saline aquifers are widely distributed, whose mineral compositions and texture maturity are markedly different from those of the marine sedimentary basins in North America, and their stratigraphic environments are more complicated. The studies on the CO2–water–rock (mineral) still have many research gaps or insufficiencies, and there is no report on the dissolution mechanisms of individual minerals in the reaction. Taking one certain block of Daqing Oilfield, which is a typical continental deposit in China, as an example, we analyze the dissolution laws and four types of typical continental deposited minerals under the effect of CO2 and the change features of ionic compositions and pH of the formation water in the process of geochemical reaction. The research results indicate that CO2 has different dissolution degrees for the four types of minerals, among which, feldspar, as the main mineral in continental sedimentary formations, has the lowest dissolution rate. Furthermore, in terms of the water type (Na+-enriched NaHCO3) of the saline aquifer in the deep part of the continental deposit, feldspar can precipitate into the secondary minerals represented by dawsonite in the later stage, which can act as the potential minerals of carbon fixation to increase the CO2 mineralization storage volume in continental deposited saline aquifers.

Molecular dynamics and experimental study of the effect of pressure on CO2 foam stability and its effect on the sequestration capacity of CO2 in saline aquifer

CO2 foam flooding technology is one of the important methods to improve the efficiency of CO2 sequestration in saline aquifers. This article explores the influence rules of pressure on CO2 foam stability and its micro-mechanisms, and its effect on the efficiency of CO2 foam to enhance CO2 sequestration. Increasing pressure is conducive to delaying the foam drainage and inhibiting CO2 diffusion between the liquid films, micro-mechanisms showed that the binding effect of surfactants on water and CO2 molecules was enhanced due to increased pressure. Then core-nuclear magnetic resonance was used to study the effect of pressure on CO2 sequestration characteristics from core scale, the bubble population accumulation in the macropores increased with the enhanced pressure, promoting the diversion effect of foam to the meso- and micropores. In addition to enhancing the CO2 sequestration potential of the macropores, the utilization of storage space of meso- and micropores was improved.

Integrated Formation Evaluation for Site-Specific Evaluation, Optimization, and Permitting of Carbon Storage Projects

Participation in over 80 carbon capture and sequestration (CCS) projects spanning 25 years has led to the evolution of a recommended well-based appraisal workflow for CO2 sequestration in saline aquifers. Interpretation methods are expressly adapted for CCS applications to resolve key reservoir parameters, constrain field-scale modeling, provide answers required for the permitting process, and de-risk unique CCS evaluation challenges, such as Storage capacity Injectivity Containment. A challenge complicating all of the above is the eventual impact of three-way interaction among rock matrix, brine, and (impure) CO2 streams. Most logging, sampling, and laboratory techniques are adapted from established domains such as enhanced oil recovery, underground gas storage, and unconventional reservoir evaluation, though some CCS-specific innovation is also needed. Storage evaluation begins with established methods for lithology, porosity, permeability, and pressure, while special core analysis (SCAL) determines CO2 storage efficiency and relative permeability. Containment evaluation spans multiple disciplines and methods: the petrophysicist’s task to quantify seal capacity relies heavily on laboratory analysis, while geologists leverage downhole imaging tools to verify caprock structural/tectonic integrity. Geomechanics engineers define safe injection pressure via mechanical earth models (MEMs) built on advanced acoustic logs calibrated by core geomechanics, wellbore failure observations, and in-situ stress tests. The impact of rock-brine-CO2 interactions is studied via custom SCAL experiments and/or pore-scale digital rock simulations that rigorously represent chemical and thermal processes. Wireline formation tester samples provide representative formation brine as feedstock for SCAL. Water samples also enable operators to prove injection within regulatory limits while establishing baselines for future monitoring programs. Examples applied to recent CCS projects in North America are presented. All of the above data need to be integrated into a CCS model predicting the CO2 plume behavior across the area of interest and within multiple horizons.

The Impact of Relative Permeability Hysteresis on CO2 Sequestration in Saline Aquifer

This work analyzed the amount of capillary-trapped CO2 for maximum residual gas saturation due to relative permeability hysteresis. Upward migration of CO2 is unwanted because it increases the risk of CO2 migration from storage sites to the surface. One way to mitigate CO2 leakage risk is to reduce the vertical CO2 migration to improved storage capacity and containment security. A compositional simulator (CMG-GEM) was used to simulate the flow of two components (CO2 and H2 O). A fluid model was built with the PR 78 EOS using WINPROP. A base case model without relative permeability hysteresis was simulated and compared with the case with relative permeability hysteresis. The amount of CO2 trapped, and CO2 saturation distribution were analyzed for maximum trapped gas saturation of 0.3, 0.4 and 0.5. Results shows an increase in the amount of CO2 trapped as the maximum residual gas saturation was increased from 0.3 to 0.4 and 0.5 with a value of 16560128mol for the base case study, 49041744mol, 59502924mol and 67286728mol respectively for maximum residual gas saturation due to relative permeability hysteresis of 0.3, 0.4 and 0.5 respectively. Very little accumulation of CO2 occurs when the maximum trapped gas saturation due to relative permeability hysteresis was set at 0.5. Result reveals that after 200 years, almost all the CO2 was trapped in the formation. Therefore, the imbibition cycle at the trailing end of the CO2 plume should be considered as accounting for hysteresis effects has led to a spread-out distrib

Density-Driven Convection for CO2 Solubility Trapping in Saline Aquifers: Modeling and Influencing Factors

Industrial development has significantly increased the concentration of CO2 in the atmosphere, resulting in the greenhouse effect that harms the global climate and human health. CO2 sequestration in saline aquifers is considered to be one of the efficient ways to eliminate atmospheric CO2 levels. As an important mechanism, the solubility trapping greatly determines the efficiency of CO2 sequestration in saline aquifers, and this depends, in turn, on the density-driven convection that occurs during the sequestration. Density-driven convection is influenced by multiple factors. However, existing discussions on some of these influential factors are still ambiguous or even reach contradictory conclusions. This review summarizes the common modeling approaches and the influence of factors on density-driven convection. We suggest that saline aquifers with high values of depth, permeability, pH, and SO2 impurity concentration are the ideal CO2 sequestration sites. A certain degree of porosity, fractures, stratification, slope, hydrodynamic dispersion, background flow, and formation pressure are also considered advantageous. Meanwhile, the geological formation of the Permian White Rim Sandstone or carbonate is important, but it should not contain brine with excessive viscosity and salinity. Finally, we discuss the contents in need of further research.

Expansion of Geological CO2 Storage Capacity in a Closed Aquifer by Simultaneous Brine Production with CO2 Injection

Structural trapping is the primary mechanism for intensive CO2 sequestration in saline aquifers. This is the foundation for increasing global CO2 storage; gradual switch to preferable trapping mechanisms, such as residual saturation, dissolution, and mineral trapping, will require a long-time scale. The major constraints limiting the storage capacity of structural trapping are formation pressure and structure size. Over-pressure owing to CO2 injection causes a disruption of seal integrity indicating a failure in geological sequestration. The other constraint on storage capacity is a spill point determining geological storage volume. Overflowing CO2, after filling the storage volume, migrates upward along the aquifer geometry with buoyancy. This study proposes a methodology to maximize CO2 storage capacity of a geological site with a substructure created by an interbedded calcareous layer below spill point. This study provides various conceptual schemes, i.e., no brine production, simultaneous brine production and pre-injection brine production, for geological CO2 storage. By the comparative analysis, location of brine producer, production rate, and distance between injector and producer are optimized. Therefore, the proposed scheme can enhance CO2 storage capacity by 68% beyond the pressure and migration limits by steering CO2 plume and managing formation pressure.

An analytical approach to the technical and economical optimization of CO2 sequestration in saline aquifers with simultaneous brine production

In the course of developing innovative approaches for climate change mitigation, CO2 sequestration in saline aquifers has drawn attention to itself as an appealing and effective procedure. Simultaneous brine production facilitates storage capacity enhancement in aquifers through formation depressurization. This study is devoted to developing an analytical optimization model for CO2 sequestration projects with simultaneous brine production from a technical and economical perspective. While previous studies have provided analytical optimization models for simple CO2 injection scenarios, this research aims to improve the former models by utilizing more precise transient pressure calculation formulations, up-to-date economic analysis and extending the models to also account for simultaneous brine production in CO2 storage projects. Through this model, the effect of different design parameters including well spacing, the number of injection and production wells, production-to-injection ratio, and carbon revenue can be assessed on the project's storage capacity and net revenue. Subsequently, the design parameters for the most environmentally and financially beneficial scenarios can be identified. The developed optimization model can serve as a fast and accurate pre-implementation tool for the case by case assessment and comparison of different CO2 sequestration project designs. In order to put the model to test, the developed multi-well pressure evolution formulation is used to predict pressure changes in a synthetic aquifer formation throughout several sequestration projects. This profile is then compared with numerical simulation results. The maximum CO2 injection rate and thus storage capacity for numerous project designs is then calculated based on a correlation between a reference injection rate, the time-dependant pressure profile for this rate and the aquifer's formation fracture pressure. Finally the effect of different design parameters is assessed on the storage capacity and net revenue and the fundamentals of selecting the best project design is discussed.

Review of CO2 sequestration mechanism in saline aquifers

The concentration of CO2 in the global atmosphere, which is increasingly annually with continued industrial development, affects both the global climate and the ecological environment. To control the concentration of atmospheric CO2, various methods of carbon capture and sequestration have been proposed and continue to be developed. Among them, CO2 sequestration in saline aquifers has potential for effective high-capacity carbon storage. This work reviews both the research status of structural, residual, solubility, and mineral CO2 sequestration in saline aquifers, and the research progress associated with the integrity of cement sheaths and caprocks. The findings indicate that structural sequestration research must comprehensively consider the influence of various factors, and that the capacity of structural sequestration must be evaluated based on the actual geological conditions of the saline aquifer, caprock properties, and CO2 injection rate. The heterogeneity of the caprock and dynamic changes of CO2 concentration are not considered in current simulations of the effect of chemical interaction between CO2-rich brine and the caprock. Residual sequestration and solubility sequestration are mutually interactive; therefore, exploration of the residual sequestration mechanism must consider the impact of solubility sequestration. Models for simulation of CO2 solubility sequestration in an entire saline aquifer should be developed to reservoir scale and must consider reservoir heterogeneity.

Insights from molecular dynamics on CO2 diffusion coefficient in saline water over a wide range of temperatures, pressures, and salinity: CO2 geological storage implications

Successful design and execution of CO2 sequestration in saline aquifers requires a comprehensive understanding of CO2 transport properties. CO2 diffusion coefficient affects CO2 dissolution behavior in water/brine and controls phenomena such as shape of viscous fingers and onset of instabilities. Experimental determination of CO2 diffusion coefficient is a technically and economically challenging task. In this research work, we used Molecular Dynamics (MD) simulation to compute CO2 diffusion coefficient in various NaCl saline water concentrations (1–6 mol NaCl/kg water) under a broad range of temperatures (294–423 K) and pressures (10–30 MPa) to acquire a data set for CO2 diffusion coefficient in different conditions. According to the results, NaCl concentration increase gives rise to a decrease in CO2 diffusion coefficient by 15%, 29%, 49%, and 64% at 1 M, 2 M, 4 M, and 6 M solutions, respectively, compared to pure water. Presence of more cations due to salinity increase forms further hydration shells act as a barrier for CO2 diffusion. In addition, the rise in CO2 diffusion at elevated temperatures can be explained by the cation's hydration shell size reduction with temperature increment due to intensifying repulsive forces among water molecules. We proposed a new precise correlation for estimation of CO2 diffusion coefficients over temperatures and salinity ranges of this study. Regarding the pressure variation effects, no tangible changes were observed with pressure increase, validating a negligible influence on diffusion coefficient. Furthermore, the CO2 diffusion coefficient variability in presence of other salts, namely MgCl2, CaCl2, KCl, and Na2SO4, were computed separately. Comparing the influence of various salts, CaCl2 and KCl have the highest and lowest effect on the CO2 diffusion coefficient, respectively. Finally, a set of direct numerical simulations were conducted to study the impact of CO2 diffusion coefficient on CO2 dissolution process. The results obtained from this research work shed light on the importance of CO2 diffusion coefficient changes in saline water for prediction of dissolution process behavior.

Influence of Brine–Rock Parameters on Rock Physical Changes During CO2 Sequestration in Saline Aquifer

Influence of Brine–Rock Parameters on Rock Physical Changes During CO2 Sequestration in Saline Aquifer

Diffusion coefficients of CO2–SO2–water and CO2–N2–water systems and their impact on the CO2 sequestration process: Molecular dynamics and dissolution process simulations

AbstractThe high cost of the CO2 sequestration in saline aquifers is a barrier to the implementation of them. However, a large portion of the cost is invested to purify and transport the CO2 from the flue gas stream of the emission sources. Therefore, the possibility of injecting impure CO2 will reduce the costs strongly. The diffusion coefficient is an important factor that plays a significant role in different aspects of the process. In spite of its importance, it is got less attention due to complex experimental procedures and low range of temperature and pressure applicability in the experimental conditions. To shed light on the effects of the impurity on the diffusion coefficient of CO2‐water systems, two types of impurities (SO2 and N2) in two levels are considered in this study through the molecular dynamics simulation approach. Simulations are done on a wide range of pressure and temperature conditions to cover a wide range of operational conditions for CO2 sequestration projects. The outcomes of these simulations were used in the direct numerical simulations to analyze the effect of the diffusion coefficient matrix changes on the CO2 dissolution process such as dissolution flux, the motion and shape of convective fingers, and their patterns. Results indicate that impurity has a great impact on the diffusion coefficient, and consequently on the CO2 dissolution behavior. We hope that reported results will pave the way for future studies regarding impure CO2 sequestration in saline aquifers. © 2021 Society of Chemical Industry and John Wiley & Sons, Ltd.

Investigation on CO2 permeation in water-saturated porous media with disordered pore sizes

CO2 sequestration in saline aquifers is considered to be a promising method for climate mitigation. Studies of the subsurface flow mechanisms of CO2–brine are important for evaluation of sequestration potential and security. However, this process is complicated by the intrinsic heterogeneity of reservoir rocks. The main objective of this study was to identify CO2 distribution and saturation related to changing injection conditions, and to comprehensively compare the characteristics of different drainage processes, under small scale heterogeneous condition. An X-ray computed tomography machine and a micromodel were introduced to investigate the CO2/brine drainage process from pore to core scale in a wide range of injection rates at static and transient states, respectively. Four types of drainage experiments were conducted. Horizontal and vertical (upward) flow directions in a micromodel setup at ambient conditions and vertical (upward and downward) flow directions in a core-flood setup at in-situ conditions. Based on experimental results, it is found that, a higher injection rate gives rise to a higher displacement efficiency but a lower sweep efficiency. The stability of CO2 displacing front become weak with drainage development. The difference in pore structure leads to different CO2 saturation variation with CO2 injection rates change. Even the sand pack is almost homogenous at core scale, the impact of heterogeneous porosity is enhanced with increasing flow rates in upward drainage, while it weakens in downward drainage.

Application of an artificial neural network in predicting the effectiveness of trapping mechanisms on CO2 sequestration in saline aquifers

Predicting the effectiveness of geological CO2 storage and evaluating the field application of successful CO2 sequestration require a large number of case studies. These case studies that incorporate geologic, petrophysical, and reservoir characteristics can be achieved with an artificial neural network. We created an artificial neural network model for geological CO2 sequestration in saline aquifers (ANN-GCS). To train and test the ANN-GCS model, data of residual and solubility trapping indices were generated from a synthetic aquifer. Training and testing were conducted using Python with Keras, where the best iteration and regression were considered based on the calculated coefficient of determination (R2) and root mean square error (RMSE) values. The architecture of the model consists of eight hidden layers with each layer of 64 nodes showing an R2 of 0.9847 and an RMSE of 0.0082. For practical application, model validation was performed using a field model of saline aquifers located in Pohang Basin, Korea. The model predicted the values, resulting in an R2 of 0.9933 and an RMSE of 0.0197 for RTI and an R2 of 0.9442 and an RMSE of 0.0113 for STI. The model was applied successfully to solve a large number of case studies, predict trapping mechanisms, and optimize relationships between physical parameters of formation characteristics and storage efficiency. We propose that the ANN-GCS model is a useful tool to predict the storage effectiveness and to evaluate the successful CO2 sequestration. Our model may be a solution to works, where conventional simulations may not provide successful solutions.

Modeling, Simulation, and Optimization of Geological Sequestration of CO2

With heightened concerns on carbon dioxide (CO2) emissions from coal power plants, there has been a major emphasis in recent years on development of safe and economical geological carbon sequestration (GCS) technology. However, the detailed multiphase fluid dynamics and processes of GCS are not fully understood because various CO2 trapping mechanisms in geological formations have large variations in both spatial and temporal scales. As a result, there remain many uncertainties in determining the sequestration capacity of the reservoir and the safety of sequestered CO2 due to leakage. Furthermore, the sequestration efficiency is highly dependent on the CO2 injection strategy, which includes injection rate, injection pressure, and type of injection well, and its orientation, etc. The goal of GCS is to maximize the sequestration capacity and minimize the plume migration by optimizing the GCS operation. In this paper, first the basic fluid dynamics and trapping mechanisms for CO2 sequestration are briefly discussed. They are followed by a brief summary of current GCS projects worldwide with special emphasis on those in the United States. Majority of the paper is devoted to the numerical modeling, simulation, and optimization of CO2 sequestration in saline aquifers at macro spatial scales of a few to hundreds of kilometers and macro temporal scales of a few to hundreds of years. Examples of numerical simulations of a few large industrial scale projects are presented. The optimization studies include the investigation of various injection and well placement strategies to determine the optimal approach for maximizing the storage and minimizing the plume migration.

Estimation of Interfacial Tension for Geological CO2 Storage

AbstractThe effective CO2 sequestration in saline aquifers as a climate change‐lessening solution is mainly governed by the interfacial tension (IFT) behavior between CO2 and brine. An innovative and competent decision tree‐based approach called stochastic gradient boosting (SGB) tree algorithm was applied to predict the CO2‐aquifer brine IFT as a function of temperature, pressure, and brine salinities. The produced results were compared with the previously reported outcomes of other machine learning models, namely, radial basis function networks, multilayer perceptron networks, least squares support vector machine, and adaptive neuro fuzzy inference system. Amongst all models, the developed SGB tree algorithm provided superior outputs and turned out to be the most accurate tool.

Liquid CO2 behaviour during water displacement in a sandstone core sample

CO2 sequestration in saline aquifers and hydrocarbon reservoirs is a potential strategy to reduce CO2 concentration in the atmosphere, enhance hydrocarbon production, or extract geothermal heat. CO2 injection is considerably influenced by the interfacial interactions, capillary forces and viscous forces. Any change in the subsurface conditions of pressure, temperature, and salinity is likely to have an impact on the interfacial interactions, capillary forces and viscous forces, which, in turn, will have an influence on the injection, migration, displacement, and CO2 storage capacity. In this study, unsteady-state immiscible experimental investigations have been performed to explore the impact of fluid pressure, temperature, salinity (brine concentration and valency) and injection rate on the dynamic pressure evolution and displacement efficiency when CO2 as a liquid phase is injected into a water-saturated sandstone core sample. This study also highlights the impact of capillary forces and viscous forces on the two-phase flow properties and shows when capillary forces or viscous forces are dominant. The results reveal a moderate to considerable impact for the fluid pressure, temperature, injection rate, and salinity on the differential pressure profile, water recovery (WR), endpoint CO2 relative permeability (KrCO2), and cumulative produced volumes. Overall, increasing fluid pressure, CO2 injection rate and salinity (brine concentration and valency) cause an increase in the differential pressure profile; the highest increase occurred with the injection rate. In general, increasing temperature caused a reduction in the differential pressure profile. The WR is in range of around 61.6–69.3% while the KrCO2 is in range of 0.112–0.203, depending on the parameters investigated. Increasing fluid pressure and injection rate caused an increase in the WR; the highest increase occurred with the injection rate. On the other hand, increasing temperature and salinity caused a decrease in the WR; the highest reduction occurred with salinity. Nevertheless, the increase in fluid pressure, temperature, injection rate and salinity led to a reduction in the KrCO2; the highest reduction occurred with increasing temperature whilst the lowest occurred with increasing fluid pressure. The cumulative produced volumes decreased with fluid pressure and salinity but showed no noticeable change with temperature and injection rate. The capillary forces have less impact on the differential pressure profiles than viscous forces when fluid pressure, temperature and injection rate increase but the capillary forces show more impact as salinity increase.

The Effect of CO2 Phase on Oil Displacement in a Sandstone Core Sample

CO2 sequestration in saline aquifers and hydrocarbon reservoirs is a promising strategy to reduce CO2 concentration in the atmosphere and/or enhance hydrocarbon production. Change in subsurface conditions of pressure and temperature and CO2 state is likely to have a significant impact on capillary and viscous forces, which, in turn, will have a considerable influence on the injection, migration, displacement, and storage capacity and integrity of CO2 processes. In this study, an experimental investigation has been performed to explore the impact of fluid pressure, temperature, and injection rate, as a function of CO2 phase, on the dynamic pressure evolution and the oil recovery performance of CO2 during oil displacement in a Berea sandstone core sample. The results reveal a considerable impact of the fluid pressure, temperature, and injection rate on the differential pressure profile, cumulative produced volumes, endpoint CO2 relative permeability, and oil recovery; the trend and the size of the changes depend on the CO2 phase as well as the pressure range for gaseous CO2–oil displacement. The residual oil saturation was in the range of around 0.44–0.7; liquid CO2 gave the lowest, and low-fluid-pressure gaseous CO2 gave the highest. The endpoint CO2 relative permeability was in the range of about 0.015–0.657; supercritical CO2 gave the highest, and low-pressure gaseous CO2 gave the lowest. As for increasing fluid pressure, the results indicate that viscous forces were dominant in subcritical CO2 displacements, while capillary forces were dominant in supercritical CO2 displacements. As temperature and CO2 injection rates increase, the viscous forces become more dominant than capillary forces.