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Summary Using seawater or engineered water to inject into oil formations can cause inorganic scaling, such as calcium sulfate, barium sulfate, and strontium sulfate. These scales may clog pore throats and limit production. Scale inhibitor (SI) squeeze treatment reduces inorganic scaling and improves oil recovery. Chemical compounds called SIs suppress or delay mineral scaling. SIs fall into two categories, each with its own mechanism. Most polymeric inhibitors impede nucleation, whereas phosphonate SIs deform crystal formation. The oil and gas industry now uses a fixed mixture of these inhibitors to maximize all inhibition mechanisms. However, the impact of blended SIs on fluid/fluid and rock/fluid interactions has not been addressed. This study aims to evaluate the efficiency of blended SIs when dealing with three well-known mineral scales all together. In this study, first, the process of mineral scale formation was simulated using PHREEQC (pH-REdox-EQuilibrium), and the impact of temperature and mixing ratios was investigated. Then, by choosing a proper temperature and mixing ratio, the effect of polymeric and phosphonate SIs blending on barium, calcium, and strontium sulfate inhibition is examined. Additionally, fluid/fluid interactions and rock/fluid interactions were studied via interfacial tension and contact angle measurements. The influence of seawater mixing ratio on calcium, strontium, and barium sulfate saturation indices is medium, low, and very low, respectively, but the effect on the amount of scale precipitation is very high, high, and low for the scales indicated. This adds to the fact that barium takes precedence in scale formation, and its presence may affect the other two scales, but calcium ions have barely any effect on barite formation. Moreover, the results show a positive synergistic effect of SIs blend on sulfate scale mitigation. However, this positive figure completely depends on the concentration of phosphonate SI for calcium and strontium sulfate, while the positive synergy exists at all concentrations of phosphonate SIs for barium sulfate. Moreover, SIs could lower the water/oil/rock contact angle by 10° on average and make it more water wet. Same enhanced results have been achieved for interfacial tension by adding SIs, reducing by 8 dynes/cm on average. It is worth noting that the interfacial tension and contact angle measurements are unaffected by the synergistic action of SIs mixing. The results of coreflooding experiments substantiate the effectiveness of SIs and show 8 and 45% permeability reduction for injection of seawater with and without SIs on two different core samples, respectively. For the first time in a sulfate scaling system, this work investigates the copresence of barite, celestite, and anhydrite against a wide range of blending SI concentrations. Based on the results, it is derived that the presence of all three sulfate scales undoubtedly affect the quantity of each scale’s precipitation and the efficacy of SIs.

Most oil reservoirs are first saturated with water and become oil-wet gradually due to oil migration and accumulation. Previous studies reported that the adsorption of hydrocarbon components onto the rock surface during a considerable time caused wettability alteration from primarily water-wet to oil-wet. However, few studies fundamentally reviewed the effects of the ionic composition of formation water on the process of the rock surface wettability alteration from water-wet to oil-wet using advanced surface analysis tools. In this research, wettability alteration of calcite surface from water-wet to oil-wet and (in the next step) from oil-wet to water-wet was studied using a specific carboxylic acid (stearic acid), normal decane, and three single salt aqueous phases. During this research, the surface was analyzed using contact angle and scanning electronic microscopy. Results showed that using deionized water as an aqueous phase caused maximum surface adsorption of carboxylic components and minimum adsorption occurred in the presence of the MgCl2 aqueous phase. The carboxylic acid adsorption onto the calcite surface was controlled by interactions of negative ions formed during dissociation of carboxylic acids and positive salt ions present in brine solvents.

In recent years, many studies have been conducted on the method of low-salinity water (LSW) injection and its effect on enhanced oil recovery (EOR) of oil reservoirs. The lower operating cost of th...

Carbon dioxide (CO2) sequestration through CO2 enhanced oil recovery (EOR) in oil reservoirs is one way to reduce this gas in the atmosphere. Undesirable chemical reactions that occur during these operations can affect the reservoir structure and characteristics. In this study, the effect of CO2-water-rock interaction on the rock permeability alteration and final oil recovery has been evaluated experimentally during CO2 injection into a carbonate rock. The effect of flow rate, displacement type and pressure were investigated during CO2 EOR injection. Different scenarios of miscible/immiscible displacement, secondary/tertiary recovery has been evaluated for different levels of connate water salinity and injection rate. The results show that the severity of damage is directly related to the injection rate, however change in displacement type from miscible to immiscible reduce the intensity of chemical reactions in porous medium. Moreover, in the tertiary CO2 injection, the chemical reactions become more severe due to the higher water saturations. Interestingly, this growth in the level of chemical reactions has a negligible impact on permeability reduction, since the major volume of possible reactions occurs in coarse and high permeable pores. Results reveal that damage is more intense in the case of more saline water.

Implicit texture/empirical foam model is one of the most commonly used approaches for enhanced oil recovery; however, a comprehensive set of standard steps of a foam simulation study is not yet introduced. In this paper, a practical package consisting of different methods/steps has been compiled. In addition, their strengths, weaknesses, and challenges are described. This paper has shown that surfactant formula can have a substantial impact on probability of micro-emulsion (ME) creation or rock curves alteration during foam injection. Depending on the severity of surfactant influence on rock and fluid properties, capillary pressure and relative permeability curves should be modified or viscosity model should be corrected in the case of ME formation. This review has studied distinct approaches for the modification of rock curves or the correction of viscosity in the presence of ME. From a review of literature, foam flood experiments can be carried out in distinct media. Foam behavior, however, in core flood experiments resembles more the foam performance in reservoir condition. Various well-known algorithms for obtaining foam model parameters are explained and compared here. Based on differences between experimental conditions and pilot tests, up-scaling simulation parameters, including foam model and adsorption coefficients, are described extensively. Because media permeability has a significant effect on foam model parameters, it is also shown here that considering more than one foam model for simulation can increase the precision of results.

We have used the Maxwell–Stefan diffusion theory to model the mass transfer between tertiary-injected gas and residual oil blocked by water, in order to predict the time required for the rupture of the water barrier due to oil swelling. We have also designed and conducted a set of visualization micromodel experiments on various pure and multicomponent oil–gas systems to measure the water rupture time in tertiary gas injection processes. The experimental results show that the initial pressure and dimensions of the system, the oil and gas composition, and the gas solubility in water control the oil swelling process. The experimentally measured rupture times are then employed to evaluate the reliability of the model and to compare its accuracy with that of a similar one using classical Fick's law. Our modeling results show that both models are able to estimate the water rupture time for pure systems with an acceptable precision. As for multicomponent mixtures, however, only the Maxwell–Stefan theory is capable of modeling the molecular diffusion process correctly and yields values close to reality, while the use of Fick's law would lead to erroneous results. Deficiency of the latter model becomes more acute when the diffusion direction in reality is contrary to what the model indicates, which leads to failure in calculating any value for rupture time at all for these cases.

This paper presents an experimental study to show the impact of Benard Marangoni flow (type of Marangoni convective flow caused by temperature variation on the interface of fluids) on fluid flow in porous media. The importance of marangoni mechanism has been rarely addressed in the oil recovery mechanisms in the related literature. In this regard, cold gas (Carbon dioxide or methane) has been injected into a fractured system to recover the bypassed oil in matrix via convective fluxes induced by interfacial tension gradient. Results demonstrate that the thermal Marangoni flow improves oil recovery significantly by enhancing the flux of oil/injectant from/into the matrix. Furthermore, the amount and rate of oil recovery are proportional to Marangoni number. Marangoni flow in carbon dioxide injection is much stronger than methane injection, owing to larger amount of interfacial tension gradient.

In this study, the researchers visually investigated changes in the saturation of fluids and the oil recovery factor (RF) during foam injection in a two-dimensional matrix-fracture micromodel system. The effects of the 1) presence of oleic phase (comparison of the results of foam injection tests with and without oil), 2) viscous force (comparison of the results of foam and gas injection tests), and 3) gravity force (comparison of the results of gas/foam injection tests in vertical and horizontal states) were mechanistically studied. The results showed that the presence of oleic phase has the potential to cause foam to degrade at the beginning of the test. However, as the experiment advanced and oil saturation was reduced, foam injection resulted in the recovery of the fluid in the matrix. Pressure decline in the fracture due to the high viscosity of the foam acted as a driving force perpendicular to the fracture in the matrix and caused a viscous cross-flow leading to a dramatic increase in oil recovery. Although the gravity force reduced the foam stability due to the foam film drainage process and the gravity segregation of gas and surfactant solution, a comparison of the performances of gas and foam in the vertical state revealed the superiority of foam injection.

In this study, the effects of amphiphilic water-soluble components of crude oil and ionic composition of water were investigated on the wettability alteration of a carbonate surface. Four different types of saltwater, which are made up of NaCl, MgCl2, CaCl2, and Na2SO4, with 0.5 M ionic strength, besides distilled water, were contacted with crude oil to be saturated with water-soluble components. The post-contact (after contact with crude oil) water properties were characterized by Fourier transform infrared spectroscopy, total organic carbon, and pH analyses. The results showed that some polar compounds of crude oil with basic and mostly acidic functional groups were transferred to saltwater and distilled water. Afterward, the oil-wet carbonate surface was soaked in both freshwater (not contacted with crude oil) and post-contact water, and their effects on the wettability of the surface were investigated through contact angle and scanning electron microscopy experiments. The results of the contact angle ...

We study the effect of brine composition on CO2 dissolution in brine. In particular, we address the effect of brine composition on the onset of convection through experiments, numerical simulations, and theoretical analyses. We use two brine solutions—one containing sodium chloride (NaCl) and one containing mixtures of NaCl and calcium chloride (CaCl2)—to study their differences in terms of the onset of convection. We perform experiments in isothermal conditions (∼50 C) with pressure range of 500–535 psi for different salinities and permeabilities (Rayleigh number of 2900 to 4900). Our experimental conditions and set-up design allow us to avoid problems associated with analogue fluids as well as with blind cells. We also conduct linear stability analysis (LSA) and high-resolution direct numerical simulations (DNS). We analyze pressure data and calculate other parameters such as diffusion coefficient, viscosity, and solubility. Specifically, we obtain the onset of convection from pressure decay curves and critical wave number from image analyses. We show that the onset of convection occurs earlier with higher wave number in brine solutions containing NaCl. Pressure results show that using mixture of NaCl and CaCl2 results in a higher CO2 diffusion coefficient, which in turn damps convective instabilities. Thus, the onset time of instabilities is later and finger growth rate is smaller for brines with NaCl and CaCl2. Our DNS results show that deviation between the cumulative dissolved CO2 as well as the dissolved CO2 due to only diffusion process occurs earlier for NaCl solution. We found a dimensionless Rayleigh-dependent onset of instability with parameters that are close for two mixtures. However, differences in the CO2 diffusivity result in smaller Rayleigh numbers for NaCl and CaCl2 containing mixtures. Our results have practical implications for CO2 geological sequestration in saline aquifers.

Summary In this study, wettability alteration, fine migration, and double-layer expansion mechanisms in a particular condition are investigated to find the predominant mechanism. Amott-Harvey and zeta potential tests were performed to study wettability and ion strength variations, respectively. The results of Amott-Harvey indicated wettability alteration from oil-wet to neutral-wet conditions by LSW injection. Zeta potential measurements suggested that the reduction of salinity leads to double-layer expansion; and an increase in wetting affinity of rock towards more water-wet conditions. Also, the fine movement mechanism did not have a significant effect on this process.

Summary Advantage of CWI over WI and CO2 injection for an Iranian heavy oil reservoir, is studied through core flooding experiments. Five different experiments were conducted in different wettability states using secondary and tertiary injection scenarios. The results showed that CWI is more beneficial than WI and CO2 injection. Higher sweep efficiency, more stable front, CO2 diffusion to oil and subsequent oil viscosity reduction and swelling are the reasons for better CWI performance. Moreover, due to the lower sweep efficiency of WI and low resistance channels created along the flow axis, tertiary CWI is not capable to recover all the bypassed oil, so its recovery is less than secondary CWI. The results of aged experiments indicated that by shifting wettability toward mixed wet, CWI performance decreased in both WI and secondary CWI. In mixed wet wettability several pores which were accessible for injection fluid in clean sand, are not reachable in aged sand anymore which accelerated injection fluid breakthrough and decreased ultimate recovery. Besides, it was observed that the proportion of recovery after breakthrough to the total recovery was increased for SCWI while decreased for WI, this is attributed to the acidic nature of carbonated water and consequent wettability alteration.

Gravity drainage is known as the controlling mechanism of oil recovery in naturally fractured reservoirs. The efficiency of this mechanism is controlled by block-to-block interactions through capillary continuity and/or reinfiltration processes. In this study, at first, several free-fall gravity drainage experiments were conducted on a well-designed three-block apparatus and the role of tilt angle, spacers’ permeability, wettability and effective contact area (representing a different status of the block-to-block interactions between matrix blocks) on the recovery efficiency were investigated. Then, an experimental-based numerical model of free-fall gravity drainage process was developed, validated and used for monitoring the saturation profiles along with the matrix blocks. Results showed that gas wetting condition of horizontal fracture weakens the capillary continuity and in consequence decreases the recovery factor in comparison with the original liquid wetting condition. Moreover, higher spacers’ permeability increases oil recovery at early times, while it decreases the ultimate recovery factor. Tilt angle from the vertical axis decreases recovery factor, due to greater connectivity of matrix blocks to vertical fracture and consequent channelling. Decreasing horizontal fracture aperture decreases recovery at early times but increases the ultimate recovery due to a greater extent of capillary continuity between the adjacent blocks. Well match observed between the numerical model results and the experimental data of oil recovery makes the COMSOL multiphysics model attractive for application in multi-blocks fractured systems considering block-to-block interactions. The findings of this research improve our understanding of the role of different fracture properties on the block-to-block interactions and how they change the ultimate recovery of a multi-block system.

Summary Mass transfer rate estimation is an important aspect of the dissolution trapping mechanism analysis during CO2 sequestration in saline aquifers which has been studied extensively in recent years. Based on laboratory experiments or direct numerical simulation tools, scaling relationships have been introduced for the mass transfer rate estimation. However, there are discrepancies between these results. To investigate the discrepancies between experimental and direct numerical simulation results, we carried out a series of experiments to quantify dispersion during CO2 convective mixing, which enabled us to obtain robust scaling relationships. Two brine compositions including sodium chloride (NaCl) and a mixture of NaCl and calcium chloride (CaCl2) are separately considered in two levels with two levels of permeability to encompass the applicable range of the Peclet number (Pe). Furthermore, we conducted a series of high resolution direct numerical simulations to show the applicability of the proposed relationship in simulation. Our analysis of results reveals that a power-law scaling relationship based on the Pe best fits the dispersion values. Furthermore, numerical simulation results show that dispersion has a considerable impact on the pattern and amount of CO2 dissolution in brine.

Summary The behaviour of viscous crossflow was investigated by the co-injection of foam. A fractured model was constructed by using the single porosity model. Foam was injected into the fracture in three different cases. The observed viscous crossflow within the matrix media was confirmed by previously carried out experimental results. Moreover, it was shown that foam behaviour in the fracture and matrix has distinct effects on the diversion of fluids from the fracture to the matrix.

Summary Low-salinity waterflooding (LSWF) is a promising IOR/EOR methodology which has been extensively investigated over the past ten years. However, mixing of the injected brine (low-salinity) with the in-situ high salinity brine (formation water) at the displacement front can decelerate oil recovery by LSWF. We propose that one promising approach to control in-situ mixing is to increase the viscosity of the low salinity injection brine by adding polymer which then improves the mobility ratio at the displacement front and subsequently suppresses dispersion of low salinity in high salinity. This, to our knowledge, has not been addressed before. To investigate systematically the mixing phenomenon in different salinity gradients and its sensitivity to HPAM polymer concentrations, sandpack experiments were designed and executed. Two sets of mixing experiments under single-phase condition were performed to capture the impact of absence or presence of polymer in the low-salinity brine. Our results show that polymer could be used as a mixing-control agent and the dispersivity of the system may be decreased to lower than 0.3 of its original value by adding 200 ppm of polymer.

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.

This paper presents experimental and theoretical studies of the onset of natural convection induced by the dissolution of carbon dioxide- nitrogen (CO2-N2) mixtures into brine. Using a high- pressure Hele-Shaw cell, we conducted four sets of experiments under high-pressure conditions (with initial pressure range of 3375 to 3691 kPa) where 0%, 10%, 20% and 100% (molar base) N2 at different brine salinities and permeability (Rayleigh number of 3120 to 4840) were conducted to obtain quantitative and qualitative data from pressure decay and image analysis respectively. Furthermore, we performed Linear Stability Analysis (LSA) based on the quasi-steady-state approximation and Direct Numerical Simulation (DNS) to theoretically examine the effect of N2 on the onset of convection. We calculated effective diffusion coefficients from experimental data, and then used them in the LSA and DNS analyses. The experimental results confirmed by theoretical analysis revealed that the onset of convection occurred earlier in 10% N2 - 90% CO2 cases than in the pure CO2 cases. On the other hand, the onset of convection for an impure CO2 mixture with 20% N2 was close to that of the pure CO2 system. These findings suggest that, depending on the mole fraction of N2, the presence of N2 as an impurity may impede or promote the onset of natural convection. Since both the solubility and diffusion of CO2 in brine are nonlinear functions of N2 concentration, increasing N2 concentration reduces the solubility and diffusion coefficient, which have opposing impacts on the stability of the diffusive boundary layer.

Summary In the current survey, the time required to rupture the water film shielding the oil as a result of oil swelling caused by the diffusion of dissolved gas in the water phase and trapped oil behind it has been investigated in porous medium at high pressure and temperature. To study the active mechanisms, the experiments have been conducted with two different types of injectants: carbon dioxide (CO2) and methane (with different solubility in water), under different miscibility conditions at equal reduced pressures. Experimental observations have been interpreted using theoretical studies. Furthermore, the time of water-film rupture has been identified in production data and matched by an analytical model. This time and its monitoring during various gas-injectant types and regimes under reservoir conditions have not been previously addressed. The results show that water film reduces the performance of oil recovery by limiting the interface of oil and gas phases. Under such a condition, the best scenario is miscible gas injection because the gas can effectively swell the oil and rupture the water shield. At miscible and near-miscible conditions, the time required to eliminate the water film increases as the injectant solubility in water decreases; however, there is a negligible difference at the immiscible regime. The trend of oil-recovery curves after rupture of the water film shows that oil swelling is one of the main mechanisms involved in water-trapped oil recovery. These results suggest practical guidelines to better understand the effect of the water-shielding phenomenon in the field of tertiary gas injection. The outcome of this integrated study could effectively increase the knowledge of shielded oil recovery using different gas-injectant types under various miscibility conditions and could prepare the required basis for compositional simulation of waterflooded oil production during tertiary gas injection.

Several phenomena could recover the bypassed oil in matrixes and low permeable areas, among them; Marangoni is the most unfamiliar one in fluid flow model. This mechanism triggers a convective flow from low interfacial tension point to a high interfacial tension point because of variation in solvent concentration, temperature or electrical charge. In this study, experimental and analytical tools have been utilized to investigate the effect of thermal Marangoni flux on the enhancement of oil recovery during immiscible injection in a matrix-fracture system. Results of non-isothermal experiments have been compared with isothermal (as the zero level of Marangoni) to study the presence of Marangoni flow and its direction respect to the fracture location. Results show that not only the Marangoni flux does exist and has significant impact on the recovery of bypassed oil but also, its magnitude is proportional to the absolute value of temperature gradient in phases interface.

The performance of CO2 injection into a semi-heavy oil reservoir was investigated at reservoir conditions, using highly permeable sandstone in a complete series of PVT tests and coreflooding experiments. Analysis of involved parameters such as: injection rate, injectant type and reservoir pressure were also considered. Oil viscosity reduction and oil swelling are the most influential mechanisms of enhanced oil recovery in this process. The results demonstrated that CO2 injection would decrease the interfacial tension for the high permeable medium in the absence of capillarity, but this reduction may not improve the recovery drastically. One of the main important aspects of this work is the introduction of a new empirical combined dimensionless group (dissolution number, Ndis) that helps prediction of oil recovery in any other heavy oil reservoir with high permeability of porous media. In this case, a more precise analysis could be performed by applying the dissolution number instead of capillary and/or Bond number.

A detailed investigation into the effect of dissolved amphiphilic compounds of crude oil in salt water on its surface tension/interfacial tension (ST/IFT) behavior has been conducted in this paper. To simulate water–oil contact during water injection into oil reservoirs, 16 single-salt aqueous solutions of NaCl, CaCl2, and Na2SO4 having ionic strengths of up to 2.0 M were mixed with a natural acidic–basic crude oil. The mixing was performed by a rocking mechanism in a visual pressure–volume–temperature cell at an elevated temperature. After the mixing process, two phases were completely separated from each other using a high-temperature centrifuge. Finally, in addition to pH measurements, the air–water ST and decane–water IFT of salt water were measured using the pendant-drop method. The results reveal that the dissolution of crude oil amphiphilic compounds, especially the acidic or basic compounds, in salt water can considerably decrease its ST/IFT. It seems that there is the same optimal ionic strength ...

Summary Diversion in heterogeneous carbonate reservoirs plays the most important role to the success of acidizing. Without the use of diversion, more acid preferentially flows into the high-permeability region and leaves the low-permeability region underreacted. But a clear understanding of diverting agents, such as polymer-based in-situ-gelled acids, can help uniformly stimulate the near-wellbore region. In this paper, we correct the rheological model that was developed by Ratnakar et al. (2013) according to experimental data from Gomaa and Nasr-El-Din (2010b) by considering shear-rate effect in a two-scale continuum model. It is found that the rheology parameters and shear rate are influential parameters in diversion. In addition, the amount of acid required for the breakthrough is found to be strongly dependent on rheology parameters and permeability in single-coreflood simulation. In our study, the viscosity of the spent acid is found to be the key parameter for diversion efficiency. We have constructed a mechanistic model similar to that in Panga et al. (2005) that simulates the acid injection in two dimensions. Then, we extended our simulation to dual-core systems with different permeability contrasts. The results show that there exists an intermediate injection rate that develops a wormhole in low-permeability core. This intermediate injection rate increases with increasing the permeability contrast. The results suggest that the dissolution pattern in the high-permeability core is dependent on the permeability contrast. It changes from wormhole to uniform shape when the permeability contrast increases.

Water shielding phenomenon generally occurs after waterflooding in water-wet rocks, and impedes direct contact between the oil and the injected gas in tertiary gas injection processes. In this work, a set of visualization experiments were performed on micromodel patterns including designed dead-end pores with a film of water on the surface of pore bodies, which is a more realistic representation of porous media. The experiments were conducted at different miscibility conditions, and the required time for water to be displaced from the throat by the swelling of oil was measured for first contact miscible (n-C 5 /CO 2 ) and immiscible (n-C 10 /CO 2 ) systems. In the next step, a model was proposed to simulate the results of the experiments, based on the work of Bijeljic et al. (2003). As the impact of non-ideal mixing in this process has not been previously discussed in the available literature, the new model was developed by taking into account the changes in the partial molar volumes of oil and gas components using the PR and the SRK equations of state, and also by considering the mass transfer from the surrounding water on the pore body into the shielded oil. The rupture times predicted by the model were compared with the measured experimental data, as well as those reported by Campbell and Orr (1985). It was found that inclusion of partial molar volumes of components improves the accuracy of the model. The results also revealed the significant role of the water film on the pore body surfaces in mass transfer rate between the phases in water-wet media. The close agreement between the results of the model proposed in this study and the experimental data shows that it can be helpful for developing more accurate multiphase compositional models.

In this study, a new tool for better estimation of CO 2 dissolution in aquifers is proposed. It will be shown that this model could increase the accuracy of the prediction considerably by involving all the effective parameters and their interaction through the design of experiments approach (response surface based on Box-Behnken method). It is also shown that the difference among previous proposed dimensionless models may be the result of the difference in the amount of dissolved CO 2 for a fixed value of the Rayleigh number. In other words, for different values of the Rayleigh number (the result of changes in different parameters), the same amount of CO 2 dissolution observed, but this would not be apparent in these models. Another contribution of this work is summarizing the parameters involved by using appropriate thermodynamic correlations (pressure, temperature, salinity, porosity and permeability are all required factors). In addition, the dependency of fluid parameters on each other is considered during the study, through the thermodynamic correlations, and the effects of different parameters are studied simultaneously. The results indicate that salinity is the most important parameter in all the periods, while permeability is the most controlling parameter, after salinity, in the overall behaviour of the system. For all the periods, porosity and salinity have negative effects, while temperature and permeability have a positive influence. Although pressure has small negative impact on the diffusion coefficient and amount of dissolved CO 2 in the early period, it affects thermodynamic correlations (especially density difference between brine and brine + CO 2 solution), and its impact changes from negative to positive through the life-time of the sequestration. Since, simulations are performed at discrete points of a continuous range of parameters in the development of the proxy models, Monte Carlo simulation was used to explore the whole range for the final conclusion. The closely similar behaviour of the Monte Carlo result curve and discrete points result, shows that the proxy models can be freely used in the selected ranges.

One of the most effective and safe mechanisms for CO 2 storage in saline aquifers is solubility trapping by which CO 2 will be dissolved into the brine. Since the brine contained CO 2 is denser than the surrounding fluids, it would sink to the bottom of the rock formation over time, trapping CO 2 more securely. However, the rate of CO 2 dissolution into the brine depends on active mass transfer mechanisms, such as convection and diffusion mechanisms, under storage conditions. Convective mixing significantly enhances the rate of CO 2 dissolution into the brine. In this paper, we are aiming to comprehensively study the effects of formation brine salinity and reservoir temperature on convection mechanism and on CO 2 storage in saline aquifers. For this objective, a series of high-pressure high-temperature experiments were performed in a specially designed PVT bead pack cell. Based on the pressure data, the effects of aforementioned parameters on CO 2 dissolution, diffusion coefficient, Rayleigh number and the onset time of convection were studied. To further investigate the effects of above parameters on convection mechanism and to quantify the effectiveness of convection mechanism on CO 2 dissolution, Sherwood number and the time (t Shmax ), when it reaches its maximum value, were obtained in each experiment. Finally, a commercial software was used to model the convection mechanism and to study the effects of above parameters on density-driven fingers and convection mechanism. The results of both experimental and numerical studies revealed that decrease in brine salinity and temperature lead to increase in the Rayleigh number and Sherwood number. Furthermore, at low brine salinity and temperature, density-driven fingers grow faster at earlier times; therefore, convection mechanism is stronger, and it reaches its maximum value at earlier stages which is favourable for a storage project. The results of this study will help us in selecting the most suitable saline aquifer for safe CO 2 storage.

The effects of petrophysical matrix properties such as porosity and permeability on bypassed oil recovery were investigated during CO2 injection in fractures at different miscibility regimes (first-contact miscibility, near-miscibility, and immiscibility). A special experimental setup was designed for this purpose and a series of CO2 injection experiments were performed using two different types of porous media, sandstones and carbonates. To confirm the analysis, some tests were repeated in the presence of irreducible water saturation. In addition, dimensional analysis was used to capture the dominant forces and mechanisms. The results demonstrated that the highest oil recovery was achieved within near-miscible regime for the both rock types. Furthermore, in all miscibility regimes, the oil recovery factor decreased with the increase of the rock complexity and frequency of dead-end pores, whereas it declined as the permeability decreased. However, differences in recovery factors of near-critical and super-critical tests grew. Considering the analytical calculations and the results of experiments including initial water saturation, it can be concluded that near-critical point wetting and the number of dead-end pores have significant effects on variations of the oil recovery factor. With near-critical point wetting, maximum recovery was achieved at near-critical state, and the presence of dead-end pores caused the role of this mechanism to be more noticeable. As a result, differences in the recovery factor of near-critical and super-critical tests grew.

Injection of CO2 into saline aquifers causes the geochemical reaction of rock-fluid and salt precipitation due to the evaporation of water as a physical process. Well injectivity is an important issue in carbon capture and storage (CCS) projects because large volumes of CO2 must be stored for a long time and salt precipitation can significantly reduce injectivity by reducing the permeability. The impact of salt precipitation on the injectivity must therefore be specified in order to maintain the security of CCS projects and enable them to perform at a high level of practicality. The objective of this work is to investigate the influence of the injection rate and brine salinity on injectivity reduction due to evaporation and salt precipitation. In this study, we injected supercritical CO2 into a sandstone rock sample fully saturated with NaCl brine to characterize the salt precipitation induced by the evaporation process. Evaporation is investigated by mass measurement of the water and vapor produced. The extension in time of salt precipitation and the precipitation profile are analyzed by drying rate measurement, Capillary number and Peclet number. The consequences of salt precipitation on injectivity are specified by permeability and relative permeability analysis. The results show that a high drying rate in the early stage of injection induces rapid salt precipitation. The level of salt precipitation increases with salinity, within a permeability reduction range of 21–66%, and decreases with the injection rate, within a permeability reduction range of 43–62%. The relative permeability of CO2 is affected by both the injection rate and salinity.