Vapor Extraction Process Research Articles

Optimizing CO2 sequestration in Vapor Extraction Process: A Meso-Scale analysis of oil Viscosity, Permeability, and mobile oil orientation effects

Carbon dioxide (CO2) use in Vapor Extraction (VAPEX) has attracted attention for its potential to enhance oil recovery by altering oil density and viscosity, leading to convective-mixing flow in the VAPEX boundary layer. This study explores CO2 sequestration via dissolution into this layer, with a focus on the impact of oil viscosity, permeability, and mobile oil orientation. An isothermal lattice Boltzmann model, which accounts for the variable oil properties like viscosity and diffusion coefficient dependent on dissolved CO2 concentration, was developed for the analysis. Results show that reduced oil viscosity leads to accelerated growth of density fingers and an expanded area swept by CO2 dissolution. Similarly, heightened permeability and mobile oil angle contribute to these effects. This research provides novel insights into optimizing CO2 sequestration within the VAPEX process.

Pore-Scale Modelling of Solvent-Based Recovery Processes

A need for a reduction in energy intensity and greenhouse gas emissions of bitumen and heavy oil recovery processes has led to the invention of several methods where mass-transfer-based recovery processes in terms of cold or heated solvent injection are used to reduce bitumen viscosity rather than steam injection. Despite the extensive numerical and experimental investigations, the field results are not always aligned to what is predicted unless several history matches are done. These discrepancies can be explained by investigating the mechanisms involved in mass transfer and corresponding viscosity reduction at the pore level. A two-phase multicomponent pore-scale simulator is developed to be used for realistic porous media simulation. The simulator developed predicts the chamber front velocity and chamber propagation in agreement with 2D experimental data in the literature. The simulator is specifically used for vapor extraction (VAPEX) modelling in a 2D porous medium. It was found that the solvent cannot reach its equilibrium value everywhere in the oleic phase confirming the non-equilibrium phase behavior in VAPEX. The equilibrium assumption is found to be invalid for VAPEX processes even at a small scale. The model developed can be used for further investigation of mass transfer-based processes in porous media.

Experimental and Numerical Study of Strategies for Improvement of Cyclic Solvent Injection in Thin Heavy-Oil Reservoirs

SummaryTo overcome the problems of slow mixing in the vapor-extraction (VAPEX) process and regaining high oil viscosity in the cyclic solvent process (CSP), we introduce a new process for thin heavy-oil reservoirs known as the enhanced cyclic solvent process (ECSP). In ECSP, two types of hydrocarbon solvents are cyclically injected in two separate slugs: one slug is more volatile (methane) and the other is more soluble (propane or ethane) in heavy oil. In this study, experiments of primary depletion, CSP, cyclic gas-alternating-water (GAW) or inverse water-alternating-gas (WAG) injection, ECSP, and surfactant-enhanced CSP at relatively low-to-intermediate pressures in a visual rectangular sandpack (with a thickness/length ratio of 1:32) filled with crude oil, gas, and brine (replicating the actual field conditions pertaining to a thin reservoir after the primary depletion) are presented. The effect of operational pressure, initial production pressure, more soluble solvent type (propane/ethane), propane-slug size, and initial oil saturation on the ECSP performance are evaluated. Moreover, the effects of well location, initial production pressure, production end pressure, system repressurization using water injection, and adding an oil-soluble surfactant before methane injection on the CSP are investigated. The performance of CSP is compared with that of ECSP, cyclic inverse WAG, surfactant-enhanced CSP, and extended waterflood (EWF). The experimental results indicate that the performance of cyclic solvent injection decreases in this order: ECSP using methane/propane, surfactant-enhanced CSP, cyclic inverse WAG using water/methane, ECSP using methane/ethane, and CSP using methane. ECSP using methane/propane outperforms surfactant-enhanced CSP and cyclic inverse WAG only if a relatively larger propane-slug size (20 to 35%) is injected. The cyclic inverse WAG (using an offset to the CSP well to repressurize the sandpack by water before conducting methane CSP) significantly improves the recovery and its rate, and it reduces the gas requirement. Also, injecting an oil-soluble foaming surfactant before methane enhances the CSP recovery factor (RF) and rate by one order of magnitude, making them comparable with those of ECSP using methane and a large slug of propane. In discussing these results, the significance of and the interplay between various recovery mechanisms in CSP, ECSP, and surfactant-enhanced CSP is highlighted in the order in which they occur during the injection cycle (viscous fingering, phase change and dissolution of solvent, diffusion and convective dispersion, and capillary mixing), soaking (solvent diffusion and mixing, oil swelling, and viscosity reduction), and the production cycle (foamy-oil flow, solution gas drive, and wellbore inflow). The results of this mechanistic analysis of CSP, ECSP, and surfactant-enhanced CSP during the injection, soaking, and production cycles render an improved paradigm for a holistic performance evaluation and understanding of cyclic solvent-injection processes. The interplay between various observed recovery mechanisms reveals various advantages of ECSP, surfactant-enhanced CSP, and cyclic inverse WAG over traditional CSP.

A review of in situ upgrading technology for heavy crude oil

With the growing demand of oil worldwide, heavy oil has increasingly become vital in the world energy market. However, further development of heavy oil reservoirs are limited by regular enhanced oil recovery (EOR) methods. In situ upgrading technology provides potential for the development of heavy oil and bitumen reservoirs. This study reviews three categories of in situ upgrading methods: solvent-based, in situ combustion (ISC), and catalytic. Solvent-based methods, including cyclic solvent injection, vapor extraction, and hybrid processes, have recently received attention and have been progressed in both laboratory and field applications. However, high solvent costs in relation to the low price of heavy oil have continued to limit the field applications of these techniques. ISC, which may have the potential to develop particularly harsh reservoirs with extremely viscous crude oil, involves complex reaction mechanisms and consists of three main steps: oxidation, combustion, and gas flooding. Yet, complex operating conditions and a low success rate have restricted its application. Catalytic methods, which have demonstrated the potential to refine and upgrade crude oil in a more economic and environmentally friendly way, are often accompanied by conventional thermal EOR methods, such as steam flooding and ISC, and involve a series of hydroprocessing or hydrotreating reactions, such as hydrocracking, hydrodesulfurization, hydrodenitrogenation, hydrodeoxygenation, and hydrodemetallization. However, the high cost and complexity of the reaction mechanisms have limited their applications.

A shortcut model to estimate oil production rate in VAPEX process

An analytical model for estimating the oil production rate in the vapor extraction process (VAPEX) is presented in this work. It regards the most effective properties of fluid and reservoir in the form of the Rayleigh number. The model involves three coefficients (x1, x2 and x3) that are determined through minimizing an objective function based on the difference between experimental VAPEX data and calculated data. The strength of the model was examined through comparison experimental work. Having an average relative error of 15% against the real data, the model showed its high capability for predicting the VAPEX production rate.

Revisiting the Butler-Mokrys Model for the Vapor-Extraction Process

Summary The dynamics of a process in which a solvent in the form of a vapor or gas is introduced in a heavy-oil reservoir is considered. The process is called the solvent vapor-extraction process (VAPEX). When the vapor dissolves in the oil, it reduces its viscosity, allowing oil to flow under gravity and be collected at the bottom producer well. The conservation-of-species equation is analyzed to obtain a more-appropriate equation that differentiates between the velocity within the oil and the velocity at the interface, which can be solved to obtain a concentration profile of the solvent in oil. We diverge from an earlier model in which the concentration profile is assumed. However, the final result provides the rate at which oil is collected, which agrees with the previous model in that it is proportional to h, where h is the pay-zone height; in contrast, some of the later data show a dependence on h. Improved velocity profiles can capture this dependence. A dramatic increase in output is seen if the oil viscosity decreases in the presence of the solvent, although the penetration of the solvent into the oil is reduced because under such conditions the diffusivity decreases with decreased solvent. One other important feature we observe is that when the viscosity-reducing effect is very large, the recovered fluid is mainly solvent. Apparently, some optimum might exist in the solubility φo, where the ratio of oil recovered to solvent lost is the largest. Finally, the present approach also allows us to show how the oil/vapor interface evolves with time.

Performance and Economic Analysis of SAGD and VAPEX Recovery Processes

Heavy oil has attracted global attention because of its significant volume of original oil in place. However, there are several economic and operational challenges associated with heavy oil recovery due to its high viscosity and high density. Recently, steam-assisted gravity drainage (SAGD) and solvent vapor extraction (VAPEX) recovery processes have been introduced to enhance heavy oil recovery. Although SAGD recovery process achieves high oil recovery, many drawbacks are related to this process, such as produced water treatment and huge amount of water and energy required to generate steam which leads to significant CO $$_{2 }$$ emissions. On the other hand, VAPEX recovery process has many challenges such as low production rates and potential sensitivity to reservoir heterogeneity. The drawbacks of SAGD could minimize its economic profitability compared to VAPEX process. Therefore, the objective of this work is to model and evaluate the two recovery methods from the economic point of view and based on the achieved net present value (NPV). Several sensitivity studies are applied on SAGD and VAPEX to analyze the effect of different operation parameters and different reservoir conditions. The effects of aquifer and initial oil viscosity on the recovery performance of SAGD and VAPEX are analyzed. In all the cases considered, VAPEX achieved higher NPV than SAGD by at least 70%, although SAGD has higher oil recovery factor. This research shows and confirms that VAPEX is more economic profitable recovery method and it is a step forward to eliminate CO $$_{2}$$ emissions associated with thermal recovery process.

Acoustic investigation of CO2 mass transfer into oil phase for vapor extraction process under reservoir conditions

Generally, researchers to study mass transfer of gas phase into liquid use pressure decay method, visual cell or pendant drop technique. Despite available data about CO2 solubility in oil, there are limited methods which allow to study interactions between fluids. In this paper, a newly developed acoustic pulse-echo (APE) technique was applied to measure oil volume expansion factors in the presence of carbon dioxide in a pressure range of 2–6 MPa at a temperature of 297 K to cover most practical cases of interest for the vapor extraction process. With the APE technique, a wave is emitted from a piezoelectric transducer, and its reflection from the boundary is detected at a later time. As CO2 becomes soluble in the oil, the boundary between the fluids moves upward, thus affecting the travel time of the reflected wave from the fluid interface. Since volume changes are registered, the expansion factor can be evaluated. The experimental results show that the oil swelling factor increases with pressure; this clearly indicates that there are certain correlations between the oil swelling factor and the solubility of an oil-solvent system. The evidence for the validity of the acoustic technique was provided by comparing measured values with literature data. Compared to other investigatory approaches, the main advantage of this newly developed method is its ability to provide highly accurate swelling factor values for CO2/oil system. The method developed in this study can be serviceable for further and more complex investigations on gas-EOR experiments.

A new soft computing‐based approach to predict oil production rate for vapour extraction (VAPEX) process in heavy oil reservoirs

AbstractThere are vast resources of heavy oil and bitumen reservoirs in the Western Canadian Basin. For many of them up to 95 % of reserves still remain in place, and by considering the increase in future energy demand these abundant resources can be considered as potential sources for future years. Recently, solvent‐based heavy oil recovery methods such as vapour extraction (VAPEX) have gained attention due to the potential environmental and economic assets over thermal processes. Due to the complexity of the mechanisms associated with the solvent injection process (i.e. diffusion and gravity drainage processes), such models are incapable of accurately predicting the production rate during the VAPEX process. In this study, the artificial neural networks (ANN) technique is utilized to tackle the limitations that analytical methods encounter while predicting the complex relationships, where there is uncertainty, imprecision, and partial truth. Hence, in the first phase of the research a comprehensive experimental study in two large‐scale, visual rectangular VAPEX models was carried out by utilizing various injection solvents. Based on an extensive literature review and experimental results, the drainage height, solvent type, permeability, porosity, and heavy oil viscosity were considered as the inputs of the model to predict the heavy oil production rate as the output of the model. After trying different training scenarios, it was found that the back‐propagation learning algorithm can be successfully used to predict the ultimate recovery factor after implementing the VAPEX method in the heavy oil system of interest.

Feasibility study on application of the recent enhanced heavy oil recovery methods (VAPEX, SAGD, CAGD and THAI) in an Iranian heavy oil reservoir

ABSTRACTEnhanced oil recovery (EOR) methods assisted by gravity drainage mechanism and application of sophisticated horizontal wells bring new hope for heavy oil extraction. Variety of thermal and non-thermal EOR techniques inject an external source of energy and materials such as steam, solvent vapor, or gas through a horizontal well at the top of the reservoir to reduce in-situ heavy oil viscosity. So, the diluted oil becomes mobile and flows downwards by gravity drainage to a horizontal producer located at the bottom of the reservoir.In this paper, a sector model of an Iranian fractured carbonate heavy oil reservoir was provided to simulate and evaluate capability of some EOR techniques such as Vapor Extraction (VAPEX), Steam Assisted Gravity Drainage (SAGD), Combustion Assisted Gravity Drainage (CAGD), and Toe to Heel Air Injection (THAI) at its reservoir conditions and fluid properties. The simulation results demonstrated that wet CAGD in comparison with other nominated methods could improve heavy oil recovery factor to around 19% much more than each of SAGD, THAI, and VAPEX techniques. It could also reduce the total energy to produced oil ratio index up to 82% with respect to SAGD process in a year.Although lower oil recovery has been gained by VAPEX process, but using a proper vaporized solvent could produce a kind of de-asphalted and upgraded oil with increased API gravity up to 29°API with no considerable solvent loss.

Modelling mass transfer during venting/soil vapour extraction: Non-aqueous phase liquid/gas mass transfer coefficient estimation

We investigate how the simulation of the venting/soil vapour extraction (SVE) process is affected by the mass transfer coefficient, using a model comprising five partial differential equations describing gas flow and mass conservation of phases and including an expression accounting for soil saturation conditions. In doing so, we test five previously reported quations for estimating the non-aqueous phase liquid (NAPL)/gas initial mass transfer coefficient and evaluate an expression that uses a reference NAPL saturation. Four venting/SVE experiments utilizing a sand column are performed with dry and non-saturated sand at low and high flow rates, and the obtained experimental results are subsequently simulated, revealing that hydrodynamic dispersion cannot be neglected in the estimation of the mass transfer coefficient, particularly in the case of low velocities. Among the tested models, only the analytical solution of a convection-dispersion equation and the equation proposed herein are suitable for correctly modelling the experimental results, with the developed model representing the best choice for correctly simulating the experimental results and the tailing part of the extracted gas concentration curve.

Modelling of dynamic mass transfer in a vapour extraction heavy oil recovery process

ABSTRACTViscosity reduction through solvent dissolution into heavy oil is one of the most important recovery mechanisms of a vapour extraction (VAPEX) process. Existing analytical models can neither accurately describe the mass transfer between solvent vapour and heavy oil nor predict the solvent chamber evolution. Simulation models are confounded by numerical dispersion and have difficulty in accurately characterizing fluid properties in VAPEX. This study first develops a mass transfer model to describe a dynamic heavy oil‐solvent mixing process. This model is then incorporated into a VAPEX model to estimate solvent chamber development and an oil production rate. Diffusivity is determined through history matching theoretically calculated and experimentally measured cumulative oil production data. It is found that both constant and variable diffusivities can achieve an excellent match in cumulative oil production data. However, their respective characterization of the fluid properties in the VAPEX transition zone is very different. This study also proposes a method to convert constant diffusivity into its equivalent variable diffusivity for VAPEX by using some regressed correlations. Moreover, the back‐calculated effective diffusivity is found to be about 10–30 times of the corresponding molecular diffusivity measured in the laboratory.

Optimal parameters selection for SAGD and VAPEX processes

Steam Assisted Gravity Drainage (SAGD) and Solvent Vapor Extraction (VAPEX), both of the techniques have been proved to be successful for the exploitation of heavy oil reservoirs. Field development of heavy oil reservoirs requires careful determination of optimal parameters, well locations and control setting of producers and injectors. In recent years, field development decisions based on sensitivity studies have been shifting toward automated optimization. In this paper, we present the optimal parameter selection for SAGD and VAPEX. We performed the search of optimum parameters; the vertical separation between injector and producer, well controls and well locations. All these parameters have been simultaneously optimized to study and compare the performance of both processes. Also, we present an efficient method to constrain horizontal wells to preset minimum well spacing constraints. This method was then applied to constrain the well spacing between different peers of horizontal wells in the SAGD and VAPEX processes. The particle swarm optimization was used as an optimizer to determine the optimum parameters. The results indicated that the method could successfully determine the optimal parameters while satisfying the spacing constraint imposed by the user. The comparison of the results showed the better performance of SAGD over VAPEX process.

A parabolic solvent chamber model for simulating the solvent vapor extraction (VAPEX) heavy oil recovery process

During the solvent vapor extraction (VAPEX) process, a heavy oil reservoir can be divided into three different zones in terms of its fluid saturations, namely, the solvent chamber, transition zone, and untouched heavy oil zone. In the past, the solvent chamber was assumed to be a linear or circular shape in the previous studies. However, it has been observed to be close to a parabolic shape in many laboratory VAPEX tests. In this paper, a new parabolic solvent chamber model in the concave or convex case is formulated to predict the solvent chamber evolution and the heavy oil production in the VAPEX heavy oil recovery process. In the experiment, each recorded digital solvent chamber image at a different time is digitized to determine the solvent chamber shape by analyzing the sudden change of the gray level of each pixel. In theory, the overall discrepancy between the predicted and digitized solvent chambers is minimized by adjusting the transition-zone thickness. It is found that in comparison with the linear and circular solvent chamber models, the parabolic solvent chamber model gives the best prediction of the solvent chamber evolution, especially in the spreading phase. In addition, the maximum transition-zone thickness variation of 13.1% during the entire VAPEX test indicates that the transition-zone thickness can be assumed to be constant. Similar to the other solvent chamber models, the parabolic solvent chamber model can adequately predict the cumulative heavy oil production. The relatively large error of the predicted cumulative heavy oil production is caused by a commonly used assumption. The initial oil saturation in the transition zone is assumed to reduce to the residual oil saturation once the transition zone becomes an incremental part of the solvent chamber. This major theoretical assumption needs to be further investigated.

Mathematical modeling of the solvent chamber evolution in a vapor extraction heavy oil recovery process

In a vapor extraction (VAPEX) process, a vaporized solvent (such as light alkanes) is injected underground to dilute and recover heavy oil. A solvent chamber forms due to the depletion of oil, and goes through three phases: rising, spreading, and falling phases during a VAPEX process. Existing analytical models of VAPEX can only roughly estimate an oil production rate but are unable to accurately describe the solvent chamber evolution. Simulation models are somewhat unreliable due to extremely small physical diffusivity and relatively large numerical dispersion. This study develops a comprehensive mathematical model for the VAPEX process to characterize a transition zone and describe the solvent chamber evolution. Major recovery mechanisms occurring in the transition zone such as dynamic mass transfer, gravity drainage, multiphase flow, and surface renewal are accounted for in the model. Modeling results show that the solvent concentration in the transition zone grows slower at the top than at the bottom while rather stable at the middle along the drainage surface. In addition, it is found that a stabilized oil production rate depends on the square root of a heavy oil–solvent effective diffusion coefficient. Moreover, this new VAPEX model can accurately describe the relationship between oil production rates and diffusion coefficients in different scales thanks to the absence of numerical dispersion.

Application of CO2-based vapor extraction process for high pressure and temperature heavy oil reservoirs

A considerable portion of hydrocarbon resources in the world comprises heavy oils. Due to the high viscosity of these oils, production from these resources is difficult and requires especial enhanced oil recovery techniques. Carbon dioxide (CO2) based vapor extraction (VAPEX) process has recently been introduced as an effective method for recovery of heavy oils. However, this method has not yet been implemented in oil fields. Previous studies on CO2-based VAPEX were performed in small cells under low pressure (<9400kPa) and temperature (<60°C) conditions. In this study, the CO2-based VAPEX process was simulated for a real heavy oil reservoir to determine the application of CO2 as a non-condensable carrier gas, co-solvent, and solvent at high pressure (20,685kPa) and temperature (82.2°C) condition. Different solvent mixtures including propane (C3), butane (C4), methane (C1), and CO2 were utilized. It was found that in high pressure and temperature conditions, CO2 is not a good non-condensable carrier gas due to the miscibility of solvent mixtures (C3/C4+CO2) with the reservoir oil. In contrast, CO2 application for heavy oil recovery in such condition is similar to C3. The simulation results demonstrated that replacement of C3 with CO2 in the solvent mixtures has led to the recovery of the same amount of oil. This replacement has also caused a higher reduction in the heavy oil viscosity to obtain. Thus, CO2 can be considered as a good alternative for C3 in the VAPEX process specially for use in high pressure and temperature reservoirs. The outcomes from this research provide a new way for recovery of heavy oils by applying CO2 as a solvent in reservoirs that have high pressure and temperature.

Comprehensive experimental study and numerical simulation of vapour extraction (VAPEX) process in heavy oil systems

AbstractThere are significant heavy oil and bitumen resources in Canada. Global energy demand is rising while environmental constraints make heavy oil recovery more challenging. Therefore, looking for an economically viable and environmentally‐friendly heavy oil recovery technique is essential. Recently, solvent‐based heavy oil recovery techniques (i.e., VAPEX) have attracted attention due to their economic and environmental advantages over thermal methods. In this research, an extensive experimental and numerical simulation study on the VAPEX technique was carried out to provide more in‐depth information about key parameters which affect the ultimate performance of the VAPEX process. For this purpose, VAPEX experiments were conducted in two large‐scale physical models and various solvents were utilized. PVT experiments were also carried out, and CMG's STARSTM was used for numerical simulation studies and to history‐match the experimental results. Image analysis of the VAPEX chamber evolution showed that the highest sweep efficiency was observed after injecting propane, followed by butane, a propane/carbon dioxide mixture, a propane/methane mixture, carbon dioxide, and methane. The experiments were simulated numerically, and satisfactory history‐matching results were achieved. The major difference between the experimental and simulation results was observed after the first breakthrough of the solvent. In addition, the results showed that injection and production well configurations significantly affected the recovery performance of the process. A longer distance between the injection and production wells alongside the drainage height will increase the production rate in VAPEX.

Lattice Boltzmann investigation of thermal effect on convective mixing at the edge of solvent chamber in CO2-VAPEX process

The high viscosity of heavy oil is a serious problem for the recovery efficiency of this resource by conventional methods. Since a few past years, the vapour extraction process (VAPEX) has emerged as a promising technology for the recovery of heavy oils and bitumen in reservoirs where thermal methods, such as steam-assisted gravity drainage cannot be applied. Recently, the use of CO2 as a solvent is believed to make the VAPEX process more economical and environmentally and technically attractive. Convective mixing at the edge of the solvent chamber enhances mass and heat transfer rates which increases oil mobility and production rate. The objective of this study is to analysis the influence of the main controlling parameters, such as buoyancy ratio and Prandtl number on the flow patterns and mass transfer mechanism, in order to understand the thermal effect on the dissolution of carbon dioxide through natural convection at the boundary layer of solvent chamber of CO2-VAPEX process. The numerical results obtained by lattice Boltzmann method show that the flow structure and the mass transfer mechanism are strongly depend on the buoyancy ratio and Prandtl number. So, the performances of CO2-VAPEX process are strongly influenced by thermal effect; and we found that it has negative consequences on this process.

Extensive experimental investigation of the effect of drainage height and solvent type on the stabilized drainage rate in vapour extraction (VAPEX) process

Abstract The low cost of the injected solvent, which can be also recovered and recycled, and the applicability of VAPEX technique in thin reservoirs are among the main advantages of VAPEX process compared to thermal heavy oil recovery techniques. In this research, an extensive experimental investigation is carried out to first evaluate the technical feasibility of utilization of various solvents for VAPEX process. Then the effect of drainage height on the stabilized drainage rate in VAPEX process was studied by conducting series of experiments in two large-scale 2D VAPEX models of 24.5 cm and 47.5 cm heights. Both models were packed with low permeability Ottawa sand (#530) and saturated with a heavy oil sample from Saskatchewan heavy oil reservoirs with viscosity of 5650 mPa s. Propane, butane, methane, carbon dioxide, propane/carbon dioxide (70%/30%) and propane/methane (70%/30%) were considered as respective solvents for the experiments, and a total of twelve VAPEX tests were carried out. Moreover, separate experiments were carried out at the end of each VAPEX experiment to measure the asphaltene precipitation at various locations of the VAPEX models. It was found that injecting propane would result in the highest drainage rate and oil recovery factor. Further analysis of results showed stabilized drainage rate significantly increased in the larger physical model.

A Post–Cold Production Solvent Vapor Extraction (SVX) Process Performance Evaluation by Numerical Simulation

Solvent vapor extraction (SVX) process has been proposed as an approach to improve heavy oil production after cold production. The wormholes formed during cold production can be utilized as conduits available to produce diluted oil in SVX process. Through numerical simulation, the authors studied the effects of wormhole characteristics (length, permeability and water saturation, direction, and wormhole branch number) and fluid and formation uncertainties (dispersion coefficients, relative permeability curves, and reservoir heterogeneity) on the production performance of SVX process. The conclusions drawn can be used as guidance for designing post-cold SVX processes.