Two major applications of injecting dense carbon dioxide (CO2) into the petroleum reservoirs are enhanced oil recovery and sequester CO2 underground. For enhanced oil recovery applications, CO2 has low miscibility pressure causing the swelling of crude oil and reducing its viscosity therefore improving the macroscopic sweep process. However, the low viscosity of injected CO2 compared with the reservoir fluids causes the fingering of CO2, which may lead to bypassing huge amount of oil, early breakthrough of CO2, and increasing the gas to oil ratio (GOR). The use of direct thickeners, such as polymers, is one of the techniques used to increase the CO2 viscosity. Nevertheless, the solubility of polymers in CO2 and the high cost of soluble polymers are the main challenges facing this technique. In this study, a novel, soluble, and cost-effective thickener is proposed to directly increase the CO2 viscosity. In this study, a PVT high pressure and high temperature (HPHT) apparatus was used to evaluate the compatibility and the solubility of the thickener in dense CO2. Also, a custom designed apparatus was used to measure the viscosity of dense CO2 in the presence of the thickener at different conditions. The assessment was conducted at different experimental pressures, temperatures, and thickener concentrations. The effect of pressure on the solubility of the thickener in CO2 and on the measured viscosity of CO2 was evaluated at 1500, 2000, 2500, and 3000 psi. Also, the influence of temperature was evaluated at 25 and 50°C. Moreover, the concentrations used to study the effect of thickener concentration on the measured viscosity of CO2 ranged between 0.10-2 %. The results from laboratory experiments clearly demonstrated that the addition of the thickener at certain conditions can significantly impact the dense CO2 viscosity. The results revealed that there must be a minimum pressure at which the thickener dissolves in the dense CO2. The solubility of the thickener can occur when the CO2 is either in the liquid or supercritical phase. The results also pointed out that the CO2 viscosity increased as the pressure increased. The increase of CO2 pressure can significantly impact the solubility of the thickener in the dense CO2 and consequently the CO2 viscosity. The increase of the thickener concentration also had a significant impact on the measured CO2 viscosity. The results showed that the CO2 viscosity increased with the thickener concentration. The CO2 viscosity increased 100 to 1200 -fold as a result of adding the thickener depending on the experimental conditions
Generating in-situ foam is regarded as one of the most promising techniques to overcome gas mobility challenges and, accordingly, improve sweep and sequestration efficiency in CO2 injection processes. Foam generation and stabilization at harsh reservoir conditions as well as surfactant-rock interactions are the major limiting factors that can impair the efficiency of foam flood. Surfactants mixtures offer the solutions necessary for the generation and stabilization of foams at harsh reservoir conditions. In this study, mixtures of anionic and amphoteric surfactants have been evaluated in comparison to using each surfactant individually to determine the overall effect on producing stable foams. Using bottle foam tests, dynamic foam analyzer, and foam rheology apparatus, the foam stabilization factors were analyzed and quantified. The bulk foams for each surfactant and the mixture of the two surfactants at different mixing ratio were analyzed by measuring the foam-life over time, the foam bubble sizes, and the foam rheological properties at high pressure, high temperature (HPHT) and using high salinity water. The experimental results clearly demonstrated that the use of surfactant mixtures improved the stability of produced foam. The results revealed that the mixing ratio of each surfactant significantly impacts the foam stabilization. The surfactant mixture solutions produced more stable foams as evidenced by a longer foam-life. The foam-life increased by almost 1.5-2 times depending on the mixing ratio. The results also revealed that there are ranges of concentrations at which the most stable foams can be produced. The foam rheology results showed that the produced foams using the surfactant mixtures are of higher apparent viscosity when compared to those obtained with the anionic surfactant. The addition of the amphoteric surfactant to the anionic surfactant solution enhanced the foam stability, and accordingly, the foam rheological properties. The measured foam apparent viscosity increased as the concentration of the amphoteric surfactant increased. Longer foam-life and greater apparent viscosity are indicative of better, stronger and more stable foams.
Mechanistic modeling of the non-Newtonian CO2-foam flow in porous media is a challenging task that is computationally expensive due to abrupt gas mobility changes. The objective of this paper is to present a local equilibrium (LE) CO2-foam mechanistic model, which could alleviate some of the computational cost, and its implementation in the Matlab Reservoir Simulation Tool (MRST). Interweaving the LE-foam model into MRST enables users quick prototyping and testing of new ideas and/or mechanistic expressions. We use MRST, the open source tool available from SINTEF, to implement our LE-foam model. The model utilizes MRST automatic differentiation capability to compute the fluxes as well as the saturations of the aqueous and the gaseous phases at each Newton iteration. These computed variables and fluxes are then fed into the LE-foam model that estimates the bubble density (number of bubbles per unit volume of gas) in each grid block. Finally, the estimated bubble density at each grid block is used to readjust the gaseous phase mobility until convergence is achieved. Unlike the full-physics model, the LE-foam model does not add a population balance equation for the flowing bubbles. The developed LE-foam model, therefore, does not add much computational cost to solving a black oil system of equations as it uses the information from each Newton iteration to adjust the gas mobility. Our model is able to match experimental transient foam flooding results from the literature. The chosen flowing foam fraction (Xf) formula dictates to a large extent the behavior of the solution. An appropriate formula for Xf needs to be chosen such that our simulations are more predictive. The work described in this paper could help in prototyping various ideas about generation and coalescence of bubbles as well as any other correlations used in any population balance model. The chosen model can then be used to predict foam flow and estimate economic value of any foam pilot project.
The in-situ generation of foam is one of the most promising techniques to solve gas mobility challenges in petroleum reservoirs and subsequently improve the volumetric sweep efficiency. The stabilization of foam at reservoir conditions is a major challenge. The harsh reservoir conditions, such as high temperature, high brine salinity, together with surfactant adsorption on the rock may result in unstable foam and, consequently, poor sweep efficiency. Foam additives, such as polymers, might help strengthen the physical properties of foam film and improve foam stability. This work evaluates the effectiveness of a polymer on enhancing CO2-foam stabilization at harsh reservoir conditions. Static and dynamic foam tests were conducted to evaluate the role of polymer on foam stability. Three foaming surfactants were used to assess the ability of the polymer on enhancing foam stabilization. The static foam tests were conducted at conditions similar to reservoir conditions using test tubes. Foam column, and foam life were measured to evaluate the role of the polymer on foam stabilization. Foam viscosity in absence and presence of the polymer was measured using foam rheometer apparatus. The dynamic foam tests were conducted to assess the ability of tested materials to generate viscous foams and also measure the CO2 mobility in porous media using a coreflooding system. The mobility reduction factor (MRF) was measured at high pressure and high temperature (HPHT) conditions, 3200 psi and 100°C. The static foam tests and foam rheology measurements indicated that the addition of the polymer enhanced foam stability as a result of increasing the bulk viscosity of the aqueous solutions. The results found that the foam life increased with the polymer concentration. However, the increase of polymer concentration makes the solution very viscous, hence, the foam generation becomes challenging. The dynamic foam tests showed that the foam generated in absence of the polymer was able to reduce the CO2 mobility 13 fold. However, the addition of the polymer resulted in higher pressure drops during CO2 floods, more resistance to gas flow and, therefore, lower gas mobility compared to that obtained with surfactant alone. The addition of the polymer reduced the CO2 mobility 50 fold. This higher reduction in the CO2 mobility as a result of adding the polymer can be attributed to the effectiveness of the polymer in improving the foam stabilization and prolong the life of generated foam.
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