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Surfactants play an important role in the widely used enhanced heavy oil recovery methods such as surfactant-polymer flooding and alkali-surfactant flooding. In this study, we focus on the effects of surfactant during surfactant flooding and provide a pore scale simulator of surfactant flooding based on the Lattice Boltzmann (LB) method. We introduce a dipole to present the amphiphilic structure of surfactants in the Lattice Boltzmann model, and characterizes microscopic fluid interactions at the kinetic level. There are three velocity distribution functions to present the oil, water, and surfactant species, and every distribution follows the discrete Boltzmann-BGK equation. There is also an additional dipole vector representing the orientation of amphiphile, so that the interactions related with surfactants depend not only on particle relative distances but also on their dipolar orientations. The simulation results show that surfactants can reduce the oil-water interfacial tension and recover more oil trapped by capillary force. Moreover, surfactants are able to emulsify the flooding system, forming O/W emulsions or bi-continuous micro-emulsions. Higher surfactant concentration leads to smaller oil droplets in emulsions. In addition, the phase distribution morphologies in porous media are much different in different wetting conditions. By associating the fluid-solid interfacial tension with the surfactants adsorption concentration on walls, we characterize the wettability alteration mechanism in LB model accurately. The oil recovery can be improved by changing the wettability from oil-wet to water wet, increasing the surfactant concentration, and enhancing the adhesion parameters. However, the adsorption onto walls leads to unnecessary waste and could decrease the surfactant concentration in bulk phase. The study provides an effective pore scale tool to simulate the surfactant involved interfacial flows in porous media. In addition, we can use it to study the flow mechanisms and remaining oil distributions during surfactant flooding.

Preformed Particle Gels are successfully used for profile control in heterogeneous reservoirs. However, it is still unclear how to select proper PPG size for a given heterogeneous reservoir. In order to obtain the best profile control performance, it is necessary to study the matching relationship between the PPG mesh and the permeability ratio. In this paper, the heterogeneous parallel-dual-sandpack experimental setup is established, including the injection system, measurement systems for temperature and pressure. During the experimental processes of water injection, PPG injection and subsequent water injection, the fractional flow of the two sandpacks with high and low permeability are recorded respectively. Then, a quantitative characterization parameter of the profile improvement ability is defined by dividing the change of fractional flow of the low permeable sandpack before and after PPG injection by that of low permeable sandpack before PPG injection. The experimental results show that different PPG meshes will achieve different profile control performance for the heterogeneous sandpack with the determined permeability ratio. The PPG with excessive large size may block the low permeable area, decrease its fractional flow and thus cause more severe flow heterogeneity. The PPG with excessive small size can not well block the high permeability area and they can migrate out during subsequent water injection resulting in the increase of fractional flow in high permeable area again. The matching relationship analysis show that the matched PPG mesh increases as the permeability ratio of the heterogeneous sandpack increases. In detail, the matched PPG sizes for the permeability ratio of 2, 4, and 6 are 120-150 mesh, 100-120 mesh and 60-80 mesh, respectively. The paper studied the matching relationship between PPG size and permeability heterogeneity, which was beneficial for selecting the proper PPG size for different heterogeneous reservoirs in more future applications.

The preformed particle gel (PPG) has been proved to be an effective chemical agent to reduce fluid channeling and increase the sweeping efficiency. However, we still lack a clear understanding of the field-scale matching relationship between PPG size, elastic modulus and a heterogeneous reservoir. In this respect, the paper carried out various sand pack displacement experiments. The results indicated that an excessively large PPG or elastic modulus would plug a low-permeability sand pack and even increase the severity of fluid channeling. On the contrary, an excessively small PPG or elastic modulus allowed a certain degree of profile control, but the PPG could easily migrate out of high-permeability sand packs with water. If the elastic modulus remained unchanged, the suitable PPG size increased as the reservoir permeability ratio increased. On the other hand, the suitable elastic modulus increased with the increase of the reservoir permeability ratio when the PPG size was kept the same. By using regression analysis, quantitative expressions were established in order to determine the best suitable PPG size for a certain heterogeneous reservoir. When the elastic modulus was fixed, the best suitable PPG mesh exhibited a linear relation with the permeability ratio. This paper provides a useful reference to select the most convenient PPG size and elastic modulus for a potential heterogeneous reservoir, suitable to enhance oil recovery.

Polymers and viscoelastic particles are the main chemical agents used to improve water injection profile and thus increase oil production. In actual formations, however, there is a lack of knowledge on selecting an appropriate chemical agent to achieve excellent conformance control and oil production performance. To address this issue, this paper first investigated the main rheological properties and resistance increase performance of the two chemical agents. After that, the permeability contrast limits for applying polymer solution and viscoelastic particle suspension in heterogeneous reservoirs were determined through shunt flow experiments. The critical impact of permeability contrast limits on chemical enhanced oil recovery (EOR) was further verified via a two-dimensional (2D) visualized oil displacement experiment. It was found that the particles exhibit superior elasticity, while the polymers mainly exhibit a viscosity increase effect. The resistance increase capacity of the particle suspension in the core was more potent than that of the polymer solution, which results in its excellent conformance control in strongly heterogeneous cores. On the contrary, the polymer solution might face the risk of failure. The permeability contrast limits for applying the two chemical agents at different concentrations were determined. Visualized oil displacement experiments showed that the EOR by polymer flooding in strongly heterogeneous reservoirs is quite low (3.3%). In contrast, the particle suspension could effectively expand the swept zone and extract considerable remaining oil in the low-permeability zones. Accordingly, the EOR could reach 7.1%. Determining permeability contrast limits is of practical significance for selecting suitable chemical agents to realize successful conformance control and oil extraction in heterogeneous reservoirs.

Suitable elastic modulus and particle size of preformed particle gel are the keys to both diverting water flow and avoiding permanent impairment to reservoirs. Therefore, the paper aims at finding the best matched preformed particle gel for given reservoirs using sand-pack displacement experiments. The results show that the injection pressure of preformed particle gel with excessively small size and elastic modulus is relatively low, indicating poor capacity to increase flow resistance and reduce water channeling. On the other hand, if the particle size and elastic modulus of preformed particle gel are excessively large, the reservoir may be plugged and irreversibly damaged, affecting oil development performance. In fact, the best matched particle size and elastic modulus of preformed particle gel increase with the increase in reservoir permeability. Furthermore, the paper establishes a quantitative logarithmic model between the particle size of preformed particle gel and reservoir permeability. Finally, the established matching relationship is validated via microscopic visualization oil displacement experiments using a glass etching model. The validation experiments indicate that the preformed particle gel (60–80 mesh; 2–4 Pa) selected according to the matching relationship can effectively reduce water channeling and increase sweeping efficiency by as much as 55% compared with water flooding in the glass etching model with an average permeability of 2624 × 10−3 μm2. Therefore, the established matching relationship can provide an effective guide when selecting the best suitable preformed particle gel for a given reservoir in more future applications.

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