Foam Flooding Research Articles

Features of nanoparticle composite-enhanced CO2 foam-flooding systems for low-permeability reservoirs

This study examined an enhanced foam-flooding system incorporating nanoparticles and polymers under geological conditions of a reservoir of the Shu 16 block in the Yushulin oilfield. The system is mainly comprised of an anionic foaming agent (CQS-1) and a nonionic surfactant (FH-1). We screened 17 foams by evaluating their foaming volumes and foam half-lives using a Waring-blender and dynamic foam analysis methods, and nanoparticles were selected after examining each foam’s concentration, the ratio of the main agent to the auxiliary agent, and the dosage of the foam stabilizer. Then, we analyzed the selected system’s microstructure and rheological properties, including the adaptability of the reservoir to its temperature resistance, salt tolerance, and adsorption resistance. As a result, this study supports the field application of CO2 foam flooding.

Nanoparticle-Surfactant Stabilized Strong Foam for Enhanced Oil Recovery in High-Salinity Fractured Carbonate Reservoirs

Summary Foam flooding can minimize bypassing in gasfloods in fractured reservoirs. Finding a foam formulation effective in high-salinity brine is challenging, especially with divalent cations, e.g., American Petroleum Institute (API) brine (8% NaCl with 2% CaCl2). When formulating with nanoparticles, the colloidal dispersion stability is difficult due to the dramatic reduction in zeta potential and the Debye length at high salinity. The aim of this work was to develop a strong foam in API brine at the ambient temperature, using a nonionic surfactant and ethyl cellulose nanoparticles (ECNP), for gasflooding in fractured carbonate reservoirs. ECNPs was synthesized and dispersed in API brine using a nonionic surfactant (also denoted as SF). SF and SF/ECNP foams were generated, and their stability was studied at atmospheric pressure and 950 psi. Foam mobility was measured in a sandpack at high pressure. Foam flood experiments were conducted in oil-saturated fractured carbonate cores. The nonionic surfactant proved to be a good dispersion agent for ECNP in API brine. The SF/ECNP mixture stabilized foam in API brine, even in the presence of oil. Injecting a partially miscible gas (below its minimum miscibility pressure) as an SF foam into a fractured core more than doubles the oil recovery over injection of the gas alone. The injection of the strong foam (SF/ECNP) further improves the oil recovery over that of the SF foam, indicating the synergy between ECNP and surfactant. ECNP accumulates in the foam lamella and induces larger pressure gradients in the fracture to divert more gas into the matrix for oil displacement.

Numerical Investigation of the Most Affecting Parameters on Foam Flooding Performance in Carbonate Naturally Fractured Reservoirs

As one of the methods for reducing gas mobility and delaying gas breakthrough time, foam flooding has potentials to play a crucial role in the oil industry. Thus, being used in highly heterogeneous reservoirs, e.g., naturally fractured reservoirs, it can increase sweep efficiency. In this paper, a conceptual 3D model has been used for demonstration of influential factors on foam flooding in naturally fractured reservoirs. A series of numerical analysis on fracture and matrix permeability, fracture spacing, wettability, and foam parameters have been conducted. Furthermore, an investigation of certain phenomena, including diffusion and the block-to-block effect, has been conducted. Based on the simulations, increasing fracture permeability increased GOR in foam flooding, while increasing matrix permeability decreased it. Moreover, regardless of the intensity of the fracture in the models, the foam decreased the gas rate and increased the oil recovery. However, cases with higher fracture spacing ended up having higher GORs. Foam injection performed very well in both water-wet and oil-wet scenarios; however, it performed better in the oil-wet case. While consideration of diffusion increased GOR in model with very low matrix permeability, taking the block-to-block effect decreased GOR and increased oil recovery in all scenarios. Furthermore, the foam injection rate was one of the most critical variables that needed to be optimized. In conclusion, the foam flooding not only tended to decrease GOR drastically but also increased oil recovery significantly in naturally fractured reservoirs. However, different rock, fluid, and injection properties can significantly change the results.

MULTIPHASE TRANSPORT OF FOAM FLUID IN POROUS STRUCTURES FOR ENHANCING OIL RECOVERY

Foams in pores affect the sweep range and oil displacement efficiency for low-permeability reservoir. In this paper, regular porous media with different coordination numbers are constructed to study how the parameters of microscopic pore structure affect foam flooding, and to identify the relationship between foam flooding efficiency and pore size. A two-dimensional microscopic pore structure model is established by computed tomography (CT) and the Imagej software. The sweep range and oil displacement efficiency of foam flooding are compared with that of water flooding. The results show that porous media with low coordination numbers can lead to higher foam flooding efficiency. When the pore size of porous media with a coordination number of 3 is 1 μm, the oil displacement effect is the best. Compared with water, foam can significantly improve oil displacement efficiency. Foam can block the dominant channel and drive out the residual oil in the narrow pore throat with higher efficiency. When the gas-liquid ratio of the foam is 3:1, the residual oil saturation is the lowest, and the flooding effect is the best. The higher contact angle of the wetting wall can produce better efficiency of foam flooding. When the wetting angle is 45°, the oil displacement effect is the best. When the injection rate is 0.5 m/s, the oil displacement effect is the best, but when the injection rate reaches 5 m/s, the residual oil saturation is the smallest. When the coordination number is 4, the oil displacement effect is the best.

NUMERICAL SIMULATIONS OF NITROGEN FOAM AND GEL-ASSISTED STEAM FLOODING FOR OFFSHORE HEAVY OIL RESERVOIRS

Chemical-assisted steam flooding is a promising method for heavy oils. However, few researches have investigated the performance of nitrogen foam and gel-assisted steam flooding (NFG-A-SF) on offshore heavy oil reservoirs. In addition, the effects of operational parameters on the performance of NFG-A-SF are still unclear. In this study, a numerical simulation model was developed to simulate NFG-A-SF processes for offshore heavy oil reservoirs. Then, a comparison of NFG-A-SF and steam flooding was made to assess the feasibility of NFG-A-SF in a well group at Oilfield L, a typical offshore heavy reservoir of Bohai Bay, China. Finally, sensitivity analysis was conducted to investigate the effects of the chemical agent type, injection mode, injection timing, cycle number of gel and nitrogen foam, polymer concentration, crosslinking agent concentration, foaming agent concentration, and gas-liquid ratio on NFG-A-SF performance. The results showed that, compared with SF, the NFG-A-SF has better performance, which is a potential and effective method for offshore heavy oil reservoirs. The NFG-A-SF should be implemented as early as possible. During the NFG-A-SF processes, gel slugs should be injected alternately with nitrogen foam slugs, and the gel slugs should be injected first before nitrogen foam slugs. Considering the economic benefit, there are optimum cycle numbers of gel and nitrogen foam, gas-liquid ratio, concentrations of polymer, crosslinking agent, and foaming agent.

Pilot Test for Nitrogen Foam Flooding in Low Permeability Reservoir

Due to the characteristics of reservoir formation, the producing level of low permeability reservoir is relatively very low. It is hard to obtain high recovery through conventional development schemes. Considering the tight matrix, complex fracture system, low production level of producers, and low recovery factor of M block in Xinjiang oilfield, it is selected for on-site pilot test of nitrogen foam flooding. Detailed flooding scheme is made and the test results are evaluated respectively both for producers and injectors. The pressure index, filling degree, and fluid injection profile are found to be all improved in injectors after injection of nitrogen foam. The oil production, water cut and liquid production file are also improved in most of the producers, with the natural decline rate in the test area become slow. Results show that nitrogen foam flooding technology can be good technical storage for enhanced oil recovery in low permeability reservoir.

Investigation of Foam Flooding Assisted by Non-Newtonian and Novel Newtonian Viscosifying Agents for Enhanced Oil Recovery.

One of the main reasons for foam flooding enhanced oil recovery (EOR) is mobilizing oil left in the reservoir after primary recovery (depletion by pressure difference solely) and water flooding. However, expanding the infrastructure for certain foam EOR projects might be necessary as more wells are required, or a different well pattern is necessary. This study aims to study the effect of Newtonian and non-Newtonian viscosifying agents to assist foam flooding under the porous medium condition and to compare the results. Furthermore, this paper attempts to investigate the use of glycerol as a novel promising economic and ecological candidate instead of polymers. The shear rate inside the core was calculated based on the literature, which was combined with viscometric measurements in order to form four pairs of equal apparent viscosity. The differences and overlap within the core flooding experiments with foam generated by Newtonian and non-Newtonian fluids were observed by examining the mobility reduction factor under transient and steady-state conditions and by calculating the gas fraction present in the core. It was concluded that glycerol in core flood experiments could reach the same mobility reduction factor of about 1600 as polymer solutions with the same apparent viscosity, as long as the viscosity of the injected solution is reasonably low. Moreover, glycerol even reached the maximum mobility reduction factor faster than the foam generated by the polymer solution.

Rapid evaluation model for EOR techniques applicability of gas flooding, foam flooding and surfactant flooding based on modified fractional flow theory

Before a wide range of enhanced oil recovery (EOR) techniques were implemented for an oilfield, the EOR potential and economic evaluation of the techniques should be evaluated in advance for each reservoir to determine which EOR technique was proper. In an oilfield developed with fluvial delta reservoirs, the complicated distribution of scattered small reservoirs in vertical and horizontal directions brought trouble for evaluation work. A rapid and reliable evaluation model for EOR techniques applicability was necessary to deal with the evaluation simulation for many small reservoirs of an oilfield. Combining fraction theory model with auxiliary equations, which describe the effect of formation heterogeneity and mechanism of different EOR technique on fractional flow rate, an evaluation analysis method for EOR techniques applicability of gas flooding, foam flooding and surfactant flooding was proposed. In the gas flooding model, the minimum miscible pressure of impure gas was introduced, and the relative permeability was modified by the minimum miscible factor. In the foam flooding model, changes in the mobility ratio and chemical adsorption were considered and a reduction factor of mobility ratio was introduced. In the surfactant flooding model, calculation formulas of viscosity and interfacial tension as well as the relative permeability were introduced. Finally, the model was simulated for a low permeability reservoir, and the simulation results were compared with that from Eclipse software. The similar results, little calculation time and feasibility of predicting optimal injection parameter had shown the reliability of the rapid evaluation model.

Utilization mechanism of foam flooding and distribution situation of residual oil in fractured-vuggy carbonate reservoirs

The development of fractured-vuggy carbonate reservoirs is extremely difficult because of the complex fractured-vuggy structure and strong heterogeneity. Foam flooding is a potential enhanced oil recovery (EOR) technology in fractured-vuggy carbonate reservoirs. Based on the similarity criterion, three types of 2D visual physical models of the fractured-vuggy structure were made by laser ablation technique, and a 3D visual physical model of the fractured-vuggy reservoir was made by 3D printing technology. Then the physical analog experiments of foam flooding were carried out in these models. The experimental results show that foam can effectively improve the mobility ratio, control the flow velocity of the fluid in different directions, and sweep complex fracture networks. The effect of foam flooding in fractures can be improved by increasing foam strength and enhancing foam stability. The effect of foam flooding in vugs can be improved by reducing the density of the foam and the interfacial tension between foam and oil. Three types of microscopic residual oil and three types of macroscopic residual oil can be displaced by foam flooding. This study verifies the EOR of foam flooding in the fractured-vuggy reservoir and provides theoretical support for the application of foam flooding in fractured-vuggy reservoirs.

Adaptation study on nitrogen foam flooding in thick reservoirs with high water cut and high permeability

Most of the oilfields in China are in high- or ultrahigh-water-cut stages, and the impacts of water flooding developments have declined due to the increase in reservoir heterogeneity, the rapid increase in the water cut and the discontinuous distribution of crude oil under these conditions. Based on this phenomenon, an experimental study of nitrogen foam flooding is conducted in this paper. The oil displacement characteristics of nitrogen foam in oil and water layers of thick, high-porosity and high-permeability reservoirs are studied through one-dimensional core tube experiments, and the mechanisms of profile control and water plugging are analyzed. Through two-dimensional visualization experiments, we observe the migration and diffusion patterns of nitrogen foam, analyze the effects of different degrees of vertical foam production on the residual oil after water flooding, clarify the production effect of gas overburden on the residual oil at the top of the reservoir, and summarize the mechanisms of nitrogen foam flooding involved in improving the recovery factor. The results show that in the core tube experiment, the recovery factor of the high-permeability core is 93.73%, the recovery factor of the low-permeability core is 71.33%, and the total recovery factor reaches 83.23% in the stage of nitrogen foam flooding, which is 28.96% higher than that of water flooding. In the visualization experiment, the recovery factor of the nitrogen foam flooding stage is 57.12%, which is 24.99% higher than that of water flooding. The recovery degrees of the layers are similar; by comparing the increase in the recovery degree of each layer before and after the two stages, it is found that the increase in recovery degree increases from the bottom to the top. The foam system exhibits a good selective plugging ability under the conditions of severe heterogeneity and low residual oil in the high-permeability zone. Nitrogen foam flooding can effectively improve the recovery factor in the late-stage reservoir development of the ultrahigh-water-cut stage, and it shows good adaptability to these types of reservoirs.

Experimental Study on Chemical Recovery of Low-Permeability and Medium-Deep Heavy Oil Reservoir

To improve the oil recovery of a block in the Wutonggou Formation of the Changji Oilfield, viscosity reducing and foaming agent was optimized to improve the development effect of the water flooding reservoir. The core flooding experiment and microscopic visual experiment were conducted to investigate the production characteristics and EOR mechanism of nitrogen foam flooding. The results show that the 0.5 wt% viscosity reducing and foaming agent DXY-03 was optimized. In the process of microscopic oil displacement by nitrogen foam, nitrogen foam continuously expands and spreads, improves oil displacement efficiency, and greatly improves oil recovery through emulsification and viscosity reduction, squeezing action, dragging action, and Jamin effect. The core flooding experiment shows that on the basis of the water flooding recovery rate of 20.3%, the nitrogen foam huff and puff is increased by 9.2%. The viscosity reducing and foaming agent flooding is increased by 7.8%, and the nitrogen foam flooding is increased by 12.9%. The main EOR mechanism of the viscosity reducing and foaming agent is that it can reduce the interfacial tension between oil and water and can promote heavy oil emulsification and dispersion, thereby forming an oil/water- (O/W-) type emulsion. The reduction in the viscosity of heavy oil makes crude oil easier to extract, realizing the synergistic viscosity reducing and efficiency enhancing effect of nitrogen and viscosity reducing and foaming agents. This study is helpful to provide reference for the development of low-permeability and high-viscosity medium-deep heavy oil reservoirs by chemical agents combined with cold production.

Implications of sand mobilization on stability and rheological properties of carbon dioxide foam and its transport mechanism in unconsolidated sandstone

This study reports the role of sand grain (of varying size: 60–380 μm and concentration: 0–3 wt%) on stability and properties of Pickering carbon dioxide (CO2) foam, which relates to foam transport problem during oil recovery practice in unconsolidated formation. For foams, anionic surfactant (sodium dodecyl sulfate: 0.2 wt%) and single-step silica nanofluid (0.1 wt%, size: 33–38 nm) were used and Pickering foams were prepared by mechanical agitation in the presence of different sand (comprised mainly of quartz with traces of clay), to mimic the effect of grain on foam stability. Interestingly, a varying stability exists in presence of sand. Thus, foam volume increased from 48 ml (without sand) to 58 ml when 1 wt% sand (of size ≈ 60–120 μm) was added while it further reduced to 46 and 40 ml with 2 and 3 wt% sand, respectively. On the contrary, foam stability continuously reduced with increment in sand size (from 60 to 120 to 200–380 μm), indicating unfavorable role of sand size on foam stability. Thus, sand production during oil recovery process is unfavorable for the stability of foam systems. The effect of sand concentration and size on foam properties was validated by interfacial tension and rheological measurements. Interfacial tension between CO2-nanofluid decreased till 1 wt% sand, suggesting favorable role of sand on CO2-nanofluid interaction. Similarly, CO2 foam showed maximum viscosity (72.8 mPa s) at 1 wt% sand (of size ≈ 60–120 μm) while further increase in concentration (>1 wt%) and size (>120 μm) reduced foam viscosity. These foams also exhibited viscoelastic characteristics with presence of both storage and viscous moduli. The solid-like nature of foam was least affected by the increase in deformational strain and foams exhibited dominating storage modulus over the range strain explored. Thus, the observation of this study can be used to optimize foam flooding in sandstone reservoirs which exhibit sand/fines production.

Applicability of methane foam stabilized via Nanoparticles for enhanced oil recovery from carbonate porous media at various temperatures

Over the 60 years of primary production from carbonate oil reservoirs in the middle east, approximately 30 % of initial oil in place has been recovered in this area and the rest requires appropriate enhanced oil recovery (EOR) methods for production. Since there are huge gas resources in this area, applications of gas-based EOR methods especially those with methane gas should be the top priority. Therefore, the objective of this study is to experimentally determine and compare the influences of stabled methane foams via aluminum oxide (Al2O3), titanium dioxide (TiO2), zinc oxide (ZnO), and silica (SiO2) nanoparticles (NPs) for EOR from a limestone porous medium at 25, 50 and 85 °C. For this goal, 0.1 wt% Sodium dodecyl sulfate (SDS) was dissolved in NaCl solution 0.5 wt% and then the above-mentioned nanopowders at concentrations from 0.005 to 0.1 wt% were added. Methane at a flow rate of 250 ml/min was injected into the suspensions and the stability of produced foams was defined by measuring the half-life time. Once an optimum concentration of each NP type was found, that foam was chosen to be flooded to the limestone porous medium for EOR purposes. The optimum NP content in terms of foam stability at all temperatures was achieved at 0.01 wt% for SiO2 and ZnO NPs and 0.05 wt% for TiO2 and Al2O3 NPs. Half-life time values of methane foams in the presence of NPs were averagely found to be 16 and 3 times higher than those of the base foam at 25 and 85 °C, respectively. TiO2, Al2O3, ZnO, and SiO2 NPs in order were the best additives for foam stability at all temperatures. In addition, at 85 °C, the incremental oil recovery amounts from the limestone porous medium by TiO2, Al2O3, ZnO, and SiO2 NPs-methane foams were achieved 20.4, 18.9, 17.6, and 16.1 %, respectively, which were 6 to 10 % higher than foam flood tests without NPs. Overall, it can be concluded that NPs methane foam flooding is a promising method for EOR from carbonate porous media in the middle east area.

In-situ emulsification synergistic self-profile control system on heavy oil reservoir development: Prescription construction and EOR mechanism investigation

Water flooding is a vital method used for developing heavy oil reservoirs. However, the fingering phenomenon is common because of the significant difference in water-oil mobility ratio, resulting in limited sweep efficiency and a low cumulative recovery factor. Viscosity reduction through emulsification and profile control using foam is of great potential to enhance oil recovery (EOR) in water flooding of general heavy oil reservoirs. The present work constructed an effective in-situ emulsification synergistic self-adjusting profile control system based on these two EOR pathways and investigated the performances of the proposed system, such as viscosity reduction via emulsification, foam plugging, and synergistic oil displacement. The results show that sodium octadecyl phenol polyoxyethylene ether sulfonate-4 (JNPM) with sound viscosity reduction, profile control, and oil displacement effects were synthesized through chlorination and sulfonation reactions. JNPM can reduce the oil-water interfacial tension and promote the emulsification of heavy oil in an effective way. It forms an unstable micron-scale oil-in-water emulsion, which is easy to induce oil-water separation of the produced fluid. The reduction in viscosity for JNPM exceeds 90%, whereas the foam produced by JNPM can adequately reduce the relative permeability of the displacement medium, and it is found that the resistance factor is higher than 25. The EOR mechanisms of JNPM include the following aspects. JNPM foam fluid has a stable plugging capability on the channeling channels of the displacement media, such as water and gas, which forcefully increases the residual oil sweep efficiency. JNPM peels off the residual oil on the pore wall through emulsification, thus the oil washing efficiency is improved. The droplets of oil formed by emulsification can block the channeling channels through the Jamin effect to further increase the conformance efficiency. In addition, when the small droplets deform and pass through the pores, they can sweep away the residual oil by dragging and entraining effects. The contributions of viscosity-reducing emulsification and foam plugging to EOR are 26.4% and 12.0% respectively during the viscosity-reducing foam flooding of JNPM.

The development of heat‐resistant and salt‐tolerant foam with betaine surfactants

AbstractA modified instrument was designed to evaluate foam properties under high temperature and pressure. The type and molar ratio of betaine surfactants were screened to develop the heat‐resistant and salt‐tolerant foam for Tahe oilfield (130°C, 220 g/L), and the effects of temperature and pressure on foam properties were also investigated. The synergism between surfactants and the enhanced oil recovery (EOR) mechanism of foam flooding in fractured‐vuggy reservoirs were studied. Experimental results showed the developed foam had excellent foaming ability and foam stability when the lauramidopropyl hydroxyl sulfobetaine (LHSB): erucic amide propyl betaine (EAB) molar ratio ranged from 1:1 to 1:2 (initial foam volume was 392 ml when the molar ratio was 1:1, drainage half‐time was 5.75 min and foam half‐time was 72 min when the molar ratio was 1:2 at 130°C and 2 MPa). The synergistic effect was found to reach its maximum when the LHSB:EAB molar ratio ranged from 1:1 to 1:2 according to interaction parameters, which agreed with the results of foam properties. Foam stability was found to considerably increase with increasing pressure, but decrease with increasing temperature. However, temperature and pressure were found to have consistent effects on foaming ability, that is, the foaming ability increased with increasing temperature and pressure. The flooding test showed foam flooding exhibited better sweep efficiency and higher recovery ratio in the fractured‐vuggy model than gas flooding and water flooding. This could be because injected foam did not channel through the top (or bottom) path due to its high viscosity and moderate density.

Effects of Porous Media on Foam Properties

AbstractFoam flooding is an important pathway for enhanced oil recovery. However, the evaluation of foam properties is usually carried out in free space, which can not accurately reflect the performance of foam in porous oil formation. In the present work, by investigating the foamability and stability of foam systems in sand‐pack models with average pore throat radius from 1.24 μm to 4.28 μm, the effects of porous media on foam properties are studied. Compared with foam systems in free space, foam systems in porous media have longer foam half‐life, longer drainage half‐life, and higher foam comprehensive index. The foam volume of foam systems in porous media could be higher or lower than that in free space, depending on the average pore throat radius of the porous media. Generally, in porous media, with the decreasing of pore throat radius, the foamability of the foam systems gradually decreases while the foam stability gradually increases. Moreover, the bubble size and liquid film thickness also decrease with the decreasing of pore throat radius of the porous media. Above all, the behaviors of foams are significantly affected by porous media. When investigating a foam system to evaluate its performance for foam flooding in oil recovery or other applications in porous media, porous models which could reflect the target conditions should be considered to obtain more trustable results.

Study on the Compatibility between Combined Control of Channel Plugging and Foam Flooding and Heterogeneous Reservoirs—Taking Bohai Z Oilfield as an Example

With the oilfield developed to a later stage and its heterogeneity gradually becoming more serious, the adaptability of conventional profile control technologies for the reservoir becomes worse and worse. Therefore, the fitness of compatibility between combined patterns of profile control and target reservoir becomes an important factor for the efficient development of the oil field. Due to the importance of compatibility between the profile control and reservoir property, research on the remaining oil recovery with combined patterns of profile control and foam flooding were carried out. The experimental results showed that the combined profile control is highly consistent with the target reservoir. With a little lower initial viscosity (28.3–40.9 mPa·s), the channel plugging system is easy to inject. Due to the addition of a polymer, the reinforced foam is not easy to defoam when transporting in the pore throats of the core sample, and its spontaneous adaptability makes it match with the porous media of the formation automatically, which effectively prolongs the transporting distance for the foam in the deep part of the core sample. The segment plug with a gel-type profile control agent injected at the front stage is of great significance to the non-homogeneous reservoir, so it is necessary to inject a sufficient gel-type profile control agent into the high permeability layer to make it produce a seal. When the permeability differential was equal to 10, the maximum increase of oil recovery degree was 29.69%, and the development effect became worse after increasing or decreasing the permeability differential.

Stability mechanism of SiO2/SDS dispersion for foam flooding in hydrocarbon reservoirs: experimental research and molecular simulation.

The dispersion of silica dioxide (SiO2)/sodium lauryl sulfate (SDS) has been widely used in hydrocarbon reservoirs, but its instability is still a problem in practical engineering applications. The dispersion morphology of SiO2 nanoparticles before and after modification was studied by TEM, and the thermal stability of different foam dispersions was evaluated by FoamScan. In this paper, the mechanism of foam stability was investigated by combining the measurement of interfacial energy of nanoparticles at the gas-liquid interface with dynamics simulation of molecular diffusion. The results showed that SiO2/SDS dispersions had good thermal stability due to the synergistic effect of SiO2 nanoparticles and SDS. The addition of SiO2 nanoparticles improved the interfacial energy and interfacial activity at the gas-liquid interface, meanwhile limited the movement of SDS molecules and water molecules, which was beneficial for foam stability. Notably, the addition of modified SiO2 nanoparticles further enhanced the interfacial energy at the gas-liquid interface and strengthened the restriction of water/SDS molecular movement, thereby slowing down the drainage and decay of the foam dispersions. The mechanism investigation of SiO2/SDS dispersions was of benefit to foam flooding in hydrocarbon reservoirs.

Investigation on the Stability of Janus SiO2-n Nanoparticle-Assisted Nonionic Surfactant-Stabilized Foam and Its Application in Enhanced Oil Recovery

The stability of the foam directly impacts the final efficiency of the foam flooding in enhanced oil recovery (EOR). In the present work, a series of Janus SiO2-n nanoparticles (JSn NPs) with various modification degrees were successfully prepared and employed to improve the stability of the nonionic surfactant polyethylene glycolmonoisodecylether (PMIE)-stabilized foam. The PMIE–JS3 system with a much low JS3 NP concentration (0.1 wt %) displayed extraordinary foamability and stabilizing foam ability via the foam volume, half-life, relative volume decay, and optical microscope photograph measurements. Then, the dynamic surface tension and dilatational viscoelasticity tests were conducted to explore the mechanism. It was found that the PMIE–JS3 system with great interfacial activity and intensive interfacial film highly facilitated the generation of the foam and improved the foam stability. Moreover, the PMIE–JS3-stabilized foam exhibited outstanding stability, even under the influence of crude oil. The sandpack flooding tests indicated that the PMIE–JS3-stabilized foam could effectively plug the high-permeability channels to modify the water injection profile and consequently greatly enhanced tertiary oil recovery (∼15.3% of the initial oil in place).

Microscopic Mechanical Model Analysis and Visualization Investigation of SiO2 Nanoparticle/HPAM Polymer Foam Liquid Film Displacing Heavy Oil.

In this paper, the microscopic mechanisms and macroscopic characteristics of polymer/nanoparticle foam flooding in a heavy oil reservoir environment were studied. Sodium dodecyl sulfate (SDS) surfactant was used as the foaming agent, and the foam was prepared by a combination of partially hydrolyzed polyacrylamide (HPAM) polymer and SiO2 nanoparticles. By performing experiments with the microscopic model, the foam flooding dynamics in the heavy oil reservoir were simulated. Based on the experiments, the formula model was established to evaluate the physicochemical effects between the foam liquid film and oil surface. Finally, the macroscopic characteristics of foam flooding were studied by performing oil displacement experiments with a 2D visual model. The microscopic experiments demonstrated that the foam liquid film could exert multiple actions, such as adsorption, stretching, and cutting on the heavy oil in the reservoir pores. These actions were accompanied by force changes between the foam and heavy oil, and the addition of polymer and nanoparticles further strengthened them. The calculations of the formula model indicated that the polymer and nanoparticles amplified the force between the foam liquid film and heavy oil by 1.95 and 2.2 times, respectively. The 2D visual model experiments suggested that foam flooding could further develop heavy oil after water flooding through its liquid film effects, and the oil recovery efficiency increased from 42.43 to 57.82%. In addition, the polymer and nanoparticles further optimized the oil displacement effect of the foam liquid film, which made the oil recovery efficiency reach 64.77-68.16%.