Effects and Mechanisms of Dilute-Foam Dispersion System on Enhanced Oil Recovery from Pore-Scale to Core-Scale

Abstract

The dilute-foam dispersion system improves oil recovery by reducing interfacial tension between oil and water, altering wettability, and diverting displaced fluids by plugging larger pores. An optimized foaming system is obtained by formability evaluation experiments, in which the half-life for drainage and foaming volume by different types and concentrations of surfactants are analyzed, followed by the addition of partially hydrolyzed polyacrylamide (HPAM) with varied concentrations to enhance the foam stability. Using COMSOL Multiphysics 5.6 software, the Jamin effect and plugging mechanism of the water–gas dispersion system in narrow pore throats were simulated. This dispersion system is applied to assist CO₂ huff-n-puff in a low-permeability core, combined with the online NMR method, to investigate its effects on enhanced oil recovery from the pore scale. Core-flooding experiments with double-pipe parallel cores are then performed to check the effect and mechanism of this dilute-foam dispersion system (DFDS) on enhanced oil recovery from the core scale. Results show that foam generated by combining 0.6% alpha-olefin sulfonate (AOS) foaming agent with 0.3% HPAM foam stabilizer exhibits the strongest foamability and the best foam stability. The recovery factor of the DFDS-assisted CO₂ huff-n-puff method is improved by 6.13% over CO₂ huff-n-puff, with smaller pores increased by 30.48%. After applying DFDS, the minimum pore radius for oil utilization is changed from 0.04 µm to 0.029 µm. The calculation method for the effective working distance of CO₂ huff-n-puff for core samples is proposed in this study, and it is increased from 1.7 cm to 2.05 cm for the 5 cm long core by applying DFDS. Double-pipe parallel core-flooding experiments show that this dispersion system can increase the total recovery factor by 17.4%. The DFDS effectively blocks high-permeability layers, adjusts the liquid intake profile, and improves recovery efficiency in heterogeneous reservoirs.

1. Introduction

When a reservoir develops into a high water-cut stage, its high heterogeneity and interlayer contradictions cause severe water channeling in high-permeability layers and leave significant residual oil in low-permeability layers, resulting in a poor overall recovery factor. Many researchers have studied the water–gas dispersion system’s ability to redirect liquid flow and improve oil displacement efficiency through laboratory experiments [1,2,3,4].

The water–gas dispersion system consists of a mixture of water and gas, with gas dispersed into the liquid phase [5]. Foam is one type of water–gas dispersion system. Depending on the characteristic value (gas volume per unit volume of foam), the system can be categorized as either a dilute- or concentrated-foam dispersion system [5]. After a surfactant is added to the water–gas dispersion system, the surface of the bubbles will be covered with a thick, liquid film, and the system viscosity and dynamic shear force will increase. Typically, chemical agents are added to enhance the foam stability. The viscosity of the system, determined by the friction between the liquid films on the bubbles’ surface, mutual squeezing and collision of bubbles, and internal friction of the liquid phase, is further enhanced by the addition of foam stabilizers, delaying the liquid drainage process, achieving better water plugging and profile control, and redirecting liquid flow, thereby enhancing oil displacement efficiency [6,7]. After the addition of stabilizers and additives to the water–gas dispersion system, the dispersed phase is in the form of hexahedrons, resulting in better stability, higher apparent viscosity, and greater seepage resistance. Generally speaking, when the characteristic value is 52~74%, the water–gas dispersion system is called a dilute-foam dispersion system, and when the characteristic value is 74~97%, it is called a concentrated-foam dispersion system [5].

In porous media, the transport mechanisms of the water–gas dispersion system include the Jamin effect, coalescence mechanism, and selective plugging mechanism. The water–gas dispersion system can improve the oil recovery rate by rapidly reducing the gas phase’s relative permeability, delaying the gas breakthrough in the high-permeability layer, and blocking the high-permeability layer. The better the connectivity of the porous medium, the higher the oil recovery rate [8,9,10,11]. Based on these mechanisms, the water–gas dispersion system is effective in regulating the mobility ratio in different layers with different levels of permeability, including ultra-low, low, and medium permeability, achieving more uniform profile control, increasing sweep volume, and reducing residual oil saturation [2,3,12,13].

The M and N Block in Jidong oilfield belong to a low-permeability reservoir (≤50 mD). The M Block is a small, faulted block, and the water-flooding effect is poor because an effective well pattern cannot be established, so a suitable medium needs to be selected for the huff-n-puff method. The N Block shows strong heterogeneity after long-time water injection, leading to high-permeability channels. It is necessary to use the profile control and water plugging method to improve oil recovery. A suitable dilute-foam dispersion system is selected for both the M and N Blocks, in which a low concentration of HPAM is added as a foam stabilizer. The selected dispersion system is used as an assistant medium to CO₂ huff-n-puff, and its enhanced oil recovery effect from the pore scale is investigated. This dispersion system is then studied from the core scale and used in a parallel two-pipe core-flooding experiment, from which the effect and mechanism of the dispersion system over water-flooding are concluded. At present, there is a lack of systematic research on the mechanism of the profile control and plugging of the dilute-foam dispersion system, and the law of foam migration is not clear. In this paper, COMSOL Multiphysics 5.6 software and laboratory experiments are combined to systematically study the blocking mechanism and enhanced oil recovery effect of a dilute-foam dispersion system from the micro to the macro scale through various experimental means, which provides guidelines for the application of a dilute-foam dispersion system in an oilfield.

2. Simulation of Jamin Effect in Water–Gas Dispersion System

The Jamin effect in the flow of the water–gas dispersion system generates greater flow resistance during displacement, preventing fluid channeling. Using COMSOL Multiphysics software, the Jamin effect of dispersed-phase bubbles moving through narrow pore throats under different surface tension conditions is simulated.

2.1. Simulation of Jamin Effect in Simplified Channels

2.1.1. Level-Set Function and Fluid Control Equation

(1)

Level-Set Function

The level-set function is an effective method to solve the gas–liquid interface movement on the pore scale which can naturally deal with the topological changes and simulate the migration mechanism of the water–gas dispersion system under the simplified pore channels. The level-set function is a smooth, continuous function with a value of 0.5 on the interface. In the transition layer near the interface, the function ϕ smoothly changes from 0 to 1. In the liquid-filled area, ϕ < 0.5, and in the CO₂ area, ϕ > 0.5.

The discontinuity of fluid parameter changes at the interface when simulating moving boundary is solved by fixing interface thickness. In the CFD module of COMSOL, the following level-set equations are solved.

$${\displaystyle \frac{\partial \mathsf{\varphi }}{\partial \mathrm{t}}}+\mathrm{u}·\nabla \mathsf{\varphi }=\mathsf{\gamma }\nabla ·(\mathsf{\epsilon }\nabla \mathsf{\varphi }-\mathsf{\varphi }(1-\mathsf{\varphi }){\displaystyle \frac{\nabla \mathsf{\varphi }}{|\nabla \mathsf{\varphi }|}})$$

(1)

In the formula, ε is the interface thickness control parameter, and the ideal value is half of the maximum cell size: ε = h_c/2. γ is the interface initialization parameter (equal to the entry speed). In the simulation, the parameter γ defines the reinitialization intensity as 0.001 m/s.

(2)

Fluid Control Equation

The water–gas dispersion system is an incompressible fluid, and the fluid momentum equation is expressed by the incompressible Navier–Stokes equation of gas-liquid two-phase flow. The surface tension should be considered in the calculation process:

Navier–Stokes equations:

$$\mathsf{\rho }{\displaystyle \frac{\partial \mathrm{u}}{\partial \mathrm{t}}}+\mathsf{\rho }\left(\mathrm{u}·\nabla \right)\mathrm{u}-\nabla ·\left\{-\mathrm{p}\mathrm{I}+\mathsf{\mu }\left(\nabla \mathsf{\mu }+\nabla {\mathsf{\mu }}^{\mathrm{T}}\right)\right\}={\mathrm{F}}_{\mathrm{s}\mathrm{t}}$$

(2)

$$\nabla ·\mathrm{u}=0$$

(3)

$${\mathrm{F}}_{\mathrm{s}\mathrm{t}}=\mathsf{\sigma }\mathsf{\delta }\mathsf{\kappa }\mathrm{n}$$

(4)

$$\mathsf{\delta }=6\left|\mathsf{\varphi }\left(1-\mathsf{\varphi }\right)\right||\nabla \mathsf{\varphi }|$$

(5)

In the formula, $\mathsf{\rho }$: fluid density; $\mathrm{u}$: fluid velocity vector; t: time; $\mathsf{\mu }$: hydrodynamic viscosity; p: pressure; $\mathrm{I}$: identity matrix; ${\mathrm{F}}_{\mathrm{st}}$: gas–liquid surface tension; $\mathrm{n}$: the interface unit normal boundary vector pointing to the dispersed phase; σ: surface tension coefficient; κ: curvature, κ = −$\nabla$∙$\mathrm{n}$; $\mathsf{\delta }$: non-zero Dirac function at the fluid interface.

2.1.2. Establishment of Geometric Model

A two-dimensional plane model was established. The pore with radius R₁ = 2.8 µm and length 15 µm were on the left side of the pore throat. On the right, there is a throat with a radius of R₂ = 1.4 µm, a length of 15 µm, a radius ratio of 2:1, and a bubble radius of the water–vapor dispersion system R = 2.5 µm.

2.1.3. Setting Initial Values and Boundary Conditions

(1)

Initial value

The initial conditions for setting the model are shown in

Table 1. Basic parameters of the model.

Item	Continuous Phase (Water)	Dispersed Phase (CO2)
Density/kg·m−3	1000	1.225
Viscosity/Pa·s	0.00298	1.789 × 10−3
Surface tension/N·m	5.6 × 10−2
Contact angle/°	90	90
Slip length/$\mathsf{\mu }$m	1	1

.

(2)

Setting of boundary conditions

The fluid Reynolds number in the simplified channel is very small, that is, Re < < 1, so the fluid flow state is laminar flow, and the boundary conditions are set as follows:

①

Inlet boundary conditions: The water–vapor dispersion system flows into the left inlet at a certain flow rate through the narrow throat, using the inlet boundary condition with a level-set function of 1.

②

Outlet boundary condition: The pressure of the water–gas dispersion system fluid flowing out of the fixed outlet is constant, and the outlet pressure is 0.

③

Wetting wall boundary conditions: the contact angle of the wetting degree of the wall is expressed as θ, and the slip length of the wetting wall is certain. The model and boundary conditions of the Jamin effect in the water–gas dispersion system are shown in Figure 1.

2.1.4. Mesh Division and Model Solving

In this paper, a free triangular mesh is used to divide the model. Key parameters of the grids are set as follows: the maximum cell growth rate is 0.8; the curvature factor is 0.2; and the narrow area resolution is 1. It contains 9846 triangular mesh cells and 5125 mesh vertices, with a minimum cell mass of 0.5337 and an average cell mass of 0.9346. “Transient study including phase initialization” is selected for the simulation of transient two-phase flow.

2.2. Simulation Results

A single CO₂ bubble moving from a large pore to a small throat is depicted in Figure 2. At 0.02 s, the bubble undergoes stretching deformation; at 0.07 s, the deformation is at its maximum, with the bubble blocking the pore throat, causing maximum pressure and flow resistance. The cumulative effect of multiple CO₂ bubbles can achieve effective plugging. At 0.3 s, most of the bubble passes through the pore throat with a rapid drop in pressure, causing a large change in the gas–liquid interface and resulting in negative pressure. By 0.5 s, the bubble has completely passed through the simulated pore channel.

The influence of surface tension on the pressure change at the pore throat connection point is further analyzed, as shown in Figure 3. It shows that, with the increase in surface tension, it is more difficult for bubbles to stretch and deform, and the pressure at the pore throat connecting point increases. When the surface tension is too low, the pressure decreases, the Jamin effect weakens, and the pores cannot be effectively blocked. Therefore, it is necessary to consider the stability of the dispersed phase bubble and the surface tension of the water–gas dispersion system.

3. Experimental Description

The dilute-foam dispersion system can regulate the profile of heterogeneous reservoirs, improving oil displacement efficiency. However, foam stability affects the system’s plugging effect and oil displacement performance [13]. The surfactants used to form the dilute-foam dispersion system can be anionic, cationic, amphoteric, or nonionic [14]. The types of surfactants used in the dilute-foam dispersion system are shown in

Table 2. Types of surfactants for dilute-foam dispersion systems [15].

Type	Representative Material	Specific Example
Anionic surfactant	Sulfonates	Sodium dodecyl sulfonate
	Sulfate salts	Sodium lauryl sulfate
	Phosphate ester salts	Potassium cetyl phosphate
Cationic surfactant	Alkyl pyridine salts	Stearate TEA salt
	Alkyl amine salts	Tetacylpyridine salt
Amphoteric surfactant	Amino acid salts	Sodium lauryl glutamate (LG-95P)
	betaine	Dodecyl dimethyl betaine (BS-12)
	Imidazoline type	Sodium cocamyl amphoacetate (CAMC)
Nonionic surfactant	Polyoxyethylene type	Polysorbate
	Polyol type	Glycerin stearate ester

.

The anionic surfactant has good stability and solubility, and the adsorption loss is small in the oil displacement process. Amphoteric surfactants exhibit excellent temperature and salt resistance and can be combined with other surfactants. Although cationic surfactants have good salt resistance, their price is high, and the adsorption loss is great during displacement. Non-ionic surfactants have a high price, low foam performance, poor temperature resistance, and a large adsorption capacity. Therefore, two anionic surfactants and one amphoteric surfactant were selected for screening evaluation. Foamability evaluation experiments were performed to select surfactants with strong foamability and efficient foam stabilizers, formulating a dilute-foam dispersion system. Core-flooding experiments were conducted to determine the blocking effect and mechanism of the foam system on enhanced oil recovery.

3.1. Experimental Materials and Instruments

The following surfactants were used for the experiment: anionic surfactants, sodium dodecyl sulfate (SDS) and alpha-olefin sulfonate (AOS); amphoteric surfactants, betaine surfactant (BS-12).

Foam stabilizer: polyacrylamide (HPAM) with a molecular weight of 15 million.

Gas: nitrogen (purity 99.2–99.999%).

Water: simulated formation water (total salinity of 7516 mg/L).

Oil: mixture of degassed crude oil from Jidong N Block and aviation kerosene, with a viscosity of 1.25 mPa·s (50 °C, 0.101 MPa) and density of 0.797 g·cm⁻³ (50 °C, 0.101 MPa).

Core: due to the inaccessibility of natural cores from the oilfield, artificial cores were used. Core data and experimental parameters are shown in

Table 3. Parameters of cores for dilute-foam enhanced dispersion system displacement experiment.

Core Number	Diameter /cm	Porosity /%	Length /cm	Permeability /(10−3 μm2)	Experimental Scheme	Experimental Content
1#	2.51	19.55	5.00	50.42	Online NMR huff-n-puff	CO2 huff-n-puff
2#	2.51	22.13	5.00	50.36		DFDS-assisted CO2 huff-n-puff
3#	2.50	37.73	29.90	49.59	Parallel core displacement	Water flooding + DFDS flooding + water flooding
4#	2.50	12.10	30.35	9.61

.

Instruments: Waring Blender high-speed mixer, high-precision electronic balance (accuracy to 0.001 g), graduated cylinder, stopwatch, YRD-II electric thermostat, DSRT-II displacement pump, high-temperature and high-pressure core holder, etc.

3.2. Foamability and Foam Stability Experimental Methods

The static stability of the foam was evaluated at a temperature of (50 °C) using the Waring Blender method (high-speed stirring). The foaming volume and half-life for the drainage of foam formed by three surfactants were measured.

Experimental procedure:

(1)

Weigh a certain amount of surfactant and dissolve it in 100 mL of distilled water in a beaker. Pour the solution into a high-speed mixer and stir at 10,000 rpm for 1 min.

(2)

Quickly pour the generated foam into a 1000 mL graduated cylinder and start timing. The initial foam volume V (mL), measured at 0 s, indicates the foaming volume.

(3)

Record the time t (s) to drain 50 mL of liquid from the foam, representing the foam’s half-life for drainage and indicating foam stability.

3.3. Pore-Scale Investigation with Online NMR CO₂ Huff-n-Puff Experiments

Experimental procedure:

(1)

Put the core in a 50 °C high-temperature and high-pressure gripper and vacuum for 48 h. Close the back pressure valve, and then inject the prepared simulated oil. When the system pressure reaches 20 MPa, stop the pump and stabilize it for a long enough time.

(2)

Close the inlet end and outlet end of the core holder and connect the return pressure valve to the inlet end.

(3)

Dilute-foam dispersive system (DFDS for short)-assisted CO₂ huff-n-puff: inject 0.05 PV dilute foam alternately at a pressure of 25 MPa to strengthen the dispersion system and 0.05 PV CO₂. When the system pressure reaches 25 MPa, stop the pump and wait for 5 h.

(4)

Then, carry out throughput until the pressure at the gas injection end drops to 15 MPa, and measure and record the oil production; proceed to the next injection huff. Repeat steps (2)–(3) three or more times until no oil is produced and the final huff pressure is reduced to atmospheric pressure. Test the NMR T₂ spectra after each round of huff-n-puff and perform NMR imaging analysis after huff-n-puff. The experimental parameters are shown in Table 3.

3.4. Core-Scale Investigation with Core-Flooding Experimental Methods

Parallel double-pipe core displacement experiments were then performed to investigate the profile control and water-plugging effects of this system.

Experimental procedure:

(1)

After the core is vacuumed, saturate it with formation water, measure its wet weight, and calculate the effective pore volume. Measure the gas permeability and use crude oil to displace the water until no water is produced, calculating the oil saturation.

(2)

Age the core in a 50 °C electric thermostat for 12 h.

(3)

Water flooding: maintain the thermo-tank at 50 °C, set the back pressure to 10 MPa, and displace the core at a constant flow rate.

(4)

Parallel double-pipe core displacement: after water flooding, inject the DFDS (0.1 PV CO₂ + 0.1 PV foaming solution + 0.1 PV CO₂) into cores 3# and 4#, and then inject water again until the combined water cut at the outlet is 98%.

The experimental data error is about 2%.

4. Experimental Results and Analysis

4.1. Selection of Foaming Agent and Stabilizer

4.1.1. Selection of Type and Concentration of Foaming Agent

Using distilled water, 10 different concentrations (0.1~1%) of three surfactants were prepared. The foam performance was evaluated using the high-speed stirring method to determine the half-life for drainage and the foam volume.

The foam volume and the half-life for drainage at different surfactant concentrations are shown in Figure 4 and Figure 5, respectively. As the surfactant concentration increased, both the foam volume and the half-life for drainage increased until the concentration reached 0.6%, after which they remained relatively constant. At higher concentrations, micelles formed within the water phase, and the gas–liquid interface properties had no more significant change, leading to stable foam stability. Among the three surfactants, at concentrations of 0.6~1.0%, there was little difference in foaming volume, but AOS had a longer half-life for drainage, indicating better foam stability. Among the three surfactants, the half-life of AOS was the longest due to its high zeta potential, the large number of monomer molecules in the solution, and the increment in the elasticity and strength of the liquid film due to the repulsion between molecules [16]. At the same time, the negative charge in the molecular head group of an anionic surfactant forms a diffusion double electric layer on the gas–liquid surface. When the liquid films are close to a certain degree, liquid films with the same charge will repel each other to prevent them from thinning and will be more stable than the foam made by amphoteric surfactants [17]. Therefore, 0.6% AOS was selected as the foaming agent for the subsequent dilute-foam dispersion system.

4.1.2. Selection of Foam Stabilizer Concentration

Using 0.6% AOS as the foaming agent, the effect of varied HPAM concentrations on foam volume and half-life for drainage was studied, and the results are shown in Figure 6.

As the HPAM concentration increased, the foam volume decreased, but the decrease was relatively slow. The half-life for drainage increased with HPAM concentration from 0% to 0.3% but then remained stable as the concentration increased further. Therefore, 0.3% HPAM was chosen as the foaming stabilizer.

From these experiments, the composition of the foam dispersion system was determined to be 0.6% AOS + 0.3% HPAM. According to the foaming volume of the foam dispersion system, the characteristic value of the foam is 0.72, which belongs to the dilute foam dispersion system. This dilute foam dispersion system was then used in experiments for pore-scale and core-scale investigation.

4.2. Mechanisms of Enhanced Oil Recovery by DFDS from Pore-Scale

Experiments of CO₂ huff-n-puff with and without DFDS combined with online Nuclear Magnetic Resonance (NMR) technology were performed. The relaxation time was converted into the pore radius for analysis with the following equation:

$$\mathrm{r}=\mathrm{C}\times {\mathrm{T}}_2$$

(6)

${\mathrm{T}}_2$: ${\mathrm{T}}_2$ spectrum; $\mathrm{r}$: pore radius, µm; $\mathrm{C}$: conversion coefficient. Generally, it is 0.02.

The ${\mathrm{T}}_2$ spectrum of each huff-n-puff cycle is shown in Figure 7, and the extent of oil utilization in pores with different ranges of radium is shown in Figure 8.

The pore size distribution of the two cores, 1# and 2#, can be analyzed by T₂ spectra after the cores are saturated with oil. The pore diameter distribution of the core is relatively simple due to the artificial effect, mainly concentrated in 0.6~10 µm, with a peak value of 3.6 µm, and there are fewer pores distributed between 0.02 and 0.6 µm. The crude oil signal gradually decreases with the increase in huff-n-puff cycles, and the pores of 0.6–10 µm are the main oil-producing pores. The oil signal decline of DFDS-assisted CO₂ huff-n-puff (core 2#) is much greater than that of CO₂ only (core 1#), and the recovery degree of core 2# is 42.13%, which is 6.13% higher than that of core 1#.

To be more generalized in pore size classification, the pore sizes were classified into small pores and large pores, with 2 µm being the characteristic value. Compared with the extent of crude oil production in pores with different radii, the minimum pore radius limit for single CO₂ huff-n-puff is 0.0476 µm, and the recovery factor (RF) of crude oil in 0.2~2 µm after CO₂ huff-n-puff is 26.67%, and in 2~200 µm, it is 40.54%. The minimum available pore radius for DFDS-assisted CO₂ huff-n-puff is 0.029 µm. The RF of crude oil in 0.2~2 µm is 58.00%, and in 2~200 µm pores, it is 35.44%. DFDS-assisted CO₂ huff-n-puff increased the lower limit of the pore radius and enhanced the productivity of crude oil in 0.2~2 µm pores, and the RF increased by 30.48% compared with CO₂ only.

DFDS can effectively block the macropores after assisting CO₂ huff-n-puff and improve the recovery degree of huff-n-puff.

The online NMR imaging results after huff-n-puff are shown in Figure 9. It is obvious from the images that, by applying DFDS, the residual oil is greatly reduced. To be more quantitative, the effective working distance is introduced to characterize oil utilization by CO₂ huff-n-puff in the core with and without DFDS. The effective working distance is defined to be equal to the volume of oil produced at the end of the huff-n-puff, divided by the product of the cross-sectional area of the core and the porosity.

$$\mathrm{D}={\displaystyle \frac{\mathrm{Q}}{\mathrm{A}\times \mathsf{\phi }}}$$

(7)

$\mathrm{D}$ is the effective working distance, cm; $\mathrm{Q}$ is oil volume produced, cm³; $\mathsf{\phi }$ is the porosity; $\mathrm{A}$ is the core cross-sectional area, cm².

The results show that the effective distance of CO₂ huff-n-puff is 1.70 cm, and the DFDS-assisted CO₂ huff-n-puff distance is 2.05 cm, indicating once again that DFDS-assisted CO₂ can further improve the huff-n-puff effect.

4.3. Mechanisms of Enhanced Oil Recovery by DFDS from Core-Scale

To study the profile control and water-plugging effect, a double-pipe parallel core displacement experiment was designed. The experiment used two long cores with a permeability ratio of 5, and the core data are shown in Table 3. The core displacement results are shown in

Table 4. Experimental results of parallel core displacement.

Core Number	Permeability /(10−3 μm2)	Water Flooding Oil Recovery/%	DFDS Oil Recovery/%	Enhanced Oil Recovery/%
3#	49.59	47.9	60.1	12.2
4#	9.61	17.3	47.8	30.5
Combined oil recovery		36.9	54.3	17.4

.

The oil recovery factor curves in parallel cores and an illustration picture are shown in Figure 10. The relatively high-permeability core (3#) was first broken through during water flooding, while the relatively low-permeability core (4#) had a smaller swept volume. Therefore, during the water-flooding stage, when the total water cut at the core outlet reached 90%, 3# core had a higher oil recovery rate of 47.9%, while 4# core had a lower oil recovery rate of 17.3%, with a combined water-flooding oil-recovery factor of 36.9%.

Then DFDS was injected (0.1 PV CO₂ + 0.1 PV Foaming solution + 0.1 PV CO₂), reducing the combined water cut to 65%. Then, water was continuously injected until 2.3 PV, and finally the oil recovery factor of 3# core and 4# core increased significantly to 60.1% and 47.8% respectively. The ultimate increment in the combined oil recovery rate is 17.4%. The main reason for this phenomenon is that the DFDS can block dominant channels, playing a role in temporary plugging and diversion so that the injection pressure increases, allowing the system to enter the low-permeability core and displace more oil.

5. Conclusions

This study used foamability evaluation experiments to select surfactants and foam stabilizers, forming a new dilute-foam dispersion system. The system’s abilities and mechanisms to enhance oil recovery were examined by an online NMR CO₂ huff-n-puff experiment and analyzed on a pore scale. Then, its plugging effect and profile control mechanism were also examined through double-pipe parallel core-flooding. The main conclusions are as follows:

(1)

Foam stability evaluation: The static stability of the foam was evaluated using the high-speed stirring method, comparing three typical surfactants: sodium dodecyl sulfate (SDS), betaine surfactant (BS-12), and alpha-olefin sulfonate (AOS). The concentrations of foam stabilizers were also screened, with the optimal system being 0.6% AOS foaming agent + 0.3% HPAM.

(2)

DFDS-assisted CO₂ huff-n-puff can improve the degree of recovery in 0.2~2 µm pores. Compared with CO₂ huff-n-puff, DFDS-assisted CO₂ huff-n-puff reduced the lower limit of available pores from 0.0476 µm to 0.029 µm and increased the effective working distance from 1.7 cm to 2.05 cm on a 5 cm long core scale, increasing the contribution rate of 0.2–2 µm pores to the total recovery degree by 30.48%. This shows that DFDS can increase the swept volume and, thus, improve the recovery factor of CO₂ huff-n-puff.

(3)

The DFDS showed good oil recovery enhancement capability in the parallel double-pipe core-flooding experiment. The dispersion system can block dominant channels and increase the swept volume of low-permeability cores, acting as a temporary plug and diversion agent. The results showed that the subsequent injection of the system after water flooding increased the low-permeability core’s oil recovery factor by 30.5% and ultimately increased the combined oil recovery factor by 17.4%, indicating a significant enhancement in oil recovery.