2.4.1. Optimization of In Situ Emulsification System Strength and Evaluation of Oil Recovery Effects
The oil displacement experiments were conducted using cores with permeabilities of 109 × 10
-3μm
-2 and 12 × 10
-3μm
-2, respectively. The adaptability of different surfactant systems to cores with varying permeabilities was analyzed by evaluating the magnitude of incremental oil recovery. In the core with a permeability of 109 × 10
-3μm
-2, as depicted in
Figure 9a, the injection of all three emulsifiers resulted in a rise in pressure during injection, indicating in-situ emulsification within the core. The extent of pressure increase reflects the emulsification plugging capability, with the 3:1 combination system of branched-chain sugar surfactant and nonionic surfactant exhibiting a higher-pressure increase, indicating a stronger emulsification plugging and spreading ability, leading to a higher incremental oil recovery.
In the core with a permeability of 12 × 10
-3μm
-2, as illustrated in
Figure 9b, all three emulsifiers caused pressure rise during injection, suggesting in-situ emulsification within the core. However, the subsequent water flooding pressure continued to increase with the 3:1 combination system of branched-chain sugar surfactant and nonionic surfactant, and the 3:2 combination system, indicating a mismatch between the system solution and the core. In contrast, the 1:1 combination system of branched-chain sugar surfactant and nonionic surfactant demonstrated moderate emulsification plugging capability at this permeability, leading to an improved incremental oil recovery.
The oil displacement experimental data further supported these observations. In the core with a permeability of 109 × 10 -3μm -2, the 3:1 combination system of branched-chain sugar surfactant and nonionic surfactant exhibited the best oil displacement effect, with a chemical flooding recovery rate of 17.33%, higher than the other two combination systems. Conversely, in the core with a permeability of 12 × 10 -3μm -2, the 1:1 combination system of branched-chain sugar surfactant and nonionic surfactant demonstrated the optimal performance, with a chemical flooding recovery rate of 8.87%, surpassing the other two combination systems.
Therefore, from the comprehensive analysis presented in
Table 1, it can be concluded that different compound systems are required to achieve optimal oil displacement effects in cores with varying permeabilities. Specifically, the branched-chain betaine and non-ionic surfactant in a 3:1 compound system are suitable for cores with a permeability of 109 × 10
-3μm
-2, whereas the 1:1 compound system is more suitable for cores with a permeability of 12 × 10
-3μm
-2. This demonstrates the applicability of different compound systems to cores with different permeabilities, indicating that systems with higher emulsion stability are more suitable for cores with higher permeabilities, while those with lower emulsion stability are more suitable for cores with lower permeabilities.
2.4.2. Evaluation of Plug Combination Effects in Heterogeneous Emulsification Systems
Based on the heterogeneity of the target reservoir formation, representative sandstone core samples with permeabilities of 180 × 10 -3μm -2 and 18 × 10 -3μm -2 were selected to form a dual-tube parallel model for conducting oil displacement experiments using different single stability systems and various combination stability systems. Pressure and oil recovery were recorded, and the adequacy of different emulsification systems for plug size was determined by increasing the amplitude of oil recovery.
Oil displacement experiments were conducted using the sandstone cores with permeabilities of 180 × 10
-3μm
-2 and 18 × 10
-3μm
-2, as shown in
Figure 10. Only 0.5PV of a 3:1 combination system of branched cyclodextrin and non-ionic surfactant was injected. During chemical flooding, the pressure continued to rise, followed by a rapid decline during subsequent water flooding. The low permeability flow rate increased continuously at the onset of chemical flooding, reaching 0.11 and then began decreasing at 1.53PV, eventually tapering to 0 by 1.71PV. This decrease was attributed to the system's solution sealing the high-permeability layer, causing severe blockage in the low-permeability layer, followed by fluid diversion towards the high-permeability layer, resulting in relatively low oil recovery from the low-permeability zone.
A 3:1 combination system of branched cyclodextrin and non-ionic surfactant was first injected at 0.17 PV, followed by a 1:1 combination system at 0.33 PV. During chemical flooding, the pressure initially increased rapidly, slowed down at 1.3 PV, and then declined during subsequent water flooding, reaching equilibrium as the PV increased. The low permeability flow rate increased to 0.08 initially during chemical flooding, began decreasing at 1.59 PV, and eventually tapered to 0 by 1.99 PV. This indicated that the initial 0.17 PV injection of the 3:1 combination system played a limited sealing role in the high-permeability zone, while the subsequent injection of the 1:1 combination system mainly entered the high-permeability zone, with inadequate coverage of the low-permeability zone.
A reverse injection sequence was employed, with a 3:1 combination system of branched cyclodextrin and non-ionic surfactant injected first at 0.33 PV, followed by a 1:1 combination system at 0.17 PV. Pressure increased rapidly at the onset of chemical flooding, decreased quickly around 1.59 PV, and then gradually declined during subsequent water flooding, stabilizing around 2.4 PV. The low permeability flow rate increased rapidly to 0.16 initially during chemical flooding, began decreasing at 1.7 PV, and tapered to 0.01 by 2.4 PV. This suggested that the initial injection of the 3:1 combination system provided some blocking effect in the high-permeability zone, while the subsequent injection of the 1:1 combination system mainly entered the low-permeability zone, resulting in effective in-situ emulsification oil displacement effects in both high and low permeability cores.
Oil displacement experiments using cores with permeabilities of 20 × 10
-3μm
-2 and 2 × 10
-3μm
-2 were conducted in parallel, as shown in
Figure 11. Only 0.5 PV of a 1:1 combination system of branched cyclodextrin and non-ionic surfactant was injected. Pressure increased slowly at the start of chemical flooding, began to decline gradually around 1.69 PV, and continued to decrease during subsequent water flooding, stabilizing around 2.37 PV. The low permeability flow rate increased continuously at the start of chemical flooding, peaked at 0.05, then began to decline, reaching 0.01 by 2.2 PV. This indicated that the 1:1 combination system of branched cyclodextrin and non-ionic surfactant entered the high permeability core and underwent in-situ emulsification with residual oil, resulting in a continuous increase in the low permeability flow rate and expansion of the affected volume.
A 3:2 combination system of branched cyclodextrin and non-ionic surfactant was injected first at 0.17 PV, followed by a 1:1 combination system at 0.33 PV. Pressure increased rapidly at the start of chemical flooding, then decreased quickly around 1.46 PV, slowed down at 1.59 PV, and gradually declined during subsequent water flooding, stabilizing around 1.99 PV. The low permeability flow rate increased continuously at the start of chemical flooding, peaked at 0.07, then began to decline slowly, reaching 0.01 by 2.16 PV. This indicated that the initial injection of the 3:2 combination system played a blocking role in the high-permeability zone but caused damage and retention in the low-permeability core. Subsequent injection of the 1:1 combination system mainly entered the high-permeability core, with limited expansion effects.
A reverse injection sequence was employed, with a 3:2 combination system of branched cyclodextrin and non-ionic surfactant injected first at 0.33 PV, followed by a 1:1 combination system at 0.17 PV. Pressure increased rapidly at the start of chemical flooding, then decreased around 1.55 PV, and gradually declined during subsequent water flooding, stabilizing around 2.31 PV. The low permeability flow rate increased initially during chemical flooding, peaked at 0.05, then began to decline slowly, reaching 0 by 2.31 PV. This indicated that the initial injection of the 3:2 combination system effectively blocked both high and low permeability cores, making subsequent system injection difficult to move effectively into the core depths.
The oil displacement experiment data, as shown in
Table 2, indicated that the best plug combination to increase oil recovery was achieved by sequentially injecting a 3:1 combination system of branched cyclodextrin and non-ionic surfactant at 0.33 PV, followed by a 1:1 combination system at 0.17 PV, into the core with a permeability of 180 × 10
-3μm
-2 + 18 × 10
-3μm
-2, resulting in the highest oil recovery of 82.12% in the high permeability zone and 22.73% in the low permeability zone. For the core with a permeability of 20 × 10
-3μm
-2 + 2 × 10
-3μm
-2, injecting only 0.5 PV of a 1:1 combination system of branched cyclodextrin and non-ionic surfactant yielded the best oil recovery results, with 58.33% in the high permeability zone and 13.71% in the low permeability zone.