Three-phase flow displacement dynamics and Haines jumps in a hydrophobic porous medium

Abstract

We use synchrotron X-ray micro-tomography to investigate the displacement dynamics during three-phase-oil, water and gas-flow in a hydrophobic porous medium. We observe a distinct gas invasion pattern, where gas progresses through the pore space in the form of disconnected clusters mediated by double and multiple displacement events. Gas advances in a process we name three-phase Haines jumps, during which gas re-arranges its configuration in the pore space, retracting from some regions to enable the rapid filling of multiple pores. The gas retraction leads to a permanent disconnection of gas ganglia, which do not reconnect as gas injection proceeds. We observe, in situ, the direct displacement of oil and water by gas as well as gas-oil-water double displacement. The use of local in situ measurements and an energy balance approach to determine fluid-fluid contact angles alongside the quantification of capillary pressures and pore occupancy indicate that the wettability order is oil-gas-water from most to least wetting. Furthermore, quantifying the evolution of Minkowski functionals implied well-connected oil and water, while the gas connectivity decreased as gas was broken up into discrete clusters during injection. This work can be used to design CO₂ storage, improved oil recovery and microfluidic devices.

Keywords: enhanced oil recovery; gas injection; porous media; synchrotron imaging; three-phase flow; wettability.

Figure 1.

The flooding and imaging apparatus used to conduct the three-phase flow experiment in the oil-wet reservoir rock at 8 MPa and 60°C. The rock was inserted in a flow cell placed in front of the synchrotron light source to image the movement of water, oil and gas in the pore space. The three fluid phases were injected at a very low flow rate using syringe pumps to capture the pore-scale displacement dynamics. (Online version in colour.)

Figure 2.

Filtered raw two-dimensional pore-scale images of a cross-section of the rock acquired after: (a) oil injection (OI); (b) water flooding (WF); and (c) gas injection (GI), with a voxel size of 3.5 µm. In (a), rock is the light phase and oil is the dark phase. In (b) and (c), the order from darkest to brightest phase is oil–water–rock and gas–oil–water–rock, respectively.

Figure 3.

Three-dimensional images showing the location of the dynamic scans (1280 × 1280 × 1080 voxels) relative to the static scans of the whole sample (1280 × 1280 × 3940 voxels). The spatial resolution of the images is 3.5 µm. The macro-porosities (ϕ_macro) of the static and dynamic scans are 16% and 12%, respectively.

Figure 4.

Probability density function of the in situ measured distribution of fluid–fluid contact angles at the end of (a) waterflooding (WF) and (b) gas injection (GI). The contact angles were measured using the automated method developed by AlRatrout et al. [69]. The angle was characterized through the denser phase: water in the case of oil and water and gas and water, and oil in the case of gas and oil. (Online version in colour.)

Figure 5.

Two-dimensional raw pore-scale images, with a voxel size of 3.5 µm, showing (a) the contact angles formed between gas and water when the fluids are at rest and (b) the gas–water contact angles during the displacement of water by gas. (Online version in colour.)

Figure 6.

Normalized bar charts showing the pore occupancy in the oil-wet rock, characterized on static images of the whole sample, after (a) water flooding (WF) and (b) gas injection (GI). (Online version in colour.)

Figure 7.

A three-dimensional volume rendering of the fluid configurations in the section of the rock imaged dynamically during (a) oil injection, (b) water flooding and (c) gas injection. Oil is shown in red, water in blue and gas in green. (Online version in colour.)

Figure 8.

Three-dimensional maps of the gas connectivity in the pore space during GI shown at different time steps. Each disconnected gas cluster is labelled with a different colour. The black arrow points towards the direction of flow. S_g is the gas saturation in the imaged section, while t is time. (Online version in colour.)

Figure 9.

Three-dimensional images of direct and multiple displacement events occurring at different time steps during gas injection in the oil-wet rock. Displacement of oil by gas is shown in green, water by gas in blue and water by oil in red. The black arrow points towards the direction of flow. S_g is the gas saturation in the imaged section, while t is time. (Online version in colour.)

Figure 10.

Three-dimensional images of the gas phase at different time steps illustrating the occurrence of a three-phase Haines jump during the displacement of oil by gas in the oil-wet pore space. (a) and (b) show the difference in gas saturation before and after the three-phase Haines jump. (c) The specific interfacial area between gas and the rest of the phases (water, oil and solid) is lower in the high-pressure region, marked by the dashed line, after the three-phase Haines jump owing to gas retraction. The black arrow points towards the direction of flow. (Online version in colour.)

Figure 11.

Three-dimensional images of the gas phase at different time steps illustrating the occurrence of a three-phase Haines jump during the displacement of water by gas in the oil-wet pore space. (a) and (b) show the difference in gas saturation before and after the three-phase Haines jump. (c) The specific interfacial area between gas and the rest of the phases (water, oil and solid) is lower in the high-pressure region, marked by the dashed line, after the three-phase Haines jump owing to gas retraction. The black arrow points towards the direction of flow. (Online version in colour.)

Figure 12.

The evolution of Minkowski functionals—(a) saturation, (b) fluid–fluid specific interfacial area, (c) fluid–solid specific interfacial area and (d) capillary pressure—during gas injection in the dynamically imaged section of the oil-wet rock. The vertical dashed line represents the time of gas breakthrough in the imaged field of view. Error bars indicate uncertainty in the measurement. (Online version in colour.)

Figure 13.

Probability distributions of the two principal curvatures, κ₁ and κ₂, at the (a–c) gas–oil interface, (d–f) oil–water interface and (g–i) gas–water interface plotted at different time steps during gas injection in the oil-wet porous medium. κ₁ is defined to be the larger curvature. (Online version in colour.)