Pore-scale study of counter-current imbibition in strongly water-wet fractured porous media using lattice Boltzmann method

Oil recovery from naturally fractured reservoirs with low permeability rock remains a challenge. To provide a better understanding of spontaneous imbibition, a key oil recovery mechanism in the fractured reservoir rocks, a pore-scale computational study of the water imbibition into an artificially generated dual-permeability porous matrix with a fracture attached on top is conducted using a recently improved lattice Boltzmann color-gradient model. Several factors affecting the dynamic countercurrent imbibition processes and the resulting oil recovery have been analyzed, including the water injection velocity, the geometry configuration of the dual permeability zones, interfacial tension, the viscosity ratio of water to oil phases, and fracture spacing if there are multiple fractures. Depending on the water injection velocity and interfacial tension, three different imbibition regimes have been identified: the squeezing regime, the jetting regime, and the dripping regime, each with a distinctively different expelled oil morphology in the fracture. The geometry configuration of the high and low permeability zones affects the amount of oil that can be recovered by the countercurrent imbibition in a fracture-matrix system through transition of the different regimes. In the squeezing regime, which occurs at low water injection velocity, the build-up squeezing pressure upstream in the fracture enables more water to imbibe into the permeability zone closer to the fracture inlet thus increasing the oil recovery factor. A larger interfacial tension or a lower water-to-oil viscosity ratio is favorable for enhancing oil recovery, and new insights into the effect of the viscosity ratio are provided. Introducing an extra parallel fracture can effectively increase the oil recovery factor, and there is an optimal fracture spacing between the two adjacent horizontal fractures to maximize the oil recovery. These findings can aid the optimal design of water-injecting oil extraction in fractured rocks in reservoirs such as oil shale

Analysis of Oil Recovery by Spontaneous Imbibition of Surfactant Solution

Depending on rock and oil type, lowered interfacial tension (IFT) by the addition of surfactant to brine may contribute to capillary imbibition recovery with the support of gravity drainage in naturally fractured reservoirs (NFR). This paper aims at identifying and analyzing the recovery mechanisms and performing up-scaling exercises for oil recovery from different rock types by the capillary (spontaneous) imbibition of surfactant solution. Laboratory tests were performed using four different rock types that could possibly be the reservoir rock matrix of the NFRs (sandstone, limestone, dolomitic limestone and chalk). The sandstone sample was surface-coated to create a boundary condition causing only counter-current interaction. Wide variety of oils (light and heavy-crude oils, kerosene, and engine oil) was selected as the oleic phase. Different types (non-ionic and anionic) and concentrations of surfactants were used as the aqueous phase as well as the brine as a base case. The samples fully saturated with oil (Swi= 0) were exposed to static capillary imbibition and the recovery was monitored against time. Some experiments on the chalks were repeated using pre-wet samples (Swi > 0) to clarify the changes in the capillary imbibition characteristics of the rock. The changes (positive or negative) in the recovery rate and ultimate recovery compared to the brine imbibition were evaluated for the rock, surfactant and oil types. It was observed, for some rock samples, that the imbibition recovery by surfactant solution was strictly controlled by the concentration of the surfactant. The difference in the recovery rate and ultimate recovery between high and low IFT could be due not only to change in the IFT but also the change in the wettability and adsorption, which might vary with the rock type. This was also analyzed using the shape of the curves that indicates the strength of the capillarity on the recovery and the interaction type, i.e., co- or counter-current. In addition to the above-mentioned qualitative analysis, the recovery curves were evaluated for upscaling. Existing dimensionless scaling groups were tested. The scaling exercise helped identify whether the recovery is driven by gravity or capillary forces and clarify the interaction type, i.e., co-or countercurrent or both. The ultimate recoveries were correlated to the Inverse Bond Number using twenty-five cases covering different combinations of four rock types, four oil and four surfactant samples

Fluid-fluid interaction during miscible and immiscible displacement under ultrasonic waves

This paper aims at identifying and analyzing the influence of high-frequency, high-intensity ultrasonic radiation at the interface between immiscible (different types of oils and aqueous solutions) and miscible (different types of oil and solvent) fluids. An extensive set of Hele-Shaw type experiments were performed for several viscosity ratios, and interfacial tension. Fractal analysis techniques were applied to quantify the degree of fingering and branching. This provided a rough assessment of the degree of perturbation generated at the interface when the capillary forces along with the viscous forces are effective. Miscible Hele-Shaw experiments were also presented to isolate the effect of viscous forces. We found that ultrasound acts to stabilize the interfacial front, and that such effect is most pronounced at low viscosity ratios

BioDiesel as Additive in High Pressure and Temperature Steam Recovery of Heavy Oil and Bitumen

Use of additives to improve the efficiency of thermal heavy oil and bitumen recovery processes has been studied extensively over the decades. Two common types of additives used in thermal applications, mainly steam assisted recovery, are solvents and surfactants. Commercial use of solvents has setbacks due to their high costs and retrieval difficulties. Cost and stability of the surfactants under reservoir operating temperature and pressure are the major concerns. We propose the use of bioDiesel such as fatty acids methyl ester as a surfactant additive reducing heavy oil/bitumen-water interfacial tension in steam assisted recovery processes. Advantages of using bioDiesel as a surfactant additive are that bioDiesel is chemically stable under the operating pressure and temperature of the reservoir, it causes no harm on bitumen fuel quality and on release water chemistry and its use is economically feasible. We conducted a series of steam assisted bitumen recovery experiments to clarify the additional recovery potential and efficiency improvement capacity of bioDiesel. High pressure steam at 1.8 MPa pressure, 205°C was used in these tests at a 900 g/h feed rate. The porous media used was a normal grade oil sands ore obtained from a surface mine operation in Northern Alberta, Canada. Oil sands ore was packed in a basket and placed in a high pressure cell. Bitumen recovery experiments were performed by spraying canola oil fatty acid methyl ester on oil sands ore at a 2 g/kg-bitumen dosage. These tests show that bitumen recovery efficiency increases over 40%. In another series of tests, tall oil fatty acids methyl ester was injected into a high pressure steam line at a 8.3 g-bioDiesel/kg-steam dosage. Because of the solubility of bioDiesel in bitumen, the effect of bioDiesel on bitumen recovery could not be accurately concluded. Vapor pressure measurements performed on canola oil and tall oil derived bioDiesel samples suggest that saturation compositions of bioDiesel in steam at 1.8 MPa pressure and 205°C are at least one order of magnitude higher than the requested bioDiesel dosages. Further tests are planned by reducing bioDiesel dosages to about 0.5 to 1.0 g-bioDiesel/kilogram-steam and by monitoring the solubility of bioDiesel in bitumen