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The significant reduction in heavy oil viscosity when mixed with $$\hbox {CO}_{2}$$ is well documented. However, for $$\hbox {CO}_{2}$$ injection to be an efficient method for improving heavy oil recovery, other mechanisms are required to improve the mobility ratio between the $$\hbox {CO}_{2}$$ front and the resident heavy oil. In situ generation of $$\hbox {CO}_{2}$$ -foam can improve $$\hbox {CO}_{2}$$ injection performance by (a) increasing the effective viscosity of $$\hbox {CO}_{2}$$ in the reservoir and (b) increasing the contact area between the heavy oil and injected $$\hbox {CO}_{2}$$ and hence improving $$\hbox {CO}_{2}$$ dissolution rate. However, in situ generation of stable $$\hbox {CO}_{2}$$ -foam capable of travelling from the injection well to the production well is hard to achieve. We have previously published the results of a series of foam stability experiments using alkali and in the presence of heavy crude oil (Farzaneh and Sohrabi 2015). The results showed that stability of $$\hbox {CO}_{2}$$ -foam decreased by addition of NaOH, while it increased by addition of $$\hbox {Na}_{2}\hbox {CO}_{3}$$ . However, the highest increase in $$\hbox {CO}_{2}$$ -foam stability was achieved by adding borate to the surfactant solution. Borate is a mild alkaline with an excellent pH buffering ability. The previous study was performed in a foam column in the absence of a porous medium. In this paper, we present the results of a new series of experiments carried out in a high-pressure glass micromodel to visually investigate the performance of borate–surfactant $$\hbox {CO}_{2}$$ -foam injection in an extra-heavy crude oil in a transparent porous medium. In the first part of the paper, the pore-scale interactions of $$\hbox {CO}_{2}$$ -foam and extra-heavy oil and the mechanisms of oil displacement and hence oil recovery are presented through image analysis of micromodel images. The results show that very high oil recovery was achieved by co-injection of the borate–surfactant solution with $$\hbox {CO}_{2}$$ , due to in-situ formation of stable foam. Dissolution of $$\hbox {CO}_{2}$$ in heavy oil resulted in significant reduction in its viscosity. $$\hbox {CO}_{2}$$ -foam significantly increased the contact area between the oil and $$\hbox {CO}_{2}$$ significantly and thus the efficiency of the process. The synergy effect between the borate and surfactant resulted in (1) alteration of the wettability of the porous medium towards water wet and (2) significant reduction of the oil–water IFT. As a result, a bank of oil-in-water (O/W) emulsion was formed in the porous medium and moved ahead of the $$\hbox {CO}_{2}$$ -foam front. The in-situ generated O/W emulsion has a much lower viscosity than the original oil and plays a major role in the observed additional oil recovery in the range of performed experiments. Borate also made $$\hbox {CO}_{2}$$ -foam more stable by changing the system to non-spreading oil and reducing coalescence of the foam bubbles. The results of these visual experiments suggest that borate can be a useful additive for improving heavy oil recovery in the range of the performed tests, by increasing $$\hbox {CO}_{2}$$ -foam stability and producing O/W emulsions.

We perform co-current spontaneous imbibition ambient-condition experiments in three carbonates with a wide range of permeability under strongly water-wet conditions. We measure water saturation profiles as a function of distance and time in air-filled rocks with no initial water saturation using X-ray CT scanning. We demonstrate that the saturation profiles are functions of distance divided by the square root of time. We also demonstrate that the profiles are consistent with analytical solutions for imbibition in one dimension, and using reasonable estimates of relative permeability and capillary pressure, we can match the experimental results. We discuss how, in combination with conventional measurements of relative permeability (steady-state or using Buckley–Leverett theory in an unsteady-state experiment), the capillary pressure can be determined, or how the relative permeability can be determined from the spontaneous imbibition experiment and the capillary pressure.

An understanding of the size of petroleum secondary migration systems is vital for successful exploration for petroleum reserves. Geochemists have suggested that compositional fractionation of petroleum accompanying the migration process (geochromatography) can potentially be used to infer distances petroleum may have travelled and the ratio of oil in the reservoir to that lost in the carrier. To date, this has been attempted by measuring concentrations and distributions of specific steranes, and aromatic oxygen and nitrogen compounds in reservoired oils which have been proposed to respond to migration rather than to source maturity or other effects. We report here an experiment involving oil migration through an initially water wet siltstone under realistic subsurface carrier bed or reservoir conditions (48 MPa, 70°C) where source facies and maturity effects are eliminated. We show that geochromatography does indeed occur even for initially water-saturated rocks and that the migration fractionations observed for alkylcarbazoles, benzocarbazoles and alkylphenols are very similar to those seen in field data sets. In contrast, sterane based migration parameters show no compositional fractionation under these conditions.