To quantify and rank gas wettability of coal as a key parameter affecting the extent of CO 2 sequestration in coal and CH 4 recovery from coal, we developed a contact angle measuring system based on a captive gas bubble technique. We used this system to study the gas wetting properties of an Australian coal from the Sydney Basin. Gas bubbles were generated and captivated beneath a coal sample within a distilled water-filled (pH 5.7) pressurised cell. Because of the use of distilled water, and the continuous dissolution and shrinkage of the gas bubble in water during measurement, the contact angles measured correspond to a 'transient receding' contact angle. To take into account the mixed-gas nature (CO 2 , CH 4 , and to a lesser extent N 2 ) of coal seam gas in the basin, we evaluated the relative wettability of coal by CH 4 , CO 2 and N 2 gases in the presence of water. Measurements were taken at various pressures of up to 15 MPa for CH 4 and N 2 , and up to 6 MPa for CO 2 at a constant temperature of 22°C. Overall, our results show that CO 2 wets coal more extensively than CH 4 , which in turn wets coal slightly more than N 2 . Moreover, the contact angle reduces as the pressure increases, and becomes < 90°at various pressures depending on the gas type. In other words, all three gases wet coal better than water under sufficiently high pressure.

North Sea tight chalk oil reservoirs are well-known for their submicron pore throat sizes and heterogeneous porosity pattern that includes fractures and microfractures. The host rock of these reservoirs is extremely sensitive and can easily react with the injected fluid, which in turn adversely affects the permeability and thus injectivity. The combined effect of these parameters makes oil production in chalk reservoirs extremely difficult. A novel solvent-based enhanced oil recovery (EOR) method that can address these issues is investigated for the first time in the chalk reservoirs. We thouroughly investigate the oil recovery potential and dominant oil recovery mechanisms by dimethyl ether (DME)−brine injection under conditions pertinent to the North Sea tight chalk oil reservoirs. A series of systematically designed high-pressure and high-temperature flooding experiments were carried out using reservoir core and crude oil. The experimental results revealed the strong oil recovery potential of tertiary DME−brine injection with two different DME contents. Furthermore, both secondary and tertiary DME−brine injection scenarios significantly improved the oil recovery with the better performance in the secondary scenario. The results show that the dominant oil recovery mechanism is rapid and strong oil swelling is caused by the preferential partitioning of DME into the oil phase. During DME−brine injection, no indications of rock mineral dissolution and adverse effects on rock permeability were observed. This is one of the advantages of this method over CO 2 , CO 2 −water alternating gas (WAG), and alkaline injections in which the EOR agent causes calcite dissolution, wormhole formation, and scaling issues in fragile chalk reservoirs.

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Accurate estimation of rock permeability is a major challenge in industrial projects such as oil and gas extraction, geothermal energy production, radioactive waste containment, and CO 2 geosequestration. For many of these projects, the targeted formation exhibits low matrix permeability and the main fluid conduit is the fracture network (Berkowitz, 2002; Neuman, 2005; Sahimi, 2011). To accurately evaluate the hydraulic properties of such geoformations, understanding the behavior of a single rock fracture under in situ conditions is necessary. The permeability of fluids through a single rock fracture is often estimated using the Cubic law-a simplification of the Navier-Stokes (NS) equations based on several key assumptions. These include assuming that the fracture consists of two smooth and parallel plates (Witherspoon et al., 1980). Therefore, the geometry of the flow path can be represented by a single value, the uniform spacing between the two walls. However, no rock fracture is perfectly smooth and, as a result, its aperture field is heterogeneous. A natural way to reduce the heterogeneous aperture field to a single value is to average the fracture aperture distribution. Various averaging methods have been proposed in the literature (

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