In this paper, miscible CO2 simultaneous water-and-gas (CO2-SWAG) injection in the tight Bakken formation was experimentally studied. The effective viscosities of high-salinity water and supercritical CO2 mixtures with twelve different water volume fractions were measured at the actual reservoir conditions by using a capillary viscometer. A total of six coreflood tests with four different miscible CO2-EOR schemes were conducted in the tight reservoir core plugs collected from the Bakken formation (Canada). It was found that the measured effective viscosity of the saline water-CO2 mixture was increased with the water volume fraction and can be reasonably modeled by using the Arrhenius equation. The coreflood test results indicated that the miscible CO2-SWAG injection with an injected water-gas ratio (WGR) of 1:3 in volume had the highest oil recovery factor (RF). The miscible CO2 water-alternating-gas (CO2-WAG) injection achieved a slightly higher oil RF than that of the miscible CO2 secondary flooding, whereas the miscible CO2 tertiary flooding after mature waterflooding had the lowest oil RF. In addition, the WGR showed strong effects on the fluid production trends of the miscible CO2-SWAG injection. A water bank might be formed ahead of the water-CO2 mixture in the miscible CO2-SWAG injection with a higher injected WGR of 1:1 or 3:1. Furthermore, the mobility ratio of the injected fluid(s) to light crude oil was calculated based on the measured steady-state flow rate and pressure gradient in each coreflood test. In comparison with water or CO2 alone, the water-CO2 mixture had a lower mobility in the tight reservoir core plugs. Hence, the highest oil RF of the optimum CO2-SWAG injection with the lowest injected WGR of 1:3 was attributed to a substantially weakened waterblocking effect and a well-controlled water-CO2 mobility.

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