Abstract
The flow characteristics of dissolved gas driven processes in some heavy oil reservoirs, such as low gas–oil ratio and higher oil recovery rate than expected, are quite different from conventional oil production processes. Foamy oil is considered one of the main reasons behind such a production phenomenon. In this paper, the factors affecting the performance of foamy oil recovery were experimentally investigated in a sandpack medium with the assistance of computed tomography (CT) technology to help further the understanding of the mechanism. Five different experiments were applied and the results showed that (1) the linear pressure drop production model had a similar oil recovery to that of the step-down mode; (2) increasing the depletion rate could be more favorable to the oil recovery rate; (3) under a constant gas–oil ratio, raising the temperature had little impact on oil recovery, but showed obvious impact on the production curve; and (4) with higher permeability, there were more residual oil at the end of the displacement process. Lastly, a dry gas huff and puff experiment was conducted and the decreased oil saturation was observed in the inlet section, while no obvious effect was remarked in the outlet region of the medium.
Highlights
In recent years, the employment of dissolved gas on driving heavy oil has achieved notable development results
Discussed the capillary effect of the temperature gradient of a soluble gas driven heavy oil system; the results showed that the relative permeability curve and the gas–oil interface location were strongly influenced by the temperature change
To scrutinize the mechanism of the foamy oil flow characteristics and supply valuable instruction for heavy oil recovery field practices, this paper reports extensive studies on various influential factors on foamy oil flow, including the pressure drop rate, the formation temperature and the sandpack permeability
Summary
The employment of dissolved gas on driving heavy oil has achieved notable development results. Due to the characteristics of high crude oil viscosity, slow gas diffusion rate, and large pressure gradient, the coalescence gas is not rapidly produced as a continuous gas phase, but it is dispersed in crude oil in the form of small bubbles that move with the crude oil. With all these descriptions, this gas–oil two-phase non-Darcy flow system is called the foamy oil flow. Sarma and Maini [2] first applied the term foamy oil and defined it as the dispersed gas phase in the continuous oil phase. According to the observation of the glass micromodel experiment, Bora [3]
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