Tests Investigate Recovery Mechanisms of Steam Injection in Carbonate Reservoir
- Adam Wilson (JPT Editorial Manager)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- March 2013
- Document Type
- Journal Paper
- 135 - 138
- 2013. Society of Petroleum Engineers
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- 108 since 2007
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This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 153812, "Investigation of Recovery Mechanism of Steam Injection in Heavy-Oil Carbonate Reservoir and Mineral Dissolution," by Guo-Qing Tang, SPE, Art Inouye, Vincent Lee, SPE, Dustin Lowry, and Wei Wei, Chevron, prepared for the 2012 SPE Western Regional Meeting, Bakersfield, California, 19-23 March. The paper has not been peer reviewed.
Steam injection in carbonate heavy-oil reservoirs is a complex process. The main challenge is that the injected steam breaks through from a fracture network, resulting in poor sweep efficiency. A large amount of oil remains behind the steam front. In addition, severe mineral dissolution (or precipitation) because of steam/brine/rock interaction at high temperatures has a significant effect on steam injectivity and recovery mechanisms. An extensive laboratory study focused on understanding the recovery mechanism and relevant mineral dissolution.
Ten reservoir cores and 14°API crude oil were used for this study. Imbibition, steamflooding, and pressure blowdown tests were conducted. The results show that the recovery mechanism of steam injection in the target carbonate reservoir is composed of imbibition, viscosity reduction, in-situ steam generation induced by pressure blowdown, and oil expansion mechanisms. As the rock is heated to near 400°F, imbibition becomes the dominant recovery mechanism. The increased imbibition recovery is strongly dependent on mineral dissolution at a high temperature, which results in wettability alteration to-ward strong water-wetness. Because of microfractures, steamdrive is less efficient compared with imbibition. In-situ steam generation still can increase oil recovery by an additional 17–32% of original oil in place (OOIP) following steamflood displacement at residual oil saturation.
Significant mineral dissolution is observed with high-resolution computed tomography (CT) scanning and effluent geochemical analysis. CT-image analysis shows that the size of vugs is increased 2 to 5 times by mineral dissolution. Mineral dissolution does not increase the effective permeability because these vugs are mainly connected by microfractures, where mineral dissolution effects are negligible. In fact, permeability is reduced by fines migration resulting from mineral dissolution.
Carbonate reservoir rock samples with permeability ranging from 121 to 317 md and porosity ranging from 40.1 to 50.9% were selected for this study. CT scans showed that the selected rock samples have many vugs, with a size ranging from 0.11 to 3 mm. These vugs are connected with very tiny pores and microfractures with sizes of approximately 20 µm.
An in-house high-temperature (up to 400°F) and -pressure (up to 1,000 psi) experimental system that is capable of running either free imbibition (counter-current) or forced imbibition (cocurrent) was used for all experiments.
Different experiments, such as free imbibition, forced imbibition, thermal expansion, steamflooding, and pressure blowdown, were performed. Fig. 1 shows the experimental design.
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