Abstract
AbstractThe pore‐scale imbibition mechanism in fractured water‐wetted reservoirs has been acknowledged as an efficient tool to enhance oil recovery. Most rock in a natural reservoir is mixed‐wetted, but most studies on the pore‐scale imbibition process only focused on the water‐wetted rock. This paper adopts two mixed‐wetted core samples for microspontaneous imbibition experiment, micro‐CT scanning, and nuclear magnetic resonance (NMR) test. The results indicate that the pore radius distribution of the segmented CT images is consistent with that of the NMR test. The microimbibition recovery ratio of core No. 34‐1 and core No. 64 in the spontaneous imbibition experiment are 27.7% and 58.2%, which agrees well with that computed by the micro‐CT scanning image (27.63% and 56.09%). Based on the segmented images, the influences of the Jamin's effect, pore size distribution, and wettability on the microspontaneous imbibition are visualized and quantitatively studied. The Jamin's effect is the important factor that hinders the microimbibition process. The main pore size of imbibition distributes in the range of 1‐25 μm. Furthermore, the pore‐scale spontaneous imbibition process in a single pore with mixed wettability is investigated and analyzed. The relationships among the contact angle, capillary force, recovery ratio, wettability, and the microimbibition recovery are revealed.
Highlights
With the development of the microimaging technology, nuclear magnetic resonance (NMR)[32] and X-ray computed tomography (CT),[33,34,35,36] the distribution of different phases can be obtained at micron scale
The experimental core weight (Figure 9B) which is recorded by the high-precision balance decrease until it reaches equilibrium
By observing the experimental phenomenon (Figure 9A), we find that displaced oil accumulates and eventually forms droplets that are adsorbed on the core surface
Summary
Oil and natural gas still account for 63.5% proportion (Source: IEA1) of the international energy market.[2,3] Imbibition action has been widely considered an efficient method to enhance the oil recovery of low-permeability reservoirs[4,5,6,7,8,9,10] and promote the utilization of the injected fluids, especially for fractured reservoirs.[11,12,13,14] Brownscombe and Dyes[15] observed that the water spontaneously invaded the crude oil in experiments. Moor et al[17] and Graham et al[18] proposed that the main driving force of the imbibition process was the capillary force and gravity. Based on these studies, Iffly et al[19] explored the relationship among the gravity, capillary force, and boundary conditions and indicated that the imbibition process was mainly classified as countercurrent imbibition and cocurrent imbibition. Wang et al[30] simulated the static and dynamic imbibition processes in a regular 2D model to study the effects of the crude oil viscosity, matrix permeability, core size, interfacial tension, and displacement rate on the imbibition. With the development of the microimaging technology, nuclear magnetic resonance (NMR)[32] and X-ray computed tomography (CT),[33,34,35,36] the distribution of different phases can be obtained at micron scale
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