Investigation of the permeability of carbonate rocks is essential and challenging due to the heterogeneity of carbonates at all scales. At the micro-scale, pore geometry, pore size distribution, and pore connectivity are important factors controlling permeability. This study focuses on the influence of pore size distribution and pore structure on permeability to better understand the fluid flow in carbonate rocks.
In this paper, we use micro-computer tomography (micro-CT) to capture the microscopic heterogeneity in the pore structure. Firstly, we collected seven 1 x 6 inch carbonate rock samples including Indiana Limestone, Desert Rose, and Travertine with various porosities and permeabilities. The porosity was measured gravimetrically, and permeability was measured with core plug flooding experiments. Cubic centimeter size core samples were scanned with enhanced micro-CT imaging with the resolution of 6-8 μm/voxel, then scanned 2D images were processed with image processing software to distinguish the pore system from the matrix. The pore size distribution for each rock sample was determined by fitting a statistical function based on the binarized images. We defined a concept of equivalent pore radius to characterize the pore system, which effectively filters out the non-contributing small pores and preserves the pores actually contributing to fluid flow. The relationship between the equivalent pore radius of each rock and permeability was investigated. Based on the 2D image stack, we also constructed the 3D pore network to observe the pore structure, quantify connectivity and specific surface ratio to study their influence on permeability.
We found that laboratory measured permeability from core plugs was strongly correlated to the equivalent pore radius calculated from micro-CT scanned images among the investigated carbonate rock samples. The semilogarithmic correlation between permeability and effective pore radius fit the measured permeability data very well over a permeability range of more than two orders of magnitude. The findings of pore-scale pore structure and pore size distribution in this study are helpful for carbonate rock analysis, and the proposed new correlation between equivalent pore radius and permeability is practical for permeability estimation for a wide range of carbonate rocks.
Yang, Shu (China University of Petroleum) | Dong, Pingchuan (China University of Petroleum) | Cai, Zhenzhong (Tarim Oilfield Company Ltd. CNPC) | Ji, Xiaoyu (Renmin University of China) | Lei, Gang (China University of Petroleum) | Wu, Zisen (China University of Petroleum) | Dong, Ruitao (China University of Petroleum) | Zhang, Zhenghong (Tarim Oilfield Company Ltd. CNPC)
This paper analyzes pore-throat geometry characterization using 2D micro-CT and field scanning rock images of Tarim basin sandstone and presents the oil droplet flow model in real pore-throat network based on Navier-Stokes equations and Finite Element discretization to study remaining oil location at micro and nano scale.
Using the Gray-Level Histograms and mathematical morphology, the real pore-throat geometry network characterization is extracted from images as logic matrixes using our imaging progressing program. The porosity, pore-throat radius and representative elementary unit are calculated to the simulation model. According to the result of pore-throat network at micro and nano scale, the pore-throat hybrid grid model and the two-phase simulation are built up. It includes the continuous water phase and the single oil droplet. Furthermore, the study takes the additional resistance caused by capillary pressure, shear stress caused by boundary effects and droplets breakup model into consideration. The simulation is verified by an accuracy of approximately 20% with the experiment results. This paper is aim to predict the remaining oil location under different pressure differences and oil drop radiuses, and study the influence of these factors by the analysis of calculated oil droplet concentration and fluid streamline of the simulation.
The paper reveals the vortex flow exists in the pore-throat network and the remaining oil is likely to gather in the high tortuosity and strong vortex regions, especially at the edge of pores connected to the outlet branch throats, dead pores and the center of pores. In addition, the paper shows as the oil droplet size and pressure difference increase, the displacement efficiency decrease and the remaining oil concentration change. Overall this paper provides a fast methodology for pore-throat geometry characterization quantitative study and a pore-scale oil droplet flow model to predict remaining oil location under different conditions.