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Pore-scale modeling is essential in understanding and predicting flow and transport properties of rocks. Generally, pore-scale modeling is dependent on imaging technologies such as Micro Computed Tomography (micro-CT), which provides visual confirmation into the pore microstructures of rocks at a representative scale. However, this technique is limited in the ability to provide high resolution images showing the pore-throats connecting pore bodies. Pore scale simulations of flow and transport properties of rocks are generally done on a single 3D pore microstructure image. As such, the simulated properties are only representative of the simulated pore-scale rock volume. These are the technological and computational limitations which we address here by using a stochastic pore-scale simulation approach. This approach consists of constructing hundreds of 3D pore microstructures of the same pore size distribution and overall porosity but different pore connectivity. The construction of the 3D pore microstructures incorporates the use of Mercury Injection Capillary Pressure (MICP) data to account for pore throat size distribution, and micro-CT images to account for pore body size distribution. The approach requires a small micro-CT image volume (7–19 mm3) to reveal key pore microstructural features that control flow and transport properties of highly heterogeneous rocks at the core-scale. Four carbonate rock samples were used to test the proposed approach. Permeability calculations from the introduced approach were validated by comparing laboratory measured permeability of rock cores and permeability estimated using five well-known core-scale empirical model equations. The results show that accounting for the stochastic connectivity of pores results in a probabilistic distribution of flow properties which can be used to upscale pore-scale simulated flow properties to the core-scale. The use of the introduced stochastic pore-scale simulation approach is more beneficial when there is a higher degree of heterogeneity in pore size distribution. This is shown to be the case with permeability and hydraulic tortuosity which are key controls of flow and transport processes in rocks.
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Pressure- and Time-Dependence of Fluid Flow in Maquoketa Shale
Shales are abundant in the earth’s subsurface and play a critical role as natural barriers in geo-environmental applications, such as geologic carbon dioxide storage and nuclear waste disposal. Assessing shale permeability is essential for evaluating their sealing capacity. Traditional pore fluid pressure dissipation experiments often provide only an order of magnitude estimation of permeability if specimen geometry and boundary conditions are not properly considered. In this study, a steady-state method is employed to measure the permeability of Maquoketa Shale from the Illinois Basin and identify the influencing factors. Experimental results indicate an exponential decrease in permeability with increasing effective mean stress, with values on the order of 10−21 m2 (nano Darcy), comparable to other claystones with nanoscale pore structures. Over the span of 2 weeks, the average permeability decreases by half due to time-dependent deformation. Plotting stress-dependent permeability vs. porosity reveals a power law relationship, with a sensitivity exponent of 16 for the tested shale. This high exponent value, typical for tight rock, indicates that even small changes in porosity can significantly affect permeability compared to porous geomaterials. It appears that the time-dependent evolution of permeability can be predicted based on the knowledge of poroviscoelastic parameters and the model that considers coupling between the hydraulic and mechanical behavior of rock.
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- Award ID(s):
- 2239630
- PAR ID:
- 10660994
- Publisher / Repository:
- American Society of Civil Engineers
- Date Published:
- Page Range / eLocation ID:
- 200 to 209
- Format(s):
- Medium: X
- Sponsoring Org:
- National Science Foundation
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- Free Publicly Accessible Full Text
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Accepted Manuscript
- Conference Paper:
- https://doi.org/10.1061/9780784486009.021
