Analysis of nano-scale transport processes between pores in shale and fracture systems is essential for predicting hydrocarbon production. Accurate estimation of total hydrocarbon storage is important in reservoir management, economically and financially. Also improving EOR in unconventional reservoir requires comprehensive knowledge of the rock characteristics, such as pore size distribution. In this work we presented the results of digital rock analysis (DRA) for high-resolution micro-CT and FIB-SEM images of Bakken core plugs. The workflow includes a fundamental digital rock physics procedure to estimate porosity and absolute permeability and compare the pore-scale heterogeneities in different core samples. From the analyses that is evident that permeability can vary in even short distances of sampling in an unconventional play, such as the Bakken Fm. Therefore, assuming an average permeability for such formation may not be a promising assumption, rather upscaling techniques are recommended. Better understanding of heterogeneity in shale plays can help us to design optimal EOR operations for improved recovery.

1. Introduction

Nowadays, possessing massive oil reserves with great potential of oil production is well known for unconventional reservoirs, which have a huge effect on the future of the petroleum industry. In the United States, reservoirs such as the Barnett, Woodford, Haynesville, Fayetteville, Marcellus, and Eagle Ford Shale are examples of these types of reservoirs (Chen et al, 2013). However, the complex characteristics of these reservoirs (i.e. ultra-low permeability and heterogeneity) cause the ultimate recovery factor to remain low (less than 10%). Numerous researchers have shown that nano/micro-scale heterogeneity has noticeable impact on larger scale properties, physical phenomena, and hydrocarbon recovery assessment. Therefore, it is essential to determine the microstructure information (Farajzadeh et al., 2011). In specific cases, one of the prevalent methods for enhancing oil recovery lies within CO2 injection and huff and puff. These methods have gained the attention of researchers and have showed great recovery enhancement during both experimental and field results. This mainly happens due to low MMP (Minimum Miscibility Pressure) with oil, and small molecule size when compared to other common injected gases. Hence, obtaining internal parameters such as porosity, specific surface area, and pore size distribution is necessary to analyze the nano-scale transport processes between pores in shale and fracture systems (Chen et al., 2013). Consequently, accurate estimation of total hydrocarbon storage will improve reservoir management, economically and financially. Among all input parameters to reservoir simulation, absolute permeability is counted as an essential one to forecast hydrocarbon production. This gets even bolder when dealing with heterogeneous reservoirs, where permeability values reach nano-Darcy.

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