Shale Oil Potential and Mobility of Low-Maturity Lacustrine Shales: Implications from NMR Analysis in the Bohai Bay Basin

Abstract

A vital factor influencing shale oil exploration in lacustrine shale reservoirs is oil mobility, which is closely associated with the shale pore structure and fluid properties, especially for the low-maturity lacustrine shales in China. In this study, the oil mobility and shale oil potential in the Middle Eocene Shahejie Formation lacustrine shales (MES shales) of the Nanpu Sag in the Bohai Bay Basin are evaluated by using nuclear magnetic resonance (NMR) experiments. The low-maturity MES shales have low porosity with NMR porosity ranging from 4.29–7.41%, and the oil saturation ranges from 9.35–36.09%. The pore types are various including intergranular and dissolution pores and fractures. The pore space size spans the range from nano- to microscale, and they are predominantly mesopres. The pore structure for fluid flow is complex and has good self-similarity with high fractal dimensions. The abundant brittle minerals with a relatively high brittleness index value benefit the fracturing of MES shales. Due to the high viscosity and heavy oil in low-maturity shales, bulk relaxation is proposed to analyze the oil properties in this study. The oil viscosity of MES shales mainly ranges from 2 to 70 cP. The movable oil with a viscosity lower than 10 cP accounts for 53.66% of the total oil-filling pore space. For the black mud-shales dominating MES shales, the thermal maturity influences the porosity, viscosity, free hydrocarbon content, and oil saturation in the rocks. Higher thermal maturity would facilitate pore space development with higher porosity, enhance the free hydrocarbon content and oil saturation, and reduce the oil viscosity to some extent. Moreover, MES shales have geological conditions similar to and better brittleness than those of other shale oil producing areas, which further supports the considerable and promising shale oil potential in this formation, especially for deposits located in deeper positions of the Nanpu Sag. The technologies of in situ conversion process and hydraulic fracturing make the resource potential of shale oil in the Nanpu Sag more attractive.

Storage Capacity and Microdistribution of Pore Water in Gas-Producing Shales: A Collaborative Evaluation by Centrifugation and Nuclear Magnetic Resonance

“…Therefore, it can be qualitatively considered that adsorbed water is primarily distributed in small pores and free water is distributed in large pores. Using the relationship of d = F ρ T 2 , the T 2 value can be converted to the pore size ( d , in nanometers) after determining the ρ value. , In this study, the F value was given to be 4. It was found that the pore size controls the microdistributions of adsorbed and free water (Figure ).…”

“…Generally, there is a corresponding relationship between the T 2 value and pore size, and the larger the T 2 value, the larger the pore size will be. 55 Therefore, it can be qualitatively considered that adsorbed water is primarily distributed in small pores and free water is distributed in large pores. Using the relationship of d = FρT 2 , the T 2 value can be converted to the pore size (d, in nanometers) after determining the ρ value.…”

Pore system classification of Jurassic Da’anzhai Member Lacustrine Shale: Insight from pore fluid distribution

“…For Da’anzhai shale, D 1 is the fractal dimension of small pores, with values ranging from 0.6595 to 0.9372, while D 2 represents the fractal dimension of large pores and microfractures, with values ranging from 2.8859 to 2.9563. In addition to pore structure parameters, pore fractal characteristics and fractal dimension can quantitatively characterize pore complexity and heterogeneity (Chen et al, 2021a), D 2 is significantly higher than D 1 , reflecting that the complex macropore–macropore and pore-fracture configuration relationship may promote the flow of shale oil (Chen et al, 2021a), which further supporting that the configuration of OM-related fractures and brittle mineral-related fractures may be the dominant channels for shale oil flow (Figure 3(l)).…”

Quantitative Characterization for Pore Connectivity, Pore Wettability, and Shale Oil Mobility of Terrestrial Shale With Different Lithofacies—A Case Study of the Jurassic Lianggaoshan Formation in the Southeast Sichuan Basin of the Upper Yangtze Region in Southern China

“…Based on the TOC content, shales can be divided into three groups, namely, organic-rich (TOC content ≥1.5%), organic-containing (TOC content ranges 1~1.5%), and organic-poor shale (TOC content ranges 0~1%) (Zhang et al, 2018b;Zhang et al, 2020c;Xiao et al, 2020;Guo et al, 2021;Shan et al, 2021). In terms of mineral contituents, shales can be classified into four types: calcareous (carbonate minerals ≥50%), grapholith (clay minerals ≥50%), siliceous (siliceous minerals ≥50%), and mixed shale (each mineral accounts for less than 50%) (Li et al, 2019;Huang H. et al, 2020;Xia et al, 2020;Chen et al, 2021). Combining the two classification standards, we can achieve three times four, that is, twelve lithofacies types based on the TOC content and mineral constituents, as shown in Tables 3, 4.…”