Rock Fabric of Tight Sandstone and Its Influence on Irreducible Water Saturation in Eastern Ordos Basin

Abstract

After flowback, the residual fracturing fluid will reduce the gas seepage space and influence natural gas production, which attracts widespread attention. In this study, the irreducible water saturation was investigated, and its controlling factors were clarified. We target the Upper Paleozoic Taiyuan and Shihezi Formations, which belong to a tight gas reservoir in the eastern Ordos Basin. The main experiments include porosity, permeability, mineral composition, nitrogen adsorption, mercury intrusion porosimetry, nuclear magnetic resonance, and high-speed centrifugation. The specific surface area is very low and varies from 0.95 to 4.03 m 2 /g, and the median pore-throat diameter ranges from 28.6 to 698.6 nm. Through the T 2 cutoff value, the water saturation can be divided into movable water saturation (S mov ) and irreducible water saturation (S irr ). Furthermore, the S irr can be divided into water saturation in large pores controlled by the small throat (S irrl ) and water saturation controlled by the capillary force (S irrc ). In both formations, the S irr has a negative relationship with porosity, permeability, and average pore diameter and exhibits a positive relationship with the specific surface area. The S irrl has a positive relationship with the median pore-throat diameter in Taiyuan Formation, but the S irrl has a weak relationship with the median pore-throat diameter in Shihezi Formation. The S irrc has a negative relationship with porosity, permeability, and average pore diameter and displays a positive relationship with the specific surface area in Taiyuan Formation, but the S irrc has a weak relationship with these parameters in Shihezi Formation. The relationship difference between Taiyuan and Shihezi Formations was mainly caused by the pore structure, demonstrated by the amplitude ratio in three peaks. Based on the above analysis, this study is conducive to understanding the mechanism of water occurrence and its controlling factors.

Minireview of Microscopic CO2 Interactions with Fluids and Minerals in Shale: Advances and Outlook

“…For conventional reservoirs, the minimum miscible pressure (MMP) between CO 2 and oil can be measured by slim-tube, rapid pressure increment, vanishing IFT, rising-bubble apparatus, sonic response, NMR, and computed tomography (CT) methods . For example, NMR is applied to study multiphase fluid transport in porous media by measuring the transverse relaxation time T 2 of hydrogen nuclei in a magnetic field. , Li et al measured the transverse relaxation time of hydrocarbons at different CO 2 injection pressures using NMR. They found that the transverse relaxation time of hydrogen nuclei in hydrocarbons decreases with the CO 2 injection pressure increasing.…”

“…67 For example, NMR is applied to study multiphase fluid transport in porous media by measuring the transverse relaxation time T 2 of hydrogen nuclei in a magnetic field. 68,69 Li et al 70 measured the transverse relaxation time of hydrocarbons at different CO 2 injection pressures using NMR. They found that the transverse relaxation time of hydrogen nuclei in hydrocarbons decreases with the CO 2 injection pressure increasing.…”

Rock Fabric of Lacustrine Shale and Its Influence on Residual Oil Distribution in the Upper Cretaceous Qingshankou Formation, Songliao Basin

“…Some common methods for characterizing the pore structure include scanning electron microscopy (SEM), low-temperature nitrogen adsorption (LT-NA), mercury intrusion porosimetry (MIP), nuclear magnetic resonance (NMR), nano/micro-computed tomography (nano/micro-CT), focused ion beam scanning electron microscopy (FIB-SEM), and small/ultra-small angle neutron scattering (SANS and USANS). SEM is widely used to observe the pore types, shape, connectivity, and distribution, which can distinguish the organic and inorganic pores. − LT-NA can characterize the nanopore, the range of measurement of which usually focuses on mesopores, and this method performs well in the pore structure characterization of unconventional oil/gas reservoirs, especially shale samples. − MIP focuses on the characterization of pore-throat distribution, which can measure the pore-throat size from 3 nm to 1.1 mm, and it was widely used to investigate the pore-throat distribution of conventional and unconventional reservoirs. − NMR is a quick, no-damage, and convenient method to get the pore size distribution, which can measure the pore size larger than 0.4 nm, and is widely used in characterizing the oil/gas reservoirs. − However, it needs relaxivity to convert the T 2 transverse time into the real pore size. Micron CT was widely used to obtain the micron pore/crack distribution, which can distinguish the pore, throat, and crack and can get the coordinate number to reflect the pore connectivity. − Nano CT is used to characterize the pore as small as 50 nm. − FIB-SEM can reconstruct the three dimensions of the sample, and its resolution can be several nanometers, which has a higher precision than nano CT. − The SANS and USANS can obtain the distribution of connected and unconnected pores, but the machine for these experiments are rare. ,− At present, the widely used methods are SEM for pore geometry, LT-NA for nanoscale pore size distribution, MIP for nano–microscale pore-throat size distribution, NMR for from nano-mm scale pore size distribution, and micron CT for pore-crack distribution in three dimensions.…”

Insights into Salt Ion Diffusion Behavior in Imbibed Fluids and the Source of Salt Ions in Clay-Rich Shale from Upper Cretaceous Qingshankou Formation, Songliao Basin

“…Shale oil/gas reservoir usually has low-porosity, low-permeability, and complex pore structure, which belongs to typical unconventional reservoir, and hydraulic fracturing is regarded as a necessary way to effectively exploit its resource. − During hydraulic fracturing, the flowback fluid has a higher salt ion concentration in some shale reservoirs, which is totally different from conventional reservoirs. − This special characteristic can reflect the reservoir information, such as the fracture network complexity. , …”