Macro-, meso-, micro-pore systems combined with clay content are critical for fluid flow behavior in tight sandstone formations. This study investigates the impact of clay mineralogy on pore systems in tight rocks. Three outcrop samples were selected based on their comparative petrophysical parameters (Bandera, Kentucky, and Scioto). Our experiments carried out to study the impact of clay content on micro-pore systems in tight sandstone reservoirs involve the following techniques: Routine core analysis (RCA), to estimate the main petrophysical parameters such as porosity and permeability, X-ray diffraction (XRD), and scanning electron microscopy (SEM) to assess mineralogy and elemental composition, Mercury Injection Capillary Pressure (MICP), Nuclear Magnetic Resonance (NMR), and Micro-Computed Tomography (Micro-CT) to analyze pore size distributions. Clay structure results show the presence of booklets of kaolinite and platelets to filamentous shapes of illite. The Scioto sample exhibits a micro-pore system with an average pore body size of 12.6±0.6 μm and an average pore throat size of 0.25±0.19 μm. In Bandera and Kentucky samples illite shows pore-bridging clay filling with an average mineral size of around 0.25±0.03 μm, which reduces the micro-pore throat system sizes. In addition, pore-filling kaolinite minerals with a diameter of 5.1±0.21 μm, also reduce the micro-pore body sizes. This study qualifies and quantifies the relationship of clay content with primary petrophysical properties of three tight sandstones. The results help to advance procedures for planning oil recovery and CO₂ sequestration in tight sandstone reservoirs.

Carbon dioxide (CO₂) injection has been widely used in conventional reservoirs for enhanced oil recovery and CO₂ sequestration. Nevertheless, the effectiveness of CO₂ injection in tight reservoirs is limited due to diagenetic processes that impact displacement efficiency. This research work assesses the performance of CO₂ injection in tight reservoirs and evaluates oil mobilization and fluid distribution within the rock pore systems. A set of experiments, including routine core analysis, X-ray diffraction (XRD), scanning electron microscopy (SEM), and mercury injection capillary pressure (MICP), was performed on Scioto sandstone. Three core-flooding runs were conducted to evaluate oil recovery of different injection schemes, including tertiary miscible CO₂ injection, secondary immiscible CO₂ injection, and secondary miscible CO₂ injection. A nuclear magnetic resonance (NMR) spectrometer was utilized to evaluate the fluid distribution in pre- and postflooding schemes. Results show that secondary miscible CO₂ injection provided the highest displacement efficiency (E_d) of 88%, with oil mobilized from both micro- and macropore systems, leading to the highest oil recovery of 93% original oil in place (OOIP). Tertiary miscible CO₂ injection had E_d of 67%, providing an ultimate oil recovery of 79% OOIP mostly from the macropore system. Limited contribution of micropores during the tertiary miscible CO₂ injection is attributed to the increased water content as a result of previously conducted secondary water flooding. Secondary immiscible CO₂ injection showed the least oil recovery among the injection schemes of 68% OOIP, which is attributed to the unstable displacement, as indicated by E_d of 52%. The efficiency of pore fluid displacement was determined through NMR analyses, and the findings are in line with the displacement efficiency values obtained from core-flood experiments, with a strong positive correlation. This finding is a promising strategy for determining a suitable CO₂ injection scheme in tight rocks for oil recovery and CO₂ storage.

CO₂ flow in porous media is vital for both enhanced oil recovery and underground carbon storage. For improving CO₂ mobility control and thus improved reservoir sweep efficiency, Water-Alternating-Gas (WAG) injection has often been applied. The effectiveness of WAG diminishes, however, due to the presence of micro-scale reservoir heterogeneity which results in an early breakthrough of gas. We propose Polymer-assisted WAG (PA-WAG) as an alternative method to reduce gas mobility, while also reducing the mobility of the aqueous phase, and consequently improving the performance of WAG. In this method, high molecular weight water-soluble polymers are added to the water slug. The goal of this work was to investigate the feasibility of PA-WAG and study the transport processes in porous media. An ATBS-based polymer (SAV 10 XV) was chosen as polymer and CO₂ at immiscible conditions as gas. The objective of the experiments was to compare the performance of CO₂, WAG, and PA-WAG injection schemes by conducting a series of X-ray computed tomography (CT)-aided core-flood experiments in Bentheimer cores. Core-flood results clearly demonstrated the beneficial effects of PA-WAG over WAG and continuous CO₂ injection. Continuous injection of CO₂ led to the recovery factor (RF) of only 39.0 ± 0.5% of the original oil in place (OOIP). In-situ visualization of CO₂ displacement showed strong gravity segregation and viscous fingering because of the contrast in the viscosities and densities of CO₂ and oil. The injection of WAG almost doubled the oil recovery (i.e., RF=76.0 ± 0.5%); however, the water and gas breakthroughs still occurred in the early stage of the injection (0.22 PV for water and 0.27 PV for CO₂). The addition of the polymer to the aqueous phase delayed both the water and CO₂ breakthrough (0.51 PV for water and 0.35 PV for CO₂). This resulted in an additional 10% in the recovery factor. Using a single injection method, polymer adsorption was found to be 79.0 ± 0.5 μg polymer/g rock. The polymer adsorption can reduce the micro-scale permeability and as a result, mitigates the gas channeling. This in turn leads to the delay in CO₂ breakthrough during PA-WAG injection as was evident from in-situ visualization. This experimental study demonstrated a positive response of PA-WAG compared to WAG and paves the way for its implementation in field applications.

The novel enhanced oil recovery (EOR) technique combining the reduction of oil/water (o/w) interfacial tensions (IFT) to ultralow values and generation of a foam drive for mobility control is known as foam-assisted chemical flooding (FACF). We present a well-controlled laboratory study on the feasibility of FACF at reservoir conditions. Two specially selected chemical surfactants were screened on their stability in sea water at 90 °C. The ability of both surfactants to generate stable foam in bulk was studied in the presence and absence of crude oil. It led to the composition of the foam drive formulation for drive mobility control. Phase behavior scan studies, for the two crude oil/surfactant/brine systems, yielded the design of the chemical slug capable of mobilizing residual oil by drastically lowering the o/w IFT. Core-flood experiments were performed in Bentheimer sandstones previously brought to a residual oil to waterflood of 0.33 ± 0.02. A surfactant slug at under-optimum (o/w IFT of 10^-2 mN/m) or optimum (o/w IFT of 10^-3 mN/m) salinity was injected for mobilizing residual oil. It resulted in the formation of an unstable oil bank because of dominant gravitational forces at both salinities. Next, a foam drive was generated either in situ, by co-injecting nitrogen gas and surfactant solution, or pregenerated ex situ and then injected to displace the oil bank. We found that (i) the presence of the crude oil used in this work has a detrimental effect on foam stability in bulk and foam strength in Bentheimer sandstones, (ii) optimum salinity FACF was able to increase the ultimate oil recovery with 5% of the oil in place (OIP) after water flooding compared with under-optimum FACF, and (iii) injection of pregenerated drive foam increased its ultimate oil recovery by 13% of the OIP after water flooding compared to in situ drive foam generation at optimum salinity.

Alkaline/surfactant/foam (ASF) flooding is a novel enhanced-oil-recovery (EOR) process that increases oil recovery over waterflooding by combining foaming with a decrease in the oil/water interfacial tension (IFT) by two to three orders of magnitude. We conducted an experimental study regarding the formation of an oil bank and its displacement by foam drives with foam qualities within the range of 57 to 97%. The experiments included bulk phase behavior tests using n-hexadecane and a single internal olefin sulfonate surfactant, and a series of computed-tomography (CT) -scanned coreflood experiments using Bentheimer Sandstone cores. The main goal of this study was to investigate the effect of drive-foam quality on oil-bank displacement. The surfactant formulation was found to lower the oil/water IFT by at least two orders of magnitude. Coreflood results, at under-optimum salinity conditions yielding an oil/water IFT on the order of 10-1 mN/m, showed similar ultimate-oil-recovery factors for the range of drive-foam qualities studied. A more distinct frontal oil-bank displacement was observed at lower drive-foam qualities investigated, yielding an increased oil-production rate. The findings in this study suggested that dispersive characteristics at the leading edge of the generated oil bank in this work were strongly related to the surfactant slug size used, the lowest drive-foam quality assessed yielded the highest apparent foam viscosity (and, thus, the most stable oil-bank displacement), and drive-foam strength increased upon touching the oil bank when using drive-foam qualities of 57 and 77%.