A full petrographic and petrophysical characterization of tight sandstones has been conducted as part of ongoing study of Carbon Dioxide Enhanced Oil and Gas Recovery (CO₂-EOR/EGR) and CO₂sequestration. The main purpose of this study is to give novel perception into the interplay of the rock characteristics and fluid flow in tight formations, which are candidates for EOR/EGR processes (macroscopic sweep vs. microscopic displacement efficiency). To achieve this, several experimental techniques, including routine core analysis, X-ray diffraction (XRD), X-ray fluorescence (XRF), thin sections petrography, Scanning Electron Microscopy (SEM) and capillarity/pore size distributions by using Mercury Injection Capillary Pressure (MICP), Nuclear Magnetic Resonance (NMR), and Micro-Computed Tomography (Micro-CT), were conducted. Three tight sandstone rock samples (Bandera, Kentucky, and Scioto) were used in this work and particular attention was paid to the impact of clay content on rock's pore system and other petrophysical characteristics and hence fluids flow during production process. Results indicate that the presence of fibrous illite clay acting as pore bridging in Bandera and Kentucky samples have blocked the overall micro-pore system causing a significant reduction in the micro-pore throat system to 36% in Bandera sand and 50.9% in Kentucky sample. On the other hand, absence of fibrous illite and the presence of illite platelets in the Scioto sandstone led to a clear preservation of the sample's micro-pore throat attributing to a total of 59.1% of the total pore throat system. A new dimensionless number (dimensionless micro-pore throat modality) was established, defined as the ratio of micro-to macro-pore sizes. This shows that Scioto has the highest value of 1.44 implying that both macro- and micro-pore systems contribute to flow. Therefore, the mitigation of oil bypass from smaller pores should be a key criterion in selecting the proper recovery methods. Results show the effect of clay mineralogy on pore system considering a part of the physical and spatial properties the pore/grain framework of the tight sandstones.

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.

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.

Cross-linked polymer gel is widely used in the oil and gas industry to block high permeability conduits and reduce water cut. The complex nature of this fluid, especially regarding flow in porous media, makes its numerical simulation very time-consuming. This study presents an approach to designing an Artificial Neural Network (ANN) model that could predict the permeability reduction caused by injecting polymer gel into a 2D rock sample. Our methodology consists of two main parts: numerical simulation and ANN model building. Considering the advantages of the Lattice Boltzmann Method (LBM) this approach is used to model the injection of polymer gel in porous media. Using this model, more than 20,000 simulations were performed which resulted in highly unbalanced dataset, so an innovative approach for balancing regression dataset is also proposed in detail in this paper. The final constructed ANN model could predict the permeability reduction in a fraction of a second with less than 2.5% Mean Absolute Error (MAE). The result indicates the importance of balancing datasets to obtain a reliable prediction from ANN. Also, it should be mentioned that gelation parameters had the most significant impact on the value of permeability reduction, with mean absolute SHapley Additive exPlanations (SHAP) values of 20 and 12.5 for TDfactor and Threshold, respectively.

Water injection into the subsurface, inherent in improved hydrocarbon recovery and extraction of geothermal energy, often suffers from injectivity decline, even when water carries only nano-sized particles at low concentrations. This study investigates the propagation of such nano-sized particles experimentally and by modelling. Water with dispersed silica nanoparticles of about 140 nm diameter was used as a proxy to ultra-filtered water. Dispersion of the nanoparticles in brine is investigated by varying their concentration, the brine composition, salinity, pH and the presence of iron ions. The measured apparent hydrodynamic size and zeta potential indicate that nanoparticles remain dispersed with the expected size only for salinity below 3000 ppm with pH ranges 6.5 to 8.5. For higher salinity or pH outside that range or presence of iron ions, agglomeration becomes strong. Core flood experiments are conducted on high permeability Bentheimer sandstone, and the transport and retention of nanoparticles in the cores was analysed using multiple pressures measured along the core and by influent/effluent analysis. Core flood results show that stable injectivity can be reached with a good propagation of the nanoparticles through the permeable core with no external filter cake formation, provided the pH and salinity of the injected fluid are kept within the dispersion range and free of iron ions. However, injectivity decline still occurs in three characteristic stages well captured by our mechanistic model used to match the data. This study will contribute to better understanding of the transport dynamics of nanoparticles in the subsurface and to better modelling prediction and assessment of technologies where transport of nanoparticles is key.

Capillary forces result in the trapping of the oleic phase in porous media even after extensive flushing with brine. Alkali-surfactant-polymer formulations drastically diminish capillary forces, whereas adding polymer to the water phase increases viscous forces, resulting in highly efficient extraction of the residual oil. However, by virtue of its scale, the above process requires a large quantity of chemicals, which poses a threat to the environment. Here, we demonstrate that replacing the polymer with a gas such as nitrogen, flue gas, or carbon dioxide achieves equally superior oil extraction efficiency when using a much smaller amount of chemicals. Mobilized oil is first displaced as a continuous phase (oil-bank) and then as an oil-in-water dispersion. Microflow visualization experiments reveal that dispersed oil spreads at the gas–liquid interface (surfactant solutions) due to the presence of adsorbed surfactant molecules. Our dry-cleaning extraction of hydrocarbons has a wide spectrum of applications and is particularly useful for the production of hydrocarbons from underground formations while mitigating the impact of chemicals on the environment.

One of the main reasons for foam flooding enhanced oil recovery (EOR) is mobilizing oil left in the reservoir after primary recovery (depletion by pressure difference solely) and water flooding. However, expanding the infrastructure for certain foam EOR projects might be necessary as more wells are required, or a different well pattern is necessary. This study aims to study the effect of Newtonian and non-Newtonian viscosifying agents to assist foam flooding under the porous medium condition and to compare the results. Furthermore, this paper attempts to investigate the use of glycerol as a novel promising economic and ecological candidate instead of polymers. The shear rate inside the core was calculated based on the literature, which was combined with viscometric measurements in order to form four pairs of equal apparent viscosity. The differences and overlap within the core flooding experiments with foam generated by Newtonian and non-Newtonian fluids were observed by examining the mobility reduction factor under transient and steady-state conditions and by calculating the gas fraction present in the core. It was concluded that glycerol in core flood experiments could reach the same mobility reduction factor of about 1600 as polymer solutions with the same apparent viscosity, as long as the viscosity of the injected solution is reasonably low. Moreover, glycerol even reached the maximum mobility reduction factor faster than the foam generated by the polymer solution.

This article describes the effects of different physico-chemical factors on formation damage caused by migration of in situ clay particles as a result of water injection into a clastic reservoir.

Electromagnetic (EM) heating is an emerging method for storing renewable energy, such as photovoltaic solar and wind electric power, into aquifers. We investigate how the captured energy increases the temperature of a prototypical deep aquifer for a six-month period and then to which extent the stored energy can be recovered during the consecutive six months. Water injected at a constant flow rate is simultaneously heated using a high-frequency electromagnetic microwave emitter operating at the water natural resonance frequency of 2.45 GHz. The coupled reservoir flow and EM heating are described using Darcy’s and the energy balance equations. The latter includes a source term accounting for the EM wave propagation and absorption, modeled separately using Maxwell’s equations. The equations are solved numerically by the Galerkin least-squares finite element method. The approach was validated using EM-heating input data obtained from controlled laboratory experiments and then was applied to the aquifer. We found that after six years of alternate storage and recovery, up to 77% of the injected energy is recovered when considering realistic heat losses estimated from field data. Even when heat losses are increased by a factor of two, up to 69% of the injected energy is recovered in this case. This shows that down-hole EM heating is a highly effective method for storing renewable energies, capable of helping to solve their inherent intermittency.

Condensate banking is a major issue in the production operations of gas condensate reservoirs. Increase in liquid saturation in the near-wellbore zone due to pressure decline below dew point, decreases well deliverability and the produced condensate-gas ratio (CGR). This paper investigates the effects of condensate banking on the deliverability of hydraulically fractured wells producing from ultralow permeability (0.001 to 0.1 mD) gas condensate reservoirs. Cases where condensate dropout occurs over a large volume of the reservoir, not only near the fracture face, were examined by a detailed numerical reservoir simulation. A commercial compositional simulator with local grid refinement (LGR) around the fracture was used to quantify condensate dropout as a result of reservoir pressure decline and its impact on well productivity index (PI). The effects of gas production rate and reservoir permeability were investigated. Numerical simulation results showed a significant change in fluid compositions and relative permeability to gas over a large reservoir volume due to pressure decline during reservoir depletion. Results further illustrated the complications in understanding the PI evolution of hydraulically fractured wells in "unconventional" gas condensate reservoirs and illustrate how to correctly evaluate fracture performance in such a situation. The findings of our study and novel approach help to more accurately predict post-fracture performance. They provide a better understanding of the hydrocarbon phase change not only near the wellbore and fracture, but also deep in the reservoir, which is critical in unconventional gas condensate reservoirs. The optimization of both fracture spacing in horizontal wells and well spacing for vertical well developments can be achieved by improving the ability of production engineers to generate more realistic predictions of gas and condensate production over time.