The understanding of the mechanisms behind foam generation and the structure of foam itself form the basis of foam-related experiments for its application in Enhanced Oil Recovery and overcoming gas injection limitations. Novel insights in this paper towards the theory of foam generation can help explain experimental results and lead to improved formulas of the applied substances and concentrations. This study aims to investigate the mechanisms behind foam generation and the structure of foam by specific laboratory experiments and theoretical analyses. The liquid drainage through interconnected Plateau borders was found to be the most critical foam decay mechanism for this particular research. The justification of the foam drainage equation was demonstrated by comparing the numerical solution with the outcome of a few bulk experiments. The discrepancies were described according to the limitations of both the theory and the experimental settings. Foam modelling gives more profound knowledge in more detail of the different stages in foam drainage than experimental data can deliver, which is because of the lack of continuous measurement of foam conductivity for the foam bulk test. Therefore, a comprehension of foam modelling investigation and comparison is required to gain a deeper understanding of foam behaviour.@en

This study addresses the critical challenge of excessive water production in mature oil and gas reservoirs. It focuses on the effectiveness of polymer gel injection into porous media as a solution, with an emphasis on understanding its impact at the pore scale. A step-wise Lattice Boltzmann Method (LBM) is employed to simulate polymer gel injection into a 2D Berea sample, representing a realistic porous media. The non-Newtonian, time-dependent characteristics of polymer gel fluid necessitate this detailed pore-scale analysis. Validation of the simulation results is conducted at each procedural step. The study reveals that the methodology is successful in predicting the effect of polymer gel on reducing permeability as the gel was mainly formed in relatively larger pores, as it is desirable for controlling water cut. Mathematical model presented in this study accurately predicts permeability reductions up to 100% (complete blockage). In addition, simulations conducted over a wide range of gelation parameters, TD_factor from 1 to 1.14 and Threshold between 0.55 and 0.95, revealed a quadratic relationship between permeability reduction and these parameters. The result of this research indicates LBM can be considered as promising tool for investigating time-dependant fluids on porous media.@en

Recovering apparent viscosity and foam texture fields from coreflooding experiments is challenging, even with modern computed tomography (CT) scan equipment. In this work, we present an explicit expression for efficiently calculating effective foam viscosity and propose an improved procedure for processing CT scan images to obtain accurate water saturation profiles. Using these techniques, we processed data from a CT scan of a coreflooding experiment, showing that the increase in effective foam viscosity due to foam generation occurs early during injection and before breakthrough. The fast increment in apparent viscosity is due to foam generation before breakthrough. After breakthrough, foam texture reaches its maximum, and effective foam viscosity grows logarithmically over time as the foamed gas sweeps out the water phase. The pressure drop obtained by using the effective foam viscosity showed good agreement with the experimentally obtained values before breakthrough. The workflow proposed here could be readily adapted to other foam models, provided reasonable estimates for these new quantities can be determined from experiments.@en

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.

@en

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.

@en

The microscopic structure of low-permeability tight reservoirs is complicated due to diagenetic processes that impact the pore-fluid distribution and hydraulic properties of tight rocks. As part of an ongoing study of carbon dioxide-enhanced oil and gas recovery (CO2-EOR/EGR) and CO2 sequestration, this research article adopts an integrated approach to investigate the contribution of the micropore system in pore-fluid distribution in tight sandstones. A new dimensionless number, termed the microscopic confinement index (MCI), was established to select the right candidate for microscopic CO2 injection in tight formations. Storativity and containment indices were essential for MCI estimation. A set of experiments, including routine core analysis, X-ray diffraction (XRD), scanning electron microscopy (SEM), mercury injection capillary pressure (MICP), and nuclear magnetic resonance (NMR), was performed on three tight sandstone rock samples, namely Bandera, Kentucky, and Scioto. Results indicate that the presence of fibrous illite acting as pore bridging in Bandera and Kentucky sandstone samples reduced the micropore-throat proportion (MTMR), leading to a significant drop in the micropore system confinement in Kentucky and Bandera sandstone samples of 1.03 and 0.56, respectively. Pore-filling kaolinite booklets reduced the micropore storativity index (MSI) to 0.48 in Kentucky and 0.38 in Bandera. On the other hand, the absence of fibrous illite and kaolinite booklets in Scioto sandstone led to the highest micropore system capability of 1.44 MTMR and 0.5 MSI to store and confine fluids. Therefore, Scioto sandstone is the best candidate for CO2 injection and storage among the tested samples of 0.72 MCI.@en

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.

@en

This report describes the activities performed within Task 1.2 “Report on gas solubility and degassing kinetic (type C)” until the end of month 40 of the REFLECT project. Two series of experiments have been carried out that assess the degassing process of type C geothermal fluids respectively in bulk and porous media. This has resulted in an improved understanding of the process and the associated physical phenomena by utilizing experimental equipment and data analysis tools specifically created for this task.@en

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.

@en

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.

@en

The long-term performance of the reservoir is essential in order to ensure competitive life-cycle cost of the geothermal installations. Geothermal fluids are often saturated with gasses such as CO2 and N2. With their extraction from the reservoir, pressure and temperature decrease towards the extraction well. This disturbs the state of equilibrium the geothermal water is in with its dissolved components, which for gas can lead to exsolution. The exsolved gas bubbles can block the pores of the reservoir rock and therefore reduce the apparent permeability. As permeability reduction occurs mainly near the extraction well it can reduce production of geothermal waters substantially. This paper is aimed at experimentally investigating the conditions at which the onset of degassing starts and quantitively assess any associated permeability decrease. Knowledge on these parameters will enable operators to adapt their operation procedures in order to ensure long-time reservoir permeability. This paper reports core-flood experiments where tap water containing dissolved carbon dioxide was injected into either a Bentheimer (2.3 Darcy) or Berea (140millidarcy) sandstone core at different conditions. The first sets of core-flood experiments showed that at a temperature of 30 °C and pressure up to 50 bars the onset of the degassing process correlates closely to CO2solubility values obtained by the Henry’s law. At these conditions CO2 degassing near the core outlet will cause the apparent permeability to decrease by a factor2 to 5 in the high permeability Bentheimer sandstone core. At the same conditions the apparent permeability will decrease by a factor of nearly 10 in the low permeability Berea sandstone core. The decrease ineffective permeability is gradual in the Bentheimer sandstone while in the Berea sandstone the change is steeper. For rocks with small pore sizes and low absolute permeability, the reduction in effective permeability is larger and the rate of permeability decrease is faster. However, the onset of degassing is not influenced by the pore size and initial permeability. Experiments at temperatures between 30 and 90 °C show that with increasing temperature, the Van ‘t Hoff equation becomes less to accurate to find the degassing pressure@en

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.

@en

Due to increased energy demand, it is vital to enhance the recovery from existing oilfields. Polymer flooding is the most frequently used chemical enhanced oil recovery (cEOR) method in field applications that increases the oil sweep and displacement efficiencies. In recent years, there has been growing interest to assess the use of polymer flooding in an increasing number of field applications. This is due to the improved properties of polymers at high-salinity and high-temperature conditions and an increased understanding of the transport mechanisms of water-soluble polymers in porous media. In this review, we present an overview of the latest research into the application of polymers for cEOR, including mechanisms of oil recovery improvement and transport mechanisms in porous media. We focus on the recent advances that have been made to develop polymers that are suitable for high-salinity and high-temperature conditions and shed light on new insights into the flow of water-soluble polymers in porous media. We observed that the viscoelastic behavior of polymers in porous media (e.g., shear thickening and elastic turbulence) is the most recently debated polymer flow mechanism in cEOR applications. Moreover, advanced water-soluble polymers, including hydrophobically modified polymers and salt- and temperature-tolerant modified polyacrylamides, have shown promising results at high-salinity and high-temperature conditions@en

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.

@en

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.

@en

The exsolution of gas molecules from gas–liquid mixtures plays a significant role in a wide range of applications from industrial processes such as metal casting to subsurface flow of oil or geothermal waters. This study aims to improve the understanding of the conditions under which free gas bubbles start forming in CO2–water mixtures. The bubble point pressure was determined under various different conditions like the temperature and initial pressure of the mixture along with other parameters such as the bubble growth rate. A series of depressurization experiments at high pressure and temperature (up to 100 bar and 100 °C) is performed using a pressure cell that allows for visual monitoring of the degassing process. Bubble formation during the depressurization process is recorded using a high-speed camera paired with a uniform light source along with a pressure transducer and thermocouple. Image analysis allows for the determination of the bubble point pressure and rate of bubble formation. For CO2 in its gaseous state and at moderate temperatures, decent agreement between experimental results and the theoretical bubble point pressure is found, although significant deviations are observed at elevated temperatures. More pronounced differences in bubble point are observed for mixtures starting out at high pressures where CO2 is a supercritical fluid, which lead to lower than expected bubble point pressures.@en

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.

@en

Porous materials have high specific surface area and complicated morphology, which dramatically amplifies interfacially driven processes leading to complex transport behaviors. Over the past decade, significant improvements in experimental and computational tools have enabled the direct probing of pore-scale physics. Numerous findings have been reported that provide new insights on how interfacial phenomena modulate Darcy-scale fluid behaviors.@en

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.

@en

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.

@en