Oil Swelling Research Articles

Feasibility of CO2 Injection for Enhance Oil Recovery: A Case Study in the KMJ Layer of HKY Field

Carbondioxide (CO2) injection is a very effective and proven technology for enhanced oil recovery (EOR). Minimum miscibility pressure (MMP) and oil swelling are two important factors of the CO2 gas displacement mechanism that occurs in the reservoir when CO2 injection is applied to enhance oil recovery. In this study, MMP determination between crude oil samples and CO2 gas has been conducted using three methods, i.e., empirical equation, correlations method, and laboratory experiment using slimtube. The determination of the swelling factor was conducted using a PVT cell, where recombined fluid is injected at the reservoir temperature. The MMP value from the empirical equation (2810 psig) is relatively close to the MMP value from the laboratory experiment (2807 psig), with a difference of 3 psig. The swelling test results show that the bubble point pressure and the swelling factor increase from 410 psig to 2200 psig and from 1.0 to 1.442, respectively, as the CO2 gas injection reaches 46.82% mole. Since the fracture pressure of the KMJ Layer in the HKY Field is 2200 psig and the MMP is 2807 psig, only immiscible CO2 flooding can be applied in the field because the CO2 MMP is higher than the fracture pressure.

Decreasing Asphaltene Precipitation and Deposition during Immiscible Gas Injection Via the Introduction of a CO2-Soluble Asphaltene Inhibitor

Summary In this study, the ability of dilute concentrations of toluene to act as a CO2-soluble asphaltene stabilization agent capable of inhibiting asphaltene precipitation during immiscible CO2 injection was assessed. Phase behavior results indicated that 1,000 to 20,000 ppm toluene could readily dissolve in CO2 at cloudpoint pressures that are well below the formation pressure and typical CO2 minimum miscibility pressure (MMP) values during gas-based enhanced oil recovery (EOR). Single-phase solutions of the modified gas (CO2/toluene) were then combined with asphaltenic oils in oil swelling phase behavior tests to demonstrate that the presence of toluene increased the amount of CO2 that dissolved into reservoir crude oil at a specified temperature and pressure. However, asphaltene precipitation diminished, apparently because the effect of the increased asphaltene solvent strength of toluene was more significant than the increased amount of CO2 (an asphaltene antisolvent) that entered the oil-rich phase. During the injection of CO2/toluene solution into cores initially saturated with crude oil and brine, compared to the injection of pure CO2, asphaltene deposition declined during the injection of CO2/toluene mixtures for asphaltenic volatile and intermediate oils from 3.7 wt% to 0.7 wt% and 5.9 wt% to 1.7 wt%, respectively. Based on the asphaltene particle-size analysis, the CO2/toluene mixtures can stabilize oil particles and simultaneously reduce asphaltene aggregation more effectively than pure CO2.

Diffusion coefficient and the volume swelling of CO2/light oil systems: Insights from dynamic volume analysis and molecular dynamics simulation

The oil volume expansion and CO2 diffusion are one of the main mechanism of CO2-enhanced oil recovery (CO2-EOR). This paper established a series of experiments, numerical simulations, and molecular dynamics (MD) simulations to describe mass transfer behaviors between oil–gas phases. Expressly, the CO2 diffusion coefficient and light oil swelling factor are signification parameters to quantify and analyze these behaviors. In detail, the CO2 diffusion coefficient and the oil swelling factor were obtained from the traditional pressure decay method and the advanced MD simulation. Synthetically, the pressure decay method and MD simulation results were mutually verified. The results showed that the equilibrium pressure was proportional to the mole fraction of CO2 and inversely proportional to the mole fraction of light oil. The equilibrium time was proportional to the mole fraction of CO2 and light oil. At the temperature of 333.15 K and the initial pressure of 7.5 MPa, the CO2 diffusion coefficient in light oil was positively correlated with the relative molar proportion of CO2, while the light oil swelling factor was vice versa. In addition, the closer to the CO2-light oil interface, the greater the light oil's potential energy and self-diffusion coefficient, and the stronger the transport ability.

Modeling Viscosity of CO2-N2 Gaseous Mixtures Using Robust Tree-Based Techniques: Extra Tree, Random Forest, GBoost, and LightGBM.

Carbon dioxide (CO2) has an essential role in most enhanced oil recovery (EOR) methods in the oil industry. Oil swelling and viscosity reduction are the dominant mechanisms in an immiscible CO2-EOR process. Besides numerous CO2 applications in EOR, most oil reservoirs do not have access to natural CO2, and capturing it from flue gas and other sources is costly. Flue gases are available in huge quantities at a significantly lower price and can be considered economically viable agents for EOR operations. In this work, four powerful machine learning algorithms, namely, extra tree (ET), random forest (RF), gradient boosting (GBoost), and light gradient boosted machine (LightGBM) were utilized to accurately estimate the viscosity of CO2-N2 mixtures. To this aim, a databank was employed, containing 3036 data points over wide ranges of pressures and temperatures. Temperature, pressure, and CO2 mole fraction were applied as input parameters, and the viscosity of the CO2-N2 mixture was the output. The RF smart model had the highest precision with the lowest average absolute percent relative error (AAPRE) of 1.58%, root mean square error (RMSE) of 2.221, and determination coefficient (R 2) of 0.9993. The trend analysis showed that the RF model could precisely predict the real physical behavior of the CO2-N2 viscosity variation. Finally, the outlier detection was performed using the leverage approach to demonstrate the validity of the utilized databank and the applicability area of the developed RF model. Accordingly, nearly 96% of the data points seemed to be dependable and valid, and the rest of them were located in the suspected and out-of-leverage data zones.

Carbon Dioxide Huff and Puff as Environmentally Friendly Method for Enhanced Heavy Oil Recovery

Heavy oil and bitumen are making up approximately 70 percent of the remaining estimated hydrocarbon reserves. Many Enhanced Oil Recovery (EOR) methods such as chemical flooding, thermal recovery, gas injection, etc., were developed to make advances in the production of unconventional oil. Among all the variety of EOR methods, thermal recovery produces practically all of the heavy oil and bitumen among the various EOR methods. But at the same time, throughout its application, there are several disadvantages were revealed such as it is an expensive and not environmentally friendly process, heat loss in surface facilities and distribution lines, the efficiency is low after injection, increases in the extracted oil’s surface viscosity have caused polymerization reactions of free radicals created during the steam injection process, and the requirement for continuous steam injection is attempting to keep a hot oil-water interface at the front of the flow. For these reasons, the solvent-based non-thermal recovery method can be used to enhance heavy oil and bitumen recovery in unconventional reservoirs (thin or deep reservoirs) to prevent or reduce unwanted effects as described above. Toluene, carbon dioxide (CO2), ethane, propane, normal butane, and mixture solvents, among others, can be used as the injection solvent for the solvent-based non-thermal recovery method. That is why the researchers have concentrated on carbon dioxide as a solvent with Huff & Puff method to develop the production of heavy oil and bitumen to overcome all these negative issues because CO2 has several characteristics that make it an excellent option for this application. In this paper, the CO2 Huff and Puff method is reviewed. The CO2 Huff and Puff method’s viscosity reduction and oil swelling procedures have been the most significant factors in increasing heavy oil production. As a results, impacts of oil swelling at various temperatures and pressures as well as the viscosity reduction ratio with CO2 injection have been studied.

Assessment of CO2-Oil swelling behavior using molecular dynamics simulation: CO2 utilization and storage implication

CO2 injection into petroleum reservoirs is an effective enhanced oil recovery (EOR) method that can increase the recovery of oil while reducing CO2 emissions into the atmosphere. To ensure successful implementation of CO2 EOR, a detailed understanding of reservoir fluid properties and the phase behavior of CO2-oil mixtures at different scales is required. The extent to which CO2 injection improves the oil recovery factor is heavily dependent on the swelling behavior of CO2-oil mixtures, which can be quantified by swelling factors. In this study, we model a CO2-oil swelling test using molecular dynamics (MD) simulations to calculate the swelling factors over a pressure range of 24.8 to 68 bar at a temperature of 303.15 K for an actual crude oil sample. The multicomponent molecular model of the oil is built using 1000 molecules of six hydrocarbons, based on the compositional analysis of the oil sample. CO2 molecules are then added to the system at several pressure steps, based on experimental CO2 solubility data, and the resulting swelling factors are compared to their corresponding experimental values. The results of this study demonstrate that the MD simulation model can be successfully used to investigate CO2-oil swelling behavior and accurately predict the swelling factors with a minor mean percentage error of 6%. Additionally, analysis of potential energy variations due to interactions between different molecules in the system under increasing pressures and CO2 mole fractions indicates that the swelling process is primarily controlled by changes in intermolecular forces between CO2-oil and oil-oil molecular pairs, while the effect of CO2-CO2 molecular potentials on oil swelling is minimal. This work highlights the ability of the MD simulation technique to model the complex phase behavior of CO2-oil mixtures and provides unique insights into the molecular-scale mechanisms of CO2 dissolution in oil and the resulting swelling phenomenon.

Effect of drying methods on physicochemical, antioxidant and functional properties of potato peel flour and quality evaluation of potato peel composite cake

Cakes are usually consumed bakery item all over the world; so, their enrichment with nutrients is an effective way to increase nutrition to the people health. This goal can be achieved using the potato peel flour (PPF) on cake formulation. This research was carried out to compare the effect of drying methods (cabinet and sun drying) on the physicochemical, antioxidant and functional properties of dried potato peel flour (PPF). The physical, textural and sensory characteristics of the PPF incorporated cakes were also evaluated. The PPF was prepared by blanching (at 90–95 °C for 2–3 min), drying (65 °C and 30 °C) and grinding the potato peel; afterwards, the physical and chemical properties of PPF were analyzed. Results showed that cabinet dried PPF contains higher protein (11.39 ± 0.07%), fat (7.23 ± 0.12%), fibre (12.92 ± 0.09%) and carbohydrate content (55.42 ± 1.07%), as well as a lower amount of moisture (7.61 ± 0.01%), and ash (9.63 ± 0.67%) percentage than the sun-dried PPF. Furthermore, the mineral and antioxidant activity was more significant in the cabinet dried PPF compared to sun-dried PPF. Other functional properties such as water and oil absorption capacity, bulk density, foaming capacity, emulsifying activity and swelling capacity were also found to be higher for the cabinet-dried PPF than the sun-dried. Composite cakes were prepared at different ratios of wheat flour to cabinet-dried PPF (100: 0, 96: 4, 94: 6 and 92: 8). The addition of PPF increased the height, volume and weight of cakes compared to the control (100% wheat flour) cakes. In the sensory evaluation, the cakes enriched with 4% PPF achieved the highest score for the sensory attributes. Therefore, the incorporation of 4% cabinet-dried PPF with WF could be suggested for the formulation of composite cakes with better physical and organoleptic qualities.

Determination of mutual diffusivity of CO2/C3H8-heavy oil systems with consideration of natural convection under reservoir conditions

By performing dynamic volume analysis, we developed and applied an experimental and theoretical technique to determine mutual diffusivity (i.e., diffusivity of a gas component in an oil phase and that of the extracted oil components in the gas phase) of CO2/C3H8-heavy oil systems in the presence of natural convection under reservoir conditions. Experimentally, diffusion tests are conducted for CO2/C3H8-heavy oil systems at high pressures and elevated temperatures with a PVT setup, while swelling factors of the oil phase are measured and recorded continuously. We have collected gas and oil samples at end of the test for gas chromatography (GC) and oil compositional analysis. Theoretically, mutual diffusivity between a solvent and heavy oil can be determined once the discrepancies between the measured and calculated parameters, including swelling factors and gas compositions, have been minimized. The diffusivities of both solvents (i.e., CO2 and C3H8) and oil components are found to increase with pressure and temperature. Except for the dissolution of solvent(s) into heavy oil due to concentration difference, there exists an obvious extraction process from the oil to gas phases during each experiment at elevated temperatures as light-medium components (i.e., C1-C4 and C6-C8) have been detected in the collected gas samples at the end of the test, during which the oil swelling effect is diminished at its late period when the solvent-heavy oil system approaches its equilibrium state. Compared to the CO2-heavy oil systems, more light components have been detected for the C3H8-heavy oil systems, indicating that stronger extraction occurs when adding C3H8 to the heavy oil at elevated temperatures. Since natural convection has an opposite direction from molecular diffusion, separating the former from the latter results in larger diffusion coefficients of CO2 and C3H8. In addition to new experimental data, both diffusivity of a solvent/CO2 in heavy oil and that of the extracted oil components in the gas phase are quantified in a more complex solvent(s)/CO2-heavy oil system at high pressures and elevated temperatures, not only serving as the benchmark for future studies to consider the contribution of temperature and porous media, but also allowing us to evaluate and optimize the hybrid solvent-steam method in a heavy oil reservoir within a unified and consistent framework.

Carbonated Smart Water Injection for Optimized Oil Recovery in Chalk at High Temperature

Finding cost-efficient ways of increasing oil production with a low carbon footprint is the new challenge for the petroleum industry that wants to meet the net-zero emission goals by 2050. Smart water injection is an EOR process that increases oil production and delays water breakthrough by wettability alteration. Seawater is a smart water in chalk reservoirs, being especially effective at high temperatures. Different studies have shown that the effectiveness of seawater can be further improved by modifying the ion composition before injection. Carbonated water (CW) has been proposed as a potential EOR fluid. In addition to producing extra oil, the reduction of greenhouse gas (CO2) in the atmosphere can be achieved by using carbonated smart water as an injection fluid. The main mechanism behind increased oil recovery by injecting carbonated water is believed to be oil viscosity reduction and swelling, as the CO2 is transferred from the aqueous phase to the oil phase. Wettability alteration has also been proposed as a possible mechanism, and this hypothesis is further investigated in this study along with other proposed mechanisms. Stevns Klint outcrop chalk was used in this study, this material is recognized as an excellent analogue for North Sea chalk reservoirs. Optimized oil recovery by carbonated water in chalk was investigated at a high temperature (130°C) by flooding carbonated formation water (CFW) and carbonated seawater (CSW), to be compared with high saline formation water (FW) and seawater (SW) flooding. The oil/brine/rock/CO2 interactions were tracked by measuring the pH of the produced water (PW) and by identifying any mineralogical changes by SEM (Scanning Electron Microscope) and EDX (Energy Dispersive X-Ray) analyses. The solubility of CO2 in different brines was measured and compared with simulation data performed by PHREEQC. The diffusion of CO2 from the aqueous phase to the oil phase was analysed to check if enough CO2 can be diffused from the carbonated water into the oil phase. By flooding CSW in both secondary and tertiary modes, a slight increase in the oil recovery was observed and was found to be the best performing brine. The oil recovery was also slightly increased using CFW in tertiary mode after FW which does not behave like smart water for carbonates. The solubility of CO2 was low and increased by increasing pressure and decreasing brine salinity. The acidity of CW did not increase by increasing pressure. No changes in pore surface minerals were observed after CW flooding, confirming limited mineral dissolution. A mass transfer of CO2 from the brine phase to the oil phase was confirmed in the experimental work, but a significant amount of CO2 remained in the brine phase. The main mechanism behind this extra oil observed using CW is most likely not linked to oil swelling and viscosity reduction or mineral dissolution which could affect the porosity and the permeability of the rock system. Wettability alteration is a more likely explanation but needs to be looked further into for confirmation.

Evaluation of immiscible CO2 injection in high water production reservoir in the Pannonian basin

Carbon dioxide (CO2) flooding is one of the most important and most used enhanced oil recovery (EOR) method because it does not only increase oil recovery efficiency but also is used as an underground CO2 storage. It is considered a very complex method as it involves knowing the fluid phase behavior with different CO2 concentrations. It should be noted that oil swelling (volume increase) with the dissolution of carbon dioxide has a significant effect on increase of oil recovery. When this occurs, a significant decrease in the viscosity of the oil is observed. In this study, a reservoir 3D simulation modeling approach was applied to evaluate immiscible and miscible CO2 flooding in a high WC reservoir. To reduce simulation time, the PVT composition was grouped into 5 fluid components. The 3-parameter, Peng-Robinson Equation of State (EOS) was used to match PVT experimental data by using the Schlumberger's ECLIPSE PVTi software. One-dimensional slim-tube model was defined using ECLIPSE 300 software to determine the minimum miscibility pressure (MMP) for injection of CO2. Beside this approach, an analytical MMP estimation was carried out using several correlations. Schlumberger Petrel software was used to set up a 3D simulation model of a static and dynamic model. Various scenarios of immiscible and CO2 injection have been simulated using ECLIPSE 300 software and these results have been compared.

Effects of Extrusion Variables on Some Chemical and Functional Properties of Thermo-extrudates from Selected Varieties of Sesame (Sesamum Indicum L)

This study examined the effects of extrusion conditions of Feed moisture (FM) (14 – 25% wb) and Screw speed (SS) (250 – 350 rpm) at constant barrel temperature of 100oC on some chemical composition and functional properties of thermo-extrudates from three sesame varieties (Bogoro, E8, and Ex-Sudan), using central composite rotatable design on water absorption (WAC) and oil absorption (OAC) capacity, bulk density (BD), solubility (SOL) and swelling capacity (SC). The protein content of thermo-extrudates significantly (p<0.05) decreased with FM and increased SS. The tannin content in the thermo-extrudates ranged from 11.0 to 14.17; 9.83 to 12.50; and 7.50 to 12.65 (mg/100 g), the phytate content ranged from 19.33 to 25.00; 17.00 to 21.50 and 16.0 to 22.83 (mg/100 g) in Bogoro, E8, and Ex-Sudan respectively. An increase in FM and SS (p<0.05) reduced tannin by 41%, 40% and 46%, and phytate by 28%, 32%, and 30% in Bogoro, E8,and Ex-Sudan. Solubility was the most predictable functional property of the thermo-extrudates, with models having coefficients of determination (R2) of 0.99, 0.82, and 0.86 for Bogoro, E8, and Ex-Sudan. The optimized processing conditions for E8 with desirability of 0.74 are FM 14% and SS 250 rpm, which resulted in optimal WAC of 168.55%; SOL 14.36%; OAC 138.27%; BD 0.67 g/cm3; SC 1.53%.

Experimental study on fracture effect on the multiphase flow in ultra-low permeability sandstone based on LF-NMR

Multiphase flow affected by fractures is essential for enhanced oil recovery in ultralow-permeability reservoirs. In this study, CO2/water flooding of intact and fractured cores was performed under in-situ stress, and low-field nuclear magnetic resonance was employed to monitor the pore structure evolution and multiphase flow. The adsorption pore (AP), percolation pore (PP), and migration pore (MP) were determined in the ultralow permeability sandstone, and the PPs and MPs contributed to oil recovery during CO2 flooding. Three-scale pores contributed to oil production during water flooding. Compared with water flooding, CO2 flooding had a considerably higher average recovery efficiency, which was associated with pronounced gas channeling and lower ultimate oil recovery. In CO2 flooding, the oil production in PPs and MPs depended on the pressure difference, whereas that in APs was determined by oil swelling. But for water flooding, oil migration in the AP and MP was dominated by capillary imbibition and pressure difference, respectively. The fracture enhanced the oil recovery during CO2 flooding by increasing the CO2 sweep area in the PPs and MPs. It also improved oil recovery during water flooding based on the increment of the oil-water flow area in the APs and MPs. The mass transfer in CO2 flooding between the fracture and the matrix occurred through the PP and MP connected to the fracture, controlled by the pressure difference, number of PP and MP connected to the fracture, and oil swelling capacity. For water flooding, the oil-water exchange in the fracture-matrix system was dominated by number of pores connected to the fracture, hydrophilic ability of the rock, and pressure difference. These results can be used for enhancing oil recovery in fractured ultralow-permeability reservoirs.

Proximate Composition, Functional Properties and Sensory attributes of Gruels prepared from Blends of Sorghum and Pigeon Pea Flours

This study was carried out to evaluate the proximate composition and functional properties of sorghum and pigeon pea composite flours and the sensory properties of gruel prepared from the blends. Flours were produced from sorghum and pigeon pea seeds. The composite flours of sorghum and pigeon pea were blended using different proportions designated as SGF, PPF, SP1, SP2, SP3, SP4 and SP5. The proximate composition, functional and sensory properties of the blends were determined using standard methods. Proximate result showed significant (p<0.05) increase in protein (11.25 – 23.10%), crude fibre (3.05- 7.35%) and ash (2.01 – 4.72%) and significant (p<0.05) decrease in fat (4.53 - 1.80%) and carbohydrate (72.06 – 55.88%) with increase in percent pigeon pea flour in the blends. There were significant (p<0.05) differences in the energy value of the blends. The functional properties result showed that bulk density, water absorption capacity, oil absorption capacity, wettability, gelation capacity and swelling index ranged from 0.610 – 0.681g/ml, 1.33 – 2.25g/g, 1.28 – 1.73g/g, 80.06 – 165.12s, 9.11-10.0% and 1.56 – 2.54 respectively. The sensory result showed that the gruels made from the blends were acceptable to the panelists. The blends can be useful as good weaning foods for children.

Interfacial Instability-Induced (3I) Adhesives through "Mediator" Solvent Diffusion for Robust Underoil Adhesion.

Underoil adhesives are intensively needed in case of oil spill caused by pipeline rupture, but remain a challenge owing to the obstruction of oil layer or their swelling in oil. Herein, a general solvent diffusion principle is demonstrated by introducing dual-soluble "mediator" solvents to develop a new type of interfacial instability-induced (3I) adhesives, achieving effective underoil adhesion on various substrates and blocking the oil leakage within seconds. Microscopic characterization reveals a fast and dynamic solvent exchange process that destroys the oil layer by liquid-liquid interfacial diffusion between the "mediator" solvent and oil, enabling 3I adhesives to contact the solid surfaces directly. The principle of interfacial instability-induced liquid replacement is quite different from typical immiscible liquid replacement and is not restricted by the surface tension of solvents, surface energy, and roughness of solid surfaces, successfully directing the construction of a series of effective 3I adhesives with commercially available feedstocks. This study provides a unique clue for the design of next-generation adhesives in complex environments.

Measurement and modelling of the interfacial tensions of CO2 + decane-iododecane mixtures at high pressures and temperatures

Experimentally determined interfacial tensions (IFTs) of CO2 and decane-iododecane mixtures are reported, with iododecane mass fractions of 0%, 50%, 70%, 90% and 100% over the temperature range of 298 K to 353 K and at pressures from 1 MPa up to the mixture critical point pressure. Measurements were carried out in a thermostatic high-pressure view cell by means of the pendant drop method. It was observed that the volume of a fresh drop of hydrocarbon initially increased, while the IFT decreased, before reaching equilibrium values. These observations correspond to two key mechanisms of CO2 flooding: oil swelling and IFT reduction. The equilibrium IFTs decrease with increasing pressure isothermally until the mixture critical point pressure is reached. The IFTs also increase with increasing mass fraction of iododecane. An empirical model was developed that is able to represent the experimental results with an overall average absolute deviation of 0.2 mN∙m−1.The IFT data were modeled with the square gradient theory coupled with the volume-translated Peng-Robinson equation of state. The temperature-independent influence parameters of decane and iododecane were regressed from their surface tensions, while the influence parameter of CO2 was taken from literature. The theoretical predictions are in good agreement with the experimental results with an average absolute deviation of 0.4 mN∙m−1. Finally, we extend a group-contribution approach for the binary interaction parameters in the Peng-Robinson equation of state to encompass the CH2I functional group, thereby facilitating application of the modelling approach to other systems comprising CO2 or N2 with iodoalkanes.

Improvement to Gravity Drainage Recovery by Repressurization as a Criterion to Screen and Rank Naturally Fractured Reservoirs for Gas Injection

Summary Many of the naturally fractured carbonate reservoirs of the Middle East exhibit low natural-depletion recoveries. The reason is that most of their oil reserves are stored in the low-permeability host rocks and are left behind by the fast advancing gas/oil contact (GOC) and water/oil contact (WOC) in fractures. Producing the remaining oil in the large gas-invaded zone of these reservoirs has been a crucial reservoir management issue. We show in this study using experimental observations, analytical calculations, and numerical investigations that repressurizing naturally fractured reservoirs (NFRs) by crestal immiscible gas injection has the potential to produce a large portion of this remaining oil by improving gravity drainage (GD) through two main mechanisms. One is that at higher pressures, the gas-oil interfacial tension (IFT) and hence the capillary forces that control recovery by GD are lessened, allowing additional recovery. This mechanism is aided by the other one, which is swelling of the oil at higher pressures. In this way, repressurization is thought to be not only a means for pressure maintenance but also a methodology for enhanced-oil recovery (EOR). This is confirmed by both laboratory studies and field performance of large-scale gas injection projects. Despite the desire for implementation of projects of repressurization, gas availability and cost of these projects are important concerns, requiring a cost-benefit analysis. Screening and ranking methodologies have been previously presented for some EOR techniques but not for repressurization by gas in NFRs. Evaluating the performance of gas injection in NFRs is often done using methodologies such as numerical simulations, which are in-depth, costly, and tedious. The methodology developed here is simple, requiring spreadsheet calculations. To develop the methodology, we first obtain simple relations to calculate additional GD recovery by considering the interplay of capillary and gravity forces in a matrix block subjected to pressurization by equilibrium gas injection and then use experimental data from literature to show that these relations can predict primary and secondary GD recoveries to a good approximation. We also show by mechanistic studies using a history-matched numerical model that IFT reduction and oil swelling are the main mechanisms contributing to additional oil recovery. Then, we propose a methodology to screen and rank candidate NFRs for gas injection that uses commonly available reservoir data and is based upon two criteria, these being additional oil recovered from a matrix block by pressurization and required volume of gas to produce an additional barrel of oil. We then implement this methodology to more than 20 Iranian NFRs and identify six reservoirs with potential for additional recovery of more than 20%. By quantifying and including the uncertainties associated with the reservoir data, we illustrate that for the reservoirs under study, capillary pressure parameters along with matrix-block height are the main parameters affecting GD recovery and should be characterized more accurately.

Microscopic production characteristics of tight oil in the nanopores of different CO2-affected areas from molecular dynamics simulations

Understanding the mechanisms of CO2 extraction or flooding are vital for enhancing oil recovery (EOR) in tight reservoirs. In this study, the CO2 EOR mechanism in the displacement-affected area (DPAA) and diffusion-affected area (DFAA) of quartz nanopores were thoroughly investigated using molecular dynamics simulation techniques. First, the following two contents were mainly simulated, namely CO2 flooding oil in the single/double nanopores of DPAA and CO2 extraction oil in dead-end nanopores of the DFAA with and without the water film. Then, tight oil potential energy, threshold capillary pressure, CO2 solubility, and oil swelling in nanopores were calculated to clarify the effects of CO2 on oil transport. Moreover, different CO2 injection/flowback rates and different water film thicknesses on dead-end nanopores on oil recovery were discussed. In the DPAA, the CO2 solubility and the oil swelling factor gradually decreased with distance from the CO2-oil interface (Y = 0 nm), where the higher the injection rate, the more easily the CO2 dissolved in the oil. However, the injection rate of CO2 was inversely proportional to oil recovery. In addition, it took longer for the displacement efficiency in the 6 nm pore of double pores to reach the same displacement efficiency as in the single 6 nm pore. In the DFAA, the effect of flowback rate on the displacement efficiency of oil was relatively low. However, the thickness of the water film was a key factor that affected the oil displacement efficiency in the DFAA.

Surface-active compounds induce time-dependent and non-monotonic fluid-fluid displacement during low-salinity water flooding

Hypothesis: In a porous medium saturated with oil (containing oleic surfactant) and saline water, salinity reduction alters the thermodynamic equilibrium and induces spatial redistribution of surfactants, changing the local fluid configuration. During fluid–fluid displacement, this local change reshapes global fluid flows, and thus results in improved oil displacement.Experiments: We performed microfluidic experiments in a centimeter-long pore-network model with a fracture and a dead-end model to observe both the macroscale flows and microscopic fluid configuration evolution. Water with different salinities and model oils with different surfactant concentrations are used.Findings: When oil contacts low salinity water, we observe (1) the solid surface becomes more water-wet, and (2) water-in-oil emulsion spontaneously emerges near the oil–water interface. At the macroscale, the fluid distribution remains unchanged in short term but dramatically changes after tens of hours, which appears as improved oil recovery. Two modes are identified during fluid redistribution: gradual imbibition and sudden collapse. The displacement efficiency is a non-monotonic function of surfactant concentration. This is attributed to the interplay between two opposing effects by adding surfactant: (1) enhancing initial hydrophobicity which negatively affects the displacement, and (2) allowing stronger oil swelling which is beneficial for displacement.

Application of the Maxwell–Stefan theory in modeling gas diffusion experiments into isolated oil droplets by water

We have used the Maxwell–Stefan diffusion theory to model the mass transfer between tertiary-injected gas and residual oil blocked by water, in order to predict the time required for the rupture of the water barrier due to oil swelling. We have also designed and conducted a set of visualization micromodel experiments on various pure and multicomponent oil–gas systems to measure the water rupture time in tertiary gas injection processes. The experimental results show that the initial pressure and dimensions of the system, the oil and gas composition, and the gas solubility in water control the oil swelling process. The experimentally measured rupture times are then employed to evaluate the reliability of the model and to compare its accuracy with that of a similar one using classical Fick's law. Our modeling results show that both models are able to estimate the water rupture time for pure systems with an acceptable precision. As for multicomponent mixtures, however, only the Maxwell–Stefan theory is capable of modeling the molecular diffusion process correctly and yields values close to reality, while the use of Fick's law would lead to erroneous results. Deficiency of the latter model becomes more acute when the diffusion direction in reality is contrary to what the model indicates, which leads to failure in calculating any value for rupture time at all for these cases.

Pore matrix dissolution in carbonates: An in-situ experimental investigation of carbonated water injection

Carbonate rock dissolution during the reactive transport of carbon dioxide (CO2)-enriched brine has been studied extensively in the context of carbon storage in saline aquifers. However, there is limited knowledge of CO2-induced reactive transport in multiphase systems (containing oil and brine), which is more relevant to carbon sequestration in depleted oil reservoirs. In this work, we uncover the pore-scale dynamics of fluid flow and rock dissolution during carbonated water injection (CWI) in hydrophilic porous media containing two fluid phases (oil and brine). We combine novel core flooding and high-resolution imaging techniques to visualize and characterize changes in fluid occupancy and pore morphology. It is observed that the sequence of flow and transport in two-phase systems involves a pre-dissolution period, where CWI induces the displacement of waterflood-trapped oil, and a dissolution period typified by channel flow. Improved oil recovery during pre-dissolution emanates from an oil swelling mechanism that drives reconnection and mobilization of trapped oil globules. Additionally, CO2 is stored in both oil and carbonated water. Channel flow during dissolution results in the formation of wormholes with two distinct dissolution patterns. The first is a conical wormhole at lower injection rates where diffusion rates are significant. The second is a dominant wormhole at higher injection rates where advection dominates the transport of reactive species to the flow boundaries. We find that the oil displacement efficiency during dissolution is significantly lower than pre-dissolution levels and is dependent on the wormhole pattern, with dominant wormholes providing a high-permeability and high-velocity flow path for trapped oil movement. Therefore, unlike the injectivity losses that originate from salt precipitation during direct CO2 injection, CWI in depleted carbonate oil reservoirs enhances the injectivity of injection wells allowing for an energy efficient CO2 storage.