Oil CO2 Research Articles

Numerical study of CO2 trans-critical process inside micromodel based porous structures under supercritical pressures

Understanding the flow, heat transfer, and trans-critical process of carbon dioxide in porous media is crucial for various applications, including CO2 sequestration, soil remediation and oil and gas recovery, due to its unique physical properties in the critical region. In this study, a porous media model on a microfluidic chip structure was simulated to emphasize the heat transfer and trans-critical process of CO2 under supercritical pressure in porous media. The study aims to observe the behaviors of CO2 during its transition from subcritical to supercritical temperature under supercritical pressure. The main objective is to observe the temperature distribution and pressure change of CO2 in a porous media model under the influence of bottom heating. At the same time, we observe the changes in the position of the critical temperature point of CO2 in porous media and analyze its heat exchange process in porous media. After the flow reaches a steady state, the temperature span near the grains is 1.6 K, and the pressure drop per unit length is 1480.3 Pa/mm. As the flow time progresses, the critical temperature line migrates from outlet region to inlet region, the range of sCO2 narrows from 81.7 % to 84.7 % in the porous media region. Finally, the influence of different working conditions on the trans-critical region is studied. It is hoped that this study will contribute to the understanding of the trans-critical process of CO2 in porous media.

Simultaneous adjustment on the CO2/oil and CO2/water interface tensions using hydrophilic, lipophilic and CO2-philic surfactants during CO2 flooding to enhance shale oil recovery after hydraulic fracturing

It is an urgent demand to further enhance shale oil recovery after large-scale hydraulic fracturing with a low oil recovery. CO2 flooding technology has been demonstrated to effectively develop shale oil, however, the residual water after hydraulic fracturing can influence the efficiency of CO2 flooding because of the high CO2-water interfacial tension. Here, the hydrophilic, lipophilic and CO2-philic surfactants were investigated to simultaneously adjust the CO2/oil and CO2/water interface tension to accelerate the oil and water flows to enhance shale oil recovery. The results show that the low-carbon alcohol polyoxyethylene polyoxypropylene ether has the hydrophilic, lipophilic and CO2-philic properties. The alkyl chain length and PO groups have great influence on the interfacial tension of CO2-oil, while the presence of EO groups can significantly reduce the interfacial tension of CO2-water. The surfactant of C4EO3PO6 can not only demonstrate the best performance in reducing the interfacial tensions of shale oil-CO2 and water-CO2, but also decrease the minimum miscibility pressure (MMP) of the shale oil-CO2 system to 18.89 MPa from 24.10 MPa. The interfacial tension between water and the CO2 + 1.0 wt% C4EO3PO6 system can be decreased to 6.62 mN/m at 28 MPa and the reduction rate is 56.10 %. The enhancement of surfactants on the extraction effect of CO2 and the mutual diffusion process between CO2 and shale oil or water interface is the major mechanism to decrease the interfacial tensions. Therefore, the addition of surfactant in CO2 can simultaneously decrease the interfacial tensions of CO2-oil and CO2-water and has a potential to enhance shale oil recovery by reducing the capillary resistance of residual water after hydraulic fracturing and increasing the miscibility between CO2 and oil.

Wettability and capillary behavior in a CO2–oil–solid system under near-miscible conditions: A pore-scale study

Carbon dioxide-enhanced oil recovery (CO2-EOR) is an important means of improving oil recovery while lowering greenhouse gas emissions. However, it is still challenging to determine the pore-scale flow characteristics and interfacial interaction parameters, such as the wettability, interfacial curvature, and capillary pressure, under near-miscible conditions. In this study, X-ray microtomography (micro-CT) was used to determine the morphology of gas and oil phases and characterize the in-situ wettability under near-miscible conditions. The mean contact angle increased from 66.99° to 72.5° as the injected CO2 pore volume (PV) increased from 5.5 PV to 33.1 PV. The wettability was locally altered as the local contact angle changed from 44.14° to 107.27° because of preferential adsorption of CO2 molecules over oil molecules on solid surfaces. The mixed-wet condition was reflected by local contact angles both below and above 90°, and the capillary pressure exhibited a tower-shaped distribution with a peak value around zero, which promoted oil recovery. At the end of the displacement process, the interfaces were pushed toward the corners by a reduction in the capillary pressure, resulting in interface recession and a reduction in CO2 clusters. Pore occupancy studies showed that under near-miscible conditions, gas usually occupies large pores and oil resides in pores of varying sizes, which can result in optimal recovery.

Improved Least Squares Support Vector Machine Model Based on Grey Wolf Optimizer Algorithm for Predicting CO2–Crude Oil Minimum Miscibility Pressure

The minimum miscibility pressure (MMP) is an important reference parameter in the study of CO2 oil drive systems. In response to the problems of time‐consuming and costly prediction of MMP by conventional experimental methods, an improved least squares support vector machine (LSSVM) model based on grey wolf optimizer (GWO) algorithm is proposed to predict the CO2–crude oil MMP. Based on Pearson correlation analysis, reservoir temperature, C5+ molecular weight, intermediate component mole fraction, and volatile component mole fraction are selected as independent variables of the model, and MMP is the dependent variable. A total of 51 MMP experimental data are collected, of which 35 are used to fine‐tune the model's parameters and 16 are used to verify the model's reliability. The high leverage point method is used to detect anomalies in all experimental data to check the reliability of the model, and the abnormality of only one piece of experimental data is identified. Finally, a comparison of the model with other intelligent models is found. The absolute relative deviation of the GWO‐LSSVM model is 2.24% for the training data and 3.48% for the test data, which provides high adaptability and accuracy.

Impact of water content on minimum miscibility pressure during CO2 flooding in high water-cut reservoirs

This study focused on the X block stratum oil, specifically addressing the application of CO2 displacement technology in enhancing oil recovery under high water content conditions. It systematically investigates the variation of the minimum miscibility pressure (MMP) between CO2 and formation oil at water contents of 0%, 60%, 70%, 80%, and 90%. The research employed slim-tube model simulation experiments and theoretical analysis to explore the impact of different water contents on the physical properties of formation oil and the changes in the interaction mechanism between CO2 and crude oil. The results indicate that the MMP of CO2 flooding is the lowest at 31.11 MPa in the absence of water, reaching the highest value of 37.94 MPa at 90% water content. The MMP of the CO2-formation oil system shows a significant upward trend with increasing water content in the formation, which is related to the stability of the water film, the solubility of CO2, and the interfacial tension between oil and water. Meanwhile, high water content leads to the expansion of formation oil volume, increased viscosity, and compositional changes, collectively influencing the results. This study provides theoretical support for the field application of CO2 flooding and offers critical references for optimizing the oil displacement process.

A New Gradient-Accelerated Two-Stage Multiobjective Optimization Method for CO2-Alternating-Water Injection in an Oil Reservoir

Summary CO2-water-alternating-gas (CO2-WAG) is a reservoir development method that can simultaneously enhance oil recovery and achieve CO2 storage. However, improperly designed parameters for CO2 injection and oil production may significantly reduce the oil displacement efficiency and CO2 storage. Furthermore, optimizing the injection parameters is computationally expensive due to the high computational cost of the compositional simulation. This work aims to propose an efficient optimization method to obtain a series of well-control schemes that balance maximizing net present value (NPV) and CO2 storage for decision-makers. Given the number of CO2-WAG cycles and the duration of each cycle, we optimize the water injection rate, gas injection rate, and half-cycle for the injection well and the bottomhole pressure (BHP) for the production well. In this paper, a two-stage optimization strategy is proposed to enhance the optimization efficiency. The first stage performs the surrogate-assisted single-objective optimizations of each considered objective. It is designed to find the endpoints of the Pareto front that connect all solutions of the multiobjective optimization; this stage not only provides important search directions for the subsequent multiobjective optimization but also improves the accuracy of the surrogate model near the Pareto front. The second stage is the surrogate-assisted multiobjective optimization, which aims to find all the solutions along the Pareto front based on the Pareto endpoints obtained from the first stage. In addition, this study successfully combines the gradient of the objective functions with the meta-heuristic algorithm during the multiobjective optimization, which ensures a faster convergence to the global optimum. The proposed multiobjective optimization algorithm shows faster convergence than the conventional optimization methods when applied to the three multiobjective optimization test functions. Finally, a comparison with the conventional multiobjective optimization is conducted based on one test function and two benchmark reservoir simulation models to verify the correctness and efficiency of the proposed method. It is confirmed that the proposed method outperforms the conventional ones for the optimization of CO2-WAG injection.

Research of CO2-Soluble Surfactants for Enhanced Oil Recovery: Review and Outlook.

CO2 foam injection has been shown to be effective under reservoir conditions for enhanced oil recovery. However, its application requires a certain stability and surfactant absorbability on rock surface, and it is also associated with borehole corrosion in the presence of water. Adding surfactants to CO2 can enhance the interaction between CO2 and crude oil and control the CO2 mobility, thereby improving the performance of CO2 flooding. This paper presents a review of the research of CO2-soluble surfactants and their applications. Molecular dynamics simulation is introduced as a tool for analyzing the behavior of the surfactants in supercritical CO2 (scCO2). The applications of CO2-soluble surfactants, including CO2 thickening, reducing miscibility pressure, and generating supercritical CO2 foam, are discussed in detail. Moreover, some opportunities for the research and development of CO2-soluble surfactants are proposed.

The Environmental Curse in Oil Dependence Countries: A Missing Dimension of the Oil Curse

Objective: We build on prior studies by perhaps shedding light on the murky relationship in Oil-dependent countries. The study aims to expand the concept of the contractual oil curse and suggests another channel that may not be addressed as one of the oil curse channels. Accordingly, there remains little understanding of the oil curse by which the environmental dimension brings a new manifestation. Methods: In this study a sample of 21 oil-dependent economies were analysed from 1995-2018, using the Pooled Mean Group (PMG) and a dynamic panel technique that is heterogeneous. Results: The results empirically prove the negative influence of the connection between CO2 emissions and oil consumption. As a result, we identified a symptomatology of the oil curse via a new transmission method under the environmental domain. Depending on the transmission method, natural resources can either be a benefit or a curse. Our study found evidence supporting the concept of the oil curse taking place through the environmental channel (CO2 emissions). Conclusion: Hence, the presence of this negative relationship has a new purpose in the debate about the oil curse and its environmental impact. Policy research needs to be conducted to understand and mitigate the oil curse.

Investigation of gravity influence on EOR and CO2 geological storage based on pore-scale simulation

Gravity assistance is a critical factor influencing CO2–oil mixing and miscible flow during EOR and CO2 geological storage. Based on the Navier–Stokes equation, component mass conservation equation, and fluid property–composition relationship, a mathematical model for pore-scale CO2 injection in oil-saturated porous media was developed in this study. The model can reflect the effects of gravity assistance, component diffusion, fluid density variation, and velocity change on EOR and CO2 storage. For non-homogeneous porous media, the gravity influence and large density difference help to minimize the velocity difference between the main flow path and the surrounding area, thus improving the oil recovery and CO2 storage. Large CO2 injection angles and oil–CO2 density differences can increase the oil recovery by 22.6% and 4.2%, respectively, and increase CO2 storage by 37.9% and 4.7%, respectively. Component diffusion facilitates the transportation of the oil components from the low-velocity region to the main flow path, thereby reducing the oil/CO2 concentration difference within the porous media. Component diffusion can increase oil recovery and CO2 storage by 5.7% and 6.9%, respectively. In addition, combined with the component diffusion, a low CO2 injection rate creates a more uniform spatial distribution of the oil/CO2 component, resulting in increases of 9.5% oil recovery and 15.7% CO2 storage, respectively. This study provides theoretical support for improving the geological CO2 storage and EOR processes.

Molecular Dynamics Study on the Diffusion Mass Transfer Behaviour of CO2 and Crude Oil in Fluids Produced via CO2 Flooding.

Carbon dioxide flooding is one of the main methods used to improve crude oil recovery. It can not only improve oil recovery but also reduce greenhouse gas emissions. However, the addition of carbon dioxide makes crude oil become a more complex multiphase fluid; that is, carbon dioxide flooding-produced fluid, in which CO2 and various components in crude oil mass transfer each other. This results in significant changes in the structure and properties of crude oil that increase the hazards associated with its gathering and transportation. Therefore, it is very important to explore the microscopic mechanism for the diffusion mass transfer of CO2 and crude oil in this fluid, especially during its gathering and transportation. In this study, the diffusion mass transfer process of CO2 and crude oil in fluids produced via CO2 flooding is studied using molecular dynamics, and the influences of temperature, gas-oil ratio and water content are explored. Observations of the configuration and dynamic behaviour of the system show that after the system reaches equilibrium, the majority of the CO2 molecules are distributed at the oil-water interface, and CO2 is more prone to diffusing into the oil phase than the water phase. Increases in temperature and water content inhibit, while increases in the gas-oil ratio promote, the diffusion mass transfer of CO2 in the crude oil system. The results of this study reveal the mechanism for the diffusion mass transfer of CO2 and crude oil in fluids produced via CO2 flooding and account for the influence of the water phase, which is consistent with actual production conditions and has certain guiding significance for the safe operation of oil and gas gathering and transportation.

Effects of cosolvents on CO2 displacement of shale oil and carbon storage

Molecular dynamics method was used to establish composite wall/inorganic nanopores of three pore sizes, three shale oil systems, five CO2-cosolvent systems, and pure CO2 system. The process of CO2-cosolvent displacement of crude oil in shale nanopores and carbon storage was simulated and the influencing factors of displacement and storage were analyzed. It is shown that the attraction of the quartz wall to shale oil increases with the degree of hydroxylation. The higher the degree of quartz hydroxylation, the more difficult it is to extract the polar components of shale oil. Nanopore size also has a great impact on shale oil displacement efficiency. The larger the pore size, the higher the shale oil displacement efficiency. The closer the cosolvent molecules are to the polarity of the shale oil, the higher the mutual solubility of CO2 and shale oil. The more the non-polar components of shale oil, the lower the mutual solubility of CO2 and shale oil with highly polar cosolvent. Ethyl acetate is more effective in stripping relatively high polar shale oil, while dimethyl ether is more effective in stripping relatively low polar shale oil. Kerogen is highly adsorptive, especially to CO2. The CO2 inside the kerogen is not easy to diffuse and leak, thus allowing for a stable carbon storage. The highest CO2 storage rate is observed when dimethyl ether is used as a cosolvent, and the best storage stability is observed when ethyl acetate is used as a cosolvent.

Potential of nonionic polyether surfactant-assisted CO2 huff-n-puff for enhanced oil recovery and CO2 storage in ultra-low permeability unconventional reservoirs

Sequestering CO2 in oil reservoirs using CO2 huff-n-puff technology while maximizing oil recovery is critical for the efficient development of shale/tight reservoirs. In this work, intrinsic reasons for the limited EOR efficiency of CO2 huff-n-puff technology and the potential of a nonionic polyether surfactant C4(PO)3-assisted CO2 huff-n-puff process in further enhancing oil recovery and increasing CO2 storage capability in shale/tight reservoirs were investigated by physical modeling experiments combined with nuclear magnetic resonance techniques. The EOR performance, the mobilization of oil from different pore size ranges, and CO2 storage capability were analyzed in the CO2 huff-n-puff and CO2–C4(PO)3 mixed fluid huff-n-puff experiments. The results showed that the EOR efficiency of CO2 huff-n-puff was limited by the rapidly declining cyclic recovery and the meager recoveries from micropores and deep matrix regions. Applying CO2–C4(PO)3 mixed fluid with a surfactant concentration of 0.5 wt% resulted in a 9.7%–13.2% increase in the cumulative matrix oil recovery relative to CO2 under the same huff-n-puff cycles. Moreover, relative increases in oil recoveries from micropores, mesopores, and macropores reached 113.4%–142.2%, 14.2%–41.1%, and 0.8%–17.6%, respectively. When CO2 no longer enhanced production after the 4–5 huff-n-puff cycles, approximately 14%–19% of the residual oil was effectively recovered by applying the C4(PO)3-assisted CO2 huff-n-puff stimulation. Simultaneously, the ultimate CO2 storage capability in the examined cores increased by 22.3%–32.2% after the CO2–C4(PO)3 mixed fluid huff-n-puff process. The enhancement of CO2 injection and diffusion capabilities induced by the CO2–C4(PO)3 mixed fluid improved CO2 sweep and oil displacement efficiencies in shale/tight reservoirs, leading to a significant increase in the oil mobilization within micropores and an extended effective stimulation cycle, as well as achieving a higher CO2 storage capability. The increase of CO2 injection and diffusion amounts induced by nonionic polyether surfactants during the huff-n-puff process was attributed to the reduction in capillary resistance caused by the lowered CO2–oil interfacial tension and the increase of dissolved CO2 in oil resulting from the improved CO2–oil miscibility. This paper presents new strategies for advancing the sustainable and efficient development of shale/tight reservoirs with highly developed nanopores.

Techno-economic sensitivity assessment for supercritical CO2 extraction of lycopene from tomato processing waste

Natural lycopene is in demand by food and drug industries, and tomato processing waste (TPW) holds promise as a valuable source. Previous research investigated supercritical fluid extraction (SFE) from TPW in a techno-economic context, but lacks understanding of how technical and economic factors impact profitability. This study fills the gap by establishing a hierarchy of significance for factors affecting SFE profitability. The investigation encompasses various parameters such as static and dynamic extraction times, extractor volume, CO2 loss, project lifetime, interest rate, corporate tax rate, operator salary, cost of SFE equipment, and prices of CO2, electricity, and extract oil. The parameter boundaries are defined using well-sourced data from relevant literature. Our findings highlight that the SFE facility becomes profitable when the extractor capacity surpasses 42 L. The most influential factors on NPV include the price of the extract, the interest rate, the dynamic time of SFE, and the project lifetime.

The Determinants of Carbon Intensities of Different Sources of Carbon Emissions in Saudi Arabia: The Asymmetric Role of Natural Resource Rent

Natural resource rent (NRR) can be a blessing for the economic growth of resource-rich economies but may cause environmental problems. The present research explores the effects of NRR, economic growth, trade openness (TO), and foreign direct investment (FDI) on the carbon intensities of different sources of carbon emissions in Saudi Arabia from 1968 to 2021. The environmental Kuznets curve (EKC) is substantiated in the relationship between economic growth and the carbon intensities of gas emissions and cement emissions in the long run. The EKC is also validated in models of the carbon intensities of oil emissions, gas flaring emissions, and aggregated CO2 emissions in the short run. TO reduces the carbon intensities of oil emissions, gas emissions, and cement emissions in the long run. FDI mitigates the carbon intensity of gas flaring emissions but increases the carbon intensity of cement emissions. NRR increases the carbon intensities of all investigated sources of emissions in a linear analysis. In a nonlinear analysis, increasing NRR increases and decreasing NRR reduces the carbon intensities of all sources of emissions except aggregated CO2 emissions. In the short-run results, TO decreases the carbon intensity of gas flaring emissions and increases the carbon intensities of gas emissions and cement emissions. FDI decreases the carbon intensities of all sources of emissions. In a linear analysis, NRR reduces the carbon intensities of oil emissions and cement emissions and increases the carbon intensities of gas emissions and gas flaring emissions. In a nonlinear analysis, increasing NRR reduces the carbon intensity of cement emissions and increases the carbon intensities of gas emissions and gas flaring emissions. Moreover, decreasing NRR reduces the carbon intensities of gas emissions, gas flaring emissions, and aggregated CO2 emissions and increases the carbon intensities of oil emissions and cement emissions. The effect of NRR is asymmetrical in models of the carbon intensities of aggregated CO2 emissions, oil emissions, and gas flaring emissions and symmetrical in models of the carbon intensities of gas emissions and cement emissions.

Technology Focus: EOR Operations (November 2023)

We often see and, in some very unfortunate cases, experience ravaging wildfires, colossal floods, and scorching droughts. These “once-in-a-lifetime” climate events have become increasingly commonplace. The World Health Organization has referred to climate change as “the biggest health threat facing humanity.” The finger is often pointed at the oil and gas industry as the source of these tragic events. Indeed, according to the International Energy Agency, oil companies emit more than 5,000 million tons of CO2 every year. Even so, seeing organizations pitted against the industry and our livelihoods can be disheartening, especially because we know the other half of the story that is overlooked but cannot be understated. Oil is the bedrock on which modern society is built. The primary question remains: How can we continue to produce oil while minimizing its climate‑harming byproducts? Thanks to the ingenuity of industry professionals around the world, new technologies are emerging that allow us to achieve this goal. Using these technologies, we can simultaneously maximize CO2 sequestration and oil recovery. By using surfactant-alternating-gas or surfactant/CO2 coinjection processes, oil production and CO2 storage can be tailored to the needs of a specific reservoir, as discussed in paper SPE 212969. The same industry that produces the building blocks for life‑saving medical prosthetics can now also recycle the plastic pollutants accumulating in our landfills and oceans. Using a combination of pyrolysis, chemical functionalization, and pulverization, Janus carbon nanofluids can be mass-produced from waste plastics. Under simulated laboratory conditions, in even ultralow concentrations (0.01 wt% in brine), they can alter wettability and reduce oil/brine interfacial tension, as described in paper SPE 214799. And, while government regulations seek to limit new exploration and drilling, we now have better reservoir-management strategies and tools to continue to produce essential energy from reservoirs that are approaching their centenary. Data from the La-Sa-Xing Field in the Daqing Reservoir complex in China documents reservoir management over more than 50 years, including the maturation of polymer floods from the first small‑scale pilots in 1972 to fieldwide application, which continues to the present. A review of the field in paper SPE 215058 provides insightful guidance on well spacing, slug size, polymer chemistry, and profile modifications, among other aspects. These developments and more position the oil and gas industry as an essential player in the energy transition. Recommended additional reading at OnePetro: www.onepetro.org. SPE 212949 Kuparuk Field Reservoir Management After 40 Years by Trond B. Jensen, ConocoPhillips, et al. SPE 212958 Accurate Horizontal Well Placement in Waterflooded Field’s Drilling Project: A Case Study From Central Sumatra Basin, Indonesia by Dwiki Fimadoni, Halliburton, et al. URTeC 3870505 Design of Chemical EOR in Unconventional Reservoirs by Johannes O. Alvarez, Chevron, et al.

Study Evaluates CO2 Storage Potential During CO2 Mobility-Control Optimization

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 212969, “Evaluation of CO2 Storage Potential During CO2 Mobility-Control Optimization for Enhanced Oil Recovery,” by Alvinda Sri Hanamertani, SPE, Ying Yu, SPE, and Omar El-Khatib, SPE, University of Wyoming, et al. The paper has not been peer reviewed. _ CO2 mobility control through foam technology has enabled better sweep efficiency and, consequently, better oil productivity during enhanced oil recovery (EOR) processes. Along with enhancing oil production, a sound potential exists for in-situ generated foam to enhance CO2 storage. However, the effect of the different in-situ foam generation strategies on the combined goal of maximum oil production and carbon storage is not well elucidated in the literature. In the complete paper, the authors methodically evaluate the simultaneous optimization of CO2 storage and oil recovery using multiple injection strategies. Introduction The current investigation is a continuation of two previous studies that provided a methodology for screening and using foaming agents for optimized CO2 storage in sandstone and carbonate formations. A base case of tertiary CO2 flooding was established for comparison with in-situ foam generation by two approaches: single-cycle surfactant-alternating-gas (SAG) flooding and coinjection of CO2 and surfactant. Additionally, the effect of surfactant concentration on foam efficiency, CO2 storage capacity, and oil recovery were evaluated in both approaches at reservoir conditions. Materials and Methods Fluids and Porous Medium. In this study, a synthetic brine with total dissolved solids of 20 wt% was used as blank brine and laden with a commercial zwitterionic surfactant that was used to prepare surfactant solutions with concentrations of 0.5 and 1 wt% active matter in the synthetic brine. Three core plugs were drilled from an Indiana limestone outcrop block. The cores were then cleaned and oven-dried at 95°C. Experimental Procedure. Vacuum saturation with brine was commenced for the three cores. The porosity of the cores was calculated using their dry and brine-saturated weights. Then, the 100% brine-saturated core was placed in a core holder and loaded into an oven set to 90°C. The pore pressure was fixed at 2,000 psi, and the confining pressure was controlled at 3,000 psi throughout the flooding experiment. The brine permeability of the core samples was evaluated by measuring the pressure drop across the core at different brine-injection flow rates. In the first experiment (IL1), oil drainage with a flow rate of 0.2 cm3/min was performed to establish irreducible water saturation of 46.9%. This total flow rate was kept the same throughout the three experiments. Then, a waterflooding stage was begun and the oil recovery was recorded. After reaching a plateau in oil recovery, supercritical CO2 (scCO2) was injected during the EOR process until the oil production plateaued.

Pore-Scale Characterization of CO2 Trapping and Oil Displacement in Three-Phase Flow in a Heterogeneous Layered Sandstone

Summary Permeability variation in the vertical direction, a typical sandstone reservoir heterogeneity, can trap a large amount of oil in the low-permeability layer. We performed water-alternating-gas (WAG) injection and CO2 foam flooding on a specially constructed millimeter-sized layered sandstone and investigated fluid distribution using high-resolution X-ray microtomography. Based on the segmented images, CO2 capillary-trapping capacity, oil recovery, Euler number, shaper factor, capillary pressure, and fluid flow conductivity were calculated. Our results show that increasing the number of WAG cycles favored CO2 capillary trapping, and oil recovery was enhanced by the WAG strategy. However, there was still a significant amount of oil trapped in the low-permeability layer. After the WAG injection, the connectivity of the residual oil clusters decreased, the capillary pressure of the oil clusters increased, and oil flow conductivity decreased. This was not conducive to further oil recovery. The subsequent injection of CO2 foam effectively recovered the oil in the low-permeability layer. During the no-injection period, we observed a crossflow phenomenon caused by gravity segregation (the high-permeability layer was located below the low-permeability layer), i.e., oil in the low-permeability layer decreased while oil in the high-permeability layer increased, which is beneficial for subsequent oil production. Furthermore, CO2 moved upward driven by gravity, and although capillary barriers could prevent CO2 from escaping, subsequent water injection was essential to improve the stability of CO2 capillary trapping. This work accurately quantifies the distribution of oil and gas in high- and low-permeability layers, thus providing fundamental data for oil recovery and CO2 trapping in reservoirs with vertical heterogeneity. Although the sample used in the experiment was not natural reservoir rock, our results imply that when the permeability ratio between the two layers is greater than 2, sufficient attention must be paid to the fluid distribution differences caused by this layered heterogeneity. Different displacement strategies, such as WAG and CO2 foam flooding, or gravity differences between oil and gas can be used to enhance oil recovery.

Investigation of the Influence of Formation Water on the Efficiency of CO2 Miscible Flooding at the Core Scale

This study investigated the impact of formation water on the mass transfer between CO2 and crude oil in low-permeability reservoirs through CO2 miscible flooding. Formation water leads to water blocks, which affect the effectiveness of CO2 miscible flooding. Therefore, we studied the impact and mechanisms of formation water on the CO2-oil miscibility. The microscale interaction between formation water-CO2-core samples was investigated using CT scanning technology to analyze its influence on core permeability parameters. In addition, CO2 miscible flooding experiments were conducted using the core displacement method to determine the effects of formation water salinity and average water saturation on minimum miscibility pressure (MMP) and oil displacement efficiency. The CT scanning results indicate that high-salinity formation water leads to a decrease in the porosity and permeability of the core as well as pore and throat sizes under miscible pressure conditions. The experimental results of CO2 miscible flooding demonstrate that CO2-oil MMP decreases as the salinity of the formation water increases. Moreover, as the average water saturation in the core increases, the water block effect strengthens, resulting in an increase in MMP. The recovery factors of cores with average water saturations of 30%, 45%, and 60% are 89.8%, 88.6%, and 87.5%, respectively, indicating that the water block effect lowers the oil displacement efficiency and miscibility.

Synergistic effects of silica aerogels and SDS nanofluids on CO2 sequestration and enhanced oil recovery

This study explores the combined application of hydrophobic silica aerogels and SDS to enhance CO2 storage capacity and oil recovery. Experimental data highlighted a marked increase in CO2 solubility within silica aerogel-SDS nanofluids compared to brine and SDS solutions. Molecular dynamics simulations revealed CO2 adsorption into nanopores. Silica aerogel nanoparticles extended CO2 foam half-life by 6 % versus 62 % decline for sole SDS foam from 30 to 140 °C. Adjusting the SDS to nanoparticle ratio affects foam properties, with a ratio of 1.5 yielding optimal results. Core flooding experiments demonstrated a 75 % rise in CO2 trapping efficiency using the nanofluids over SDS solutions. Two-dimensional tests showed aerogel-SDS foam surpassed SDS foam flooding by 12 % incremental oil recovery in upper layers, attributed to enhanced profile control. The combined agents present an effective approach for geological CO2 storage and EOR optimization.

Study on the slip behavior of CO2-crude oil on nanopore surfaces with different wettability

Unconventional reservoirs are characterized by a significant amount of micro and nanopores, which pose a critical challenge in accurately assessing the microscopic fluid transport behaviors to enhance oil and gas recovery in such reservoirs. CO2 injection is a promising recovery method for unconventional resources, hence the transport mechanism of CO2-crude oil at the nanoscale deserves further exploration. In this work, the flow and transport behaviors of CO2 and multicomponent crude oil in hydrophilic, neutral, and hydrophobic nanopores were investigated by the molecular dynamics simulation (MD) method. The CO2-crude oil shows a negative slip flow on hydrophilic surfaces, while it has a slip flow on neutral and hydrophobic surfaces. By illustrating the distribution structure of each component in the fluid and the solid-liquid interaction energy, the inherent causes of the slip mechanism of different wettability surfaces were revealed. The transport capacity and permeability of CO2-crude oil in the pores with different wettability were investigated. Modifying the Hagen-Poiseuille equation based on slip characteristics can effectively improve the prediction ability of nanopore permeability. This study is helpful to understand the flow and slip behavior of CO2-crude oil in nanopores of unconventional reservoirs, which provides a theoretical basis for accurately predicting the migration of reservoir fluid in nanopores.