Oil CO2 Research Articles

Dynamics of impure CO2 and composite oil in mineral nanopores: Implications for shale oil recovery and gas storage performance

Dynamics of impure CO2 and composite oil in mineral nanopores: Implications for shale oil recovery and gas storage performance

CO2 foam structure and displacement dynamics in a Hele–Shaw cell

The substitution of CO2 gas with CO2 foam for improved mobility control has recently attracted research attentions in enhanced oil recovery (EOR) as well as aquifer and soil remediation. However, the interplay between CO2 foam properties and oil displacement remains less investigated. In this work, using clear visualizations, we systematically investigate the dynamic advection-dominated foam morphology, its corresponding viscosity, and the efficiency and dynamics of oil displacement process by CO2 foam in a Hele–Shaw cell under the effects of gas ratio (Rg), fluid injection rates (Qt), and surfactant type. Clear visualization enables particle image velocimetry to calculate actual, rather than nominal, foam velocity that significantly affects the estimated foam viscosity. Our results demonstrate that at elevated gas ratios under constant total injection rate, larger and more uniform bubbles with less number density and greater interfacial area are obtained. Increasing the injection rates leads to finer foam texture at a constant gas ratio. Different foam structures have an impact on the foam viscosity, with a general increasing trend of viscosity for larger bubbles as Rg increases from 0.5 to 0.85. The higher the foam viscosity, the more stable displacement interfaces with less viscous fingers are observed, leading to improved sweeping rates. The green surfactants (saponin + Cellulose NanoFibers) provide foams with higher viscosity and, thus, more stable displacement interfaces. These findings highlight the important effect of Rg–dependent foam structure on its viscosity, which in turn is crucial for controlling the mobility of CO2 foam to maximize oil recovery rate during EOR processes.

Numerical analysis of fluid-thermal-structure coupling characteristics of CO2 booster pump valve

CO2 booster pump valves are key components in the CO2 oil drive industry, and their reliability is critical to the safe operation of pumping booster systems. Due to the special nature of CO2, heat transfer occurs during valve movement, which can cause damage to the valve body and poppet, and thus in-depth studies on CO2 properties are needed to better predict the locations where the valve is vulnerable to damage. However, relatively few studies have been conducted to analyze the fluid-thermal-solid coupling failure of CO2 booster pump valves. This paper establishes a multi-physics coupled thermodynamic model of CO2 booster pump valves, analyzes the transient simulation of valves at different valve openings, pressures and temperatures, and investigates the thermal properties of four different poppet materials. The results show that: with the increase of valve opening, the maximum deformation of the valve decreases sharply, and then tends to stabilize; in the process of pressure increasing from 4.77 MPa to 10.52 MPa, the turbulent kinetic energy inside the valve increases by about 78 %; it is also found that the thermal deformation of different poppet materials is directly proportional to the coefficients of thermal expansion of the materials, among which the deformation of aluminum alloy poppet is the largest. In addition, the results of thermal deformation and thermal stress distribution indicate that the failure region of the valve is usually concentrated in the poppet and its corresponding body wall. These results provide theoretical references for optimizing the structural design of CO2 booster pump valves and help reduce the risk of failure of CO2 booster pump valves.

The effect of hydrocarbon prices and CO2 emission taxes on drainage strategies

Secondary recovery methods, such as water and gas injection, are effective and cost-efficient techniques for enhancing hydrocarbon recovery; however, they are highly energy-intensive, leading to a large environmental footprint. This study provides insights into the challenge of balancing high hydrocarbon demand with the imperative to reduce CO2 emissions from production by estimating how drainage strategies change under varying economic parameters and CO2 tax levels. An operator’s choice of drainage strategy is assumed to be the drainage strategy yielding the highest net present value (NPV). This paper simulates the drainage strategy of an under-saturated oil reservoir, utilizing reservoir simulations and incorporating a mathematical model that represents the production processing plant. This yields hydrocarbon production, the energy required, and the resulting CO2 emissions, all incorporated into an NPV based on hydrocarbon prices and CO2 emission taxes. The drainage strategy is then optimized to maximize NPV for various hydrocarbon prices and several levels of CO2 tax on associated emissions. The findings of this study indicate that increasing gas prices favor reducing reservoir pressure below the bubble point pressure, thereby releasing solution gas and leaving oil in the reservoir. Although lower reservoir pressure reduces the energy required for injection, the resulting increase in gas production necessitates more energy for gas compression, ultimately leading to higher emissions when gas prices rise relative to oil prices. Additionally, this study reveals that for facilities well designed for the present injection and production volumes (greenfield scenarios), the impact of CO2 tax is limited, leading to a single optimal drainage strategy. In contrast, less energy-efficient facilities (brownfield scenarios) exhibit a more pronounced need to optimize drainage strategies in response to variation in CO2 tax, and oil and gas prices. This study indicates that for fields with efficient production facilities, the ratio of gas to oil prices is more important for the drainage strategy than CO2 tax levels, as income from production tends to dominate emission taxes. This implies that hydrocarbon prices are more important for CO2 intensity than CO2 taxes, e.g., a gas price increase relative to oil price promotes higher CO2 intensity due to a shift towards more energy-intensive gas production whereas realistic tax levels for CO2 emissions have only a minor impact. Thus, increasing CO2 tax levels is mainly a measure impacting emissions from fields with inefficient production facilities.

Application of smart proxy model for multi-optimization of CO2-EOR design in farnsworth unit with production-injection well conversion

CO2-Enhanced Oil Recovery (CO2-EOR) is an effective development strategy and an economically viable CO2 storage method for a mature oil field. In this study, a smart proxy model (SPM) was constructed to establish the optimal development strategies in Farnsworth Unit (FWU) considering CO2 storage and oil production with the production-injection well conversion. An SPM was constructed with the results of 16 reservoir simulations and was validated with an R2 values of 96.3 % and 97.5 % for the CO2 storage and oil production, respectively. The obtained Pareto front indicates a range of the optimized CO2 storage and oil production. In addition, the maximum CO2 storage case shows 260 % and 61.1 % of the CO2 storage and oil production of the base case, respectively. When the maximum oil production is targeted, the CO2 storage and oil production are respectively 66.5 % and 111.3 % of the base case. It was concluded that the SPM is effectively applicable for multi-objective optimization with fewer simulation runs and shorter time. In addition, the well conversion is a viable method to improve both the CO2 storage and oil production in the FWU during CO2-EOR process.

An improved prediction model for miscibility characterization and optimization of CO2 and associated gas co-injection

Insufficient reservoir pressure and gas source problems seriously limit effective applications of CO2 flooding in hydrocarbon reservoirs. An attractive strategy is to co-inject the produced associated hydrocarbon gas with CO2 to achieve miscible/near-miscible flooding to enhance oil recovery. However, the composition of the injected mixture and the in-situ spatio-temporal composition evolution of the displacing/displaced fluids significantly affect the CO2-oil miscibility and the overall hydrocarbon recovery performance. In this work, based on slim tube simulation results, a prediction model of minimum miscible pressure (MMP)/minimum near-miscible pressure (MNMP) is established. This model takes into account the effects of CO2 concentration distribution, oil composition and temperature changes to achieve accurate spatiotemporal characterization of miscibility in the reservoir. In addition, the distribution law of the phase and components front for the impure CO2 injection process was also investigated. The miscible volume factor and recovery efficiency were used as the basis for judging the minimum injection concentration limit of CO2. The simulation results of slim tube experiment indicate that the MMP and MNMP obtained are 16.74 MPa and 12.35 MPa, respectively. Furthermore, the error caused by the traditional slim tube experiment can be reduced by using the CO2 produced fraction. It is found that CO2 injection concentration and reservoir temperature are the main factors affecting miscibility, but injection rate has less effect. Moreover, the fast migration of CH4 front leads to the shrinkage of miscible/near-miscible zone, which is not conducive to CO2 flooding. Finally, the CO2 injection concentration of non-breakthrough stage, breakthrough stage and large-scale breakthrough stage was determined to be 78.3%, 61.5% and 29.2%, respectively. This work provides strong evidence for the treatment of associated gas reinjection, which is beneficial for optimization of carbon capture, EOR-utilization and storage (CCUS-EOR) projects.

A novel dual-network CO2-responsive particle gel for mitigating CO2 channeling and leakage in hydrocarbon recovery and carbon storage

In this work, we developed and systematically evaluated a novel dual-network CO2-responsive preformed particle gel (DN-CRPPG) to address CO2 channeling and leakage in hydrocarbon recovery and carbon sequestration. The work was proven an effective effort to overcome the insufficiency of traditional channeling-control chemicals due to severe dehydration and degradation in contact with CO2. We focused on placement and plugging behavior of the DN-CRPPG in fractured reservoirs under various circumstances. Results of high-pressure vessel test show that DN-CRPPG expanded further when exposed to supercritical CO2. The responsive swelling ability was enhanced with the increase of pressure. Core flooding and plugging experiments show significantly improved CO2-channeling control ability compared with traditional non-responsive particle gels. Three key mechanisms were observed to be responsible for the improved performance. First, the CO2-responsive behavior resulted in volume swelling of DN-CRPPG. Therefore, the void spaces among the particles were occupied by the swelled gel particles, making the DN-CRPPG exhibit an in-situ self-reinforcement behavior in plugging ability. Second, the dual network structure with a relatively rigid network and a more flexible one enhances its mechanical ability and resistance to CO2 flush. Third, the CO2-repsonsiveness enabled the new gel a remarkably higher resistance to CO2 than that to water, while traditional gel is the opposite. This behavior is favorable for balancing the mobility of CO2 and water as the fact that CO2 itself is much more mobile due to low viscosities. Significant CO2 breakthrough mitigation and oil recovery improvement were demonstrated after treatment with the new gel (>30 %). This work is supposed to provide guidance for improving the success of hydrocarbon recovery and carbon storage by more effectively mitigating CO2 channeling and leakage.

Investigation of non-chemical CO2 microbubbles for enhanced oil recovery and carbon sequestration in heterogeneous porous media

Non-chemical CO2 microbubble (MB) is a promising environmentally friendly technology for enhanced oil recovery (EOR) and carbon sequestration. Understanding the interaction between non-chemical CO2 MB and oil phases in porous media is crucial for optimizing the design of CO2 MB to enhance both EOR and carbon sequestration efforts. This study explores the impact of oil on the conformance control of non-chemical MB and conducts a case study on their potential for EOR and carbon sequestration in a heterogeneous reservoir. First, experimental results reveal that MB's conformance control is impacted by the presence of oil, with varying degrees of impairment depending on oil composition. Then, reservoir simulations demonstrate that MB outperforms conventional CO2 flooding and water-alternating-gas (WAG), achieving a final recovery of 77.48% of original oil in place compared to 66.79% of original oil in place for CO2 flooding and 68.19% of original oil in place for WAG. Sensitivity analyses highlight the importance of parameters such as gas-liquid ratio of MB, reservoir heterogeneity, and reservoir thickness in MB's EOR performance. Finally, CO2 storage efficiency analyses show that MB exhibits superior CO2 storage efficiency, with higher structural and solubility trapping compared to WAG. The study concludes that MB technology holds promise for EOR and carbon sequestration, contributing to efforts toward carbon neutrality and sustainable oil recovery practices. These findings provide valuable insights for optimizing MB applications in field-scale operations and advancing toward a more environmentally sustainable energy industry.

Application of CO2-Soluble Polymer-Based Blowing Agent to Improve Supercritical CO2 Replacement in Low-Permeability Fractured Reservoirs.

Since reservoirs with permeability less than 10 mD are characterized by high injection difficulty, high-pressure drop loss, and low pore throat mobilization during the water drive process, CO2 is often used for development in actual production to reduce the injection difficulty and carbon emission simultaneously. However, microfractures are usually developed in low-permeability reservoirs, which further reduces the injection difficulty of the driving medium. At the same time, this makes the injected gas flow very fast, while the gas utilization rate is low, resulting in a low degree of recovery. This paper conducted a series of studies on the displacement effect of CO2-soluble foaming systems in low-permeability fractured reservoirs (the permeability of the core matrix is about 0.25 mD). For the two CO2-soluble blowing agents CG-1 and CG-2, the effects of the CO2 phase state, water content, and oil content on static foaming performance were first investigated; then, a more effective blowing agent was preferred for the replacement experiments according to the foaming results; and finally, the effects of the blowing agents on sealing and improving the recovery degree of a fully open fractured core were investigated at different injection rates and concentrations, and the injection parameters were optimized. The results show that CG-1 still has good foaming performance under low water volume and various oil contents and can be used in subsequent fractured core replacement experiments. After selecting the injection rate and concentration, the blowing agent can be used in subsequent fractured cores under injection conditions of 0.6 mL/min and 2.80%. In injection conditions, the foaming agent can achieve an 83.7% blocking rate and improve the extraction degree by 12.02%. The research content of this paper can provide data support for the application effect of a CO2-soluble blowing agent in a fractured core.

Interplay between economic progress, carbon emissions and energy prices on green energy adoption: Evidence from USA and Germany in context of sustainability

In contemporary times, where most academic research mainly focuses on the factors of economic and environmental sustainability and emissions reduction. Yet, very little attention has been paid to the identification of the factors of renewable energy, which requires appropriate policy-level attention. Consequently, this research investigated two developed economies, i.e., Germany and the USA, from 1991 to 2021 where, the objective of the study includes using novel and robust empirical methods to test the causal relationship between renewable energy and CO2 emissions, economic growth, technological innovations and oil prices. Using the normality and unit root estimators, this study observed that non-normal data distribution, yet all the variables are stationary. Using time-series and panel cointegration tests, the results validate the cointegration between economic growth, oil prices, carbon emission, technological innovation, and renewable energy adoption in the United States whereas Germany does not show cointegration between the variables. This study employ ‘s the Morlet-Wavelet approaches and key findings show that all these variables have a significant role in improving renewable energy adoption in both the region. Furthermore, results show a unidirectional and bidirectional causal association between the variables via the panel-stacked Granger causality test. This study recommends effective policy ramifications concerning improved investment in technological innovation, improved low-carbon production, and diverting economic growth to renewable energy transition. Use of improved new time-series method of wavelet coherence show the key contribution in this paper with new evidence of time frequency analysis on how external variables affect renewable energy consumption in developed countries of US and Germany. The objective includes understanding the effects of CO2 emissions, economic growth, technological innovations and oil prices on renewable energy which would give evidence to policy makers and environmentalists on how developed countries should improve clean energy adoption.

Study on the mechanism of CO2 huff-n-puff enhanced oil recovery and storage in shale porous media considering heterogeneous structure

CO2 possesses several advantages, including strong solubility, effective viscosity reduction ability, and low miscible pressure, making it a promising candidate for enhanced oil recovery (EOR). Additionally, due to its adsorption capture mechanism, shale formations are considered ideal environments for CO2 storage. However, the influence of heterogeneity of shale multi-scale structure on CO2 migration mechanism, EOR, and storage mechanism is not clear. In this study, a heterogeneous shale structure model containing fractures and matrix was designed based on scanning electron microscope. The multiphase–multicomponent–multirelaxation model was used to study the fluid migration mechanism in the process of miscible CO2 huff-n-puff in shale reservoir. By analyzing density variations, velocity changes, and pressure distributions, the effects of diffusion coefficient, adsorption parameters, and fracture size were studied. Furthermore, by changing the matrix structure, the influence of heterogeneity on the law of oil and gas migration was explored. Additionally, a comparison between CO2 and water was performed. Finally, the influence of reservoir heterogeneity on fluid transport mechanism was studied. The results show that EOR and CO2 storage rate (CSR) are proportional to the diffusion coefficient. The main factor affecting the CSR is the adsorption capacity of rock to CO2. The larger CO2–oil contact area between the fracture and the matrix leads to a larger CSR, highlighting the importance of induced fractures. In addition, it was found that CO2 huff-n-puff was superior to water flooding, showing an EOR performance advantage of about 15%. This study is helpful for the practical application of CO2 huff-n-puff technology in the field of unconventional oil and gas development and CO2 storage.

Experimental study on immiscible and miscible dynamic characteristics of CO2 and crude oil in visual slim tube

CO2 flooding for oil recovery is a dynamic process that requires further investigation of oil-gas interface change characteristics, interfacial mass transfer processes, and oil-gas composition variation during both immiscible and miscible displacement. Understanding these factors is crucial for better comprehending their impact on CO2-enhanced oil recovery (EOR). This research used a jointly developed CO2 miscible visual flooding experimental apparatus to study the horizontal dynamic characteristics of CO2 and crude oil under different pressures and flow rates in visual slim tube. At 10 MPa, the stratification results of CO2 and crude oil indicate that the experiment is immiscible flooding. The contact angle (7.9°) between the two phases of CO2 and crude oil at the flow rate of 15 cm/min is larger than that (5.2°) at 1.5 cm/min, and the grey scale of CO2 increases at 100 cm/min. The quantity, individual content, and shape of the light and medium hydrocarbon components condensed on the inner wall of the tube vary with different flow rates. At 15 MPa, the appearance of the CO2 and crude oil transition interval proves that the experiment is miscible flooding. At different flow rates, the inclination angle and distribution of black stripes vary. The whole transition interval is divided into 6 intervals, and the transition interval lengthens with increasing fluid velocity. The experiments visually demonstrate the occurrence of the miscible phase, and identify experimental pressure and fluid flow rate as key factors influencing the miscibility of CO2 and crude oil.

Contact Characteristics and Characterization Methods of CO2 and Crude Oil in Visual Porous Medium

In this article, the vertical static variation characteristics of CO2 and crude oil in porous medium under different experimental pressures are studied by using the CO2 miscible visual displacement device jointly developed. The process of change at the CO2 and crude oil interface is characterized by relative height and dissolution expansion rate. Experimental results demonstrate that with the increase of pressure, CO2 gradually reaches a supercritical state with strong extraction and mass transfer capacity, and CO2‐crude oil exhibits different contact forms under different pressures. Under the same pressure, there are also significant differences in contact forms between visual tube and porous medium. The existence of porous medium weakens the mass transfer and diffusion abilities between CO2 and crude oil and reduces the extraction of light components by CO2. In porous medium, the relative height of crude oil is a power function of time, which is 1/5 ≈ 3/10 of that in visual tube. And the dissolution expansion rate of CO2 and crude oil exhibits a negative logarithmic correlation with time, which is 1/4 ≈ 2/5 of that in visual tube. The impact of porous media on relative height and dissolution expansion rate of crude oil becomes more pronounced as the pressure decreases.

Synergizing shale enhanced oil recovery and carbon sequestration: A novel approach with dual lateral horizontal wells

The dual challenge of enhancing oil recovery while sequestering carbon dioxide (CO2) in oil reservoirs is a pivotal concern in the energy sector. CO2 injection is recognized for its ability to decrease oil density and viscosity, thereby improving oil mobility and recovery rates. Traditionally, efforts have been concentrated either on enhancing oil recovery (EOR) or carbon storage, but not many efforts spent to couple EOR and CO2 sequestration. Hence, novel techniques to optimize engineering designs to synergize EOR with CO2 sequestration is the best approach to maximize the opportunities of storing emission gas and contribute to the global world decarbonization goals.This study introduces an innovative dual lateral horizontal well design, aimed at simultaneously boosting oil recovery from shale reservoirs and enhancing CO2 retention. By integrating a conceptual understanding of oil recovery mechanisms with empirical data from the field, this research contrasts the proposed dual lateral design with the conventional Huff-n-Puff gas injection technique, commonly employed in shale oil formations.Our findings demonstrate that the dual lateral horizontal wells significantly outperform other injection methods in both oil recovery and CO2 storage. Upon optimization, the dual lateral injection design continues to surpass the Huff-n-Puff method in terms of CO2 storage, oil recovery, and net present value (NPV). This investigation not only presents innovative gas injection strategies in shale reservoirs but also provides insights into optimizing gas injection methods to enhance production efficiency and contribute to climate change mitigation through improved carbon capture and storage capacities.Through comprehensive numerical simulations and empirical data analysis, the study explores the optimization of well spacing, revealing that a dual lateral well with optimized spacing between 20 and 30 feet achieves the best outcomes in terms of oil recovery, CO2 retention, and net present value (NPV). The research presents a unique coupling of economic and environmental benefits, supported by economic analysis that includes the potential impact of CO2 tax credits.The novelty of this research is underscored by its integrated approach to CO2-EOR, the development of a dual lateral well design, and the optimization of well spacings for maximized efficiency. By providing a scalable solution that is both economically viable and environmentally sustainable, this research contributes a significant paradigm shift in the field of EOR and CO2 sequestration, with implications for policy and investment strategies in the energy sector. The findings propose a new direction for shale reservoir exploitation, promising to enhance production efficiency while contributing to global efforts in greenhouse gas reduction.

Effect of in-situ emulsification on CO2/N2-based cyclic solvent injection process for enhancing heavy oil recovery and CO2 storage

Surfactant-assisted CO2/N2-based CSI (SA CO2/N2-CSI) process emerges as a strategic solution to migrate the high energy consumption and carbon intensity associated with traditional thermal operations for heavy oil recovery. However, the interphase mass transfer makes the emulsification behavior in this process complex. In this study, the effect of in-situ emulsification on CO2/N2-CSI is assessed using a sandpack model and microchannel chip. Mesoscopically, SA CO2/N2-CSI outperforms conventional CO2/N2-CSI in terms of both oil recovery and CO2 storage, owing to the enhanced CO2 diffusion, oil solubilization, and foamy oil stability due to emulsification. Microscopically, the impact of emulsifier injection rate on oil removal efficiency in the dead-end pores becomes negligible when the injection rate exceeds 50 nL/min, providing insights to the emulsification mechanisms underlying the optimal pressure depletion rate (9 kPa/min) in SA CO2/N2-CSI. This study demonstrates the applicability of the SA CO2/N2-CSI in fostering sustainable heavy oil production and CO2 storage.

Shale permeability and microstructural alternation during CO2 pre-fracturing: A mechanistic study

CO2 pre-fracturing technology represents a novel approach to CO2 fracturing, effectively enhancing carbon capture efficiency in shale reservoirs while increasing the recovery of hydrocarbon resources. This study systematically quantifies the impact of water injection on the pore structure and permeability of shale samples saturated with pre-injected CO2. Based on X-ray diffraction (XRD) and low-temperature nitrogen adsorption (LT-NA) results, the dominant mechanism of the swelling-chemical coupling effect in shale property is clarified. Pre-injected CO2 can effectively mitigate the impact of water absorption. After a reaction time of 7 days, the permeability of the CO2-involved hydrated shale samples is four times that of samples without CO2. Nevertheless, the influence of subsequently injected water on shale permeability persists, resulting in an 80% reduction in shale permeability. XRD and LT-NA results indicate that the swelling-chemical coupling effect is the dominant factor in shale property variation during CO2 pre-fracturing. In the initial stage, the decline in calcite and clay mineral content is significant, and chemical dissolution dominates the change in pore structure. As the reaction progresses, the intensity of chemical reactions weakens, and clay mineral swelling becomes the primary factor affecting the shale properties. In this stage, K+ generated from original minerals effectively inhibits clay mineral swelling. Therefore, the swelling-chemical coupling effects should be comprehensively considered during the CO2 pre-fracturing process, and an appropriate soaking time should be selected to maximize CO2 storage efficiency and oil and gas production.

The Influence of Slim Tube Length on the Minimum Miscibility Pressure of CO2 Gas–Crude Oil

This study focuses on the Bozhong 25-1 oilfield formation oil as the experimental subject, systematically investigating the influence of different slim tube lengths (1 m, 12.5 m, 20 m, and 25 m) on the minimum miscibility pressure (MMP) of the CO2 and formation oil mixture system. Through slim tube experiments, the interaction process of CO2 with formation oil in slim tubes of different lengths was simulated, with a particular focus on analyzing how changes in slim tube length affect the MMP. The experiments revealed an important phenomenon: as the slim tube length gradually increased from shorter dimensions, the MMP showed a decreasing trend; when the slim tube length reached 12.5 m, this trend stabilized, meaning that further increasing the slim tube length no longer led to significant changes in the MMP, with its stable value determined to be 27.86 MPa. This phenomenon can be explained within the theoretical framework of fluid dynamics and interfacial science, where several key factors play a significant role. Firstly, the flow characteristics of the fluid inside the slim tube significantly influence it; secondly, the interfacial tension between phases is also a decisive factor; lastly, the impact of the internal microstructure of the slim tube cannot be overlooked. These aspects together form the basis for understanding the impact of slim tube length on MMP and reveal the underlying mechanisms. This research is significant for deeply understanding and quantifying this effect, providing a solid theoretical basis for optimizing CO2 flooding technology and guiding more precise operational strategies in oilfield development practices to enhance oil displacement efficiency and economic benefits.

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.