•A comprehensive literature review was conducted on CO2-EOR in tight oil reservoirs.•Specialized technologies are needed in the exploitation of China’s tight reservoirs.•The effect of CO2 diffusion ...is relatively exaggerated in experimental results.•CO2-crude oil interaction in nanopores may lead to an oil recovery increment.•CO2-water-minerals interaction influences the geomechanical properties of rock.
Primary oil recovery remains less than 10% in tight oil reservoirs, even after expensive multistage horizontal well hydraulic fracturing stimulation. Substantial experiments and simulation works have been performed to investigate CO2 enhanced oil recovery (CO2-EOR) potential in tight reservoirs; however, some results conflict with each other. The objectives of this paper are to fully understand the CO2-EOR mechanisms and to figure out the difference between tight oil exploitation in North America and China through a comprehensive literature review. It is shown that compared with Bakken and Eagle Ford formation, China’s tight oil reservoirs feature higher mud content and oil viscosity while they have a lower brittleness index of rock and formation pressure coefficient, leading to confined stimulated reservoir volume and further limited CO2-oil contact. The effect of CO2 molecular diffusion is relatively exaggerated in experimental results, which can be attributed to the dual restrictions of exposure time and oil-CO2 area in field scale. Numerical simulation works show that the shifted phase properties in nanopores lead to an oil recovery increment. The development of nano-scale chips withholding high pressure/temperature may advance the experimental study on the nanopore confinement effect. CO2-fluid-rock minerals interaction might be more complex due to the large specific surface area of nanopores in tight formations. The geomechanics coupling effect cannot be ignored when examining the CO2-EOR performance in tight reservoirs. And a comprehensive simulation study coupling with technical and economic feasibility is highly recommended before running a field test of CO2-EOR.
Geochemical reactions are crucial for in situ CO2 mineralization underground associated with CO2‐enhanced oil recovery (CO2‐EOR) in a hydrocarbon reservoir. However, the presence of formation water ...and adsorbed oil on rocks generates physical barriers to CO2's access to mineral surfaces, which may yield impedance to CO2 mineral trapping that has yet to be accounted for. In this study, we mimic the dynamic oil detachment process using molecular dynamic (MD) simulation and analyze the influence of an adsorbed oil film on supercritical CO2 (scCO2) diffusion toward the mineral surface in the presence and absence of a water phase. Our results demonstrated a negative impact of water on oil film detachment by scCO2, which may weaken mineral reactions and is unfavorable for mineralized CO2 storage underground.
Plain Language Summary
Carbon dioxide emission has been identified as one of the primary factors influencing global climate change. Storing CO2 underground while enhancing oil recovery is a promising technology that can effectively reduce costs for carbon capture, utilization, and storage (CCUS). Mineral trapping, that is, converting CO2 to carbonate minerals through CO2‐water‐mineral surface reactions, is one of the major mechanisms for CO2 storage. However, residual oil adsorbed on rock surfaces after CO2 injection into an oil reservoir yields a physical barrier for CO2 approaching mineral surfaces. CO2‐water‐oil‐mineral interactions have yet to be thoroughly understood. Therefore, we conducted a series of molecular dynamics simulations to mimic the dynamic oil detachment process and unveil the impact of water on oil film detachment by supercritical CO2. We found that the presence of water strengthens the interactions between the oil and rock surface, which may give rise to a substantial delay in oil film detachment and weaken mineral reactions. Our results provide significant implications for the mineralized storage of CO2 in a depleted oil reservoir and CO2‐enhanced oil recovery and its consequent sequestration.
Key Points
CO2‐water‐oil‐rock interactions are investigated using molecular dynamics simulations
scCO2 can collapse the oil film and channel out a path for CO2 diffusion
Water exhibits a negative impact on oil film detachment by scCO2
This work focuses on the development of a novel high-temperature microemulsion for enhanced oil recovery in tight oil reservoirs. Microemulsions are a type of mixture that has properties of both ...liquids and solids; they have shown significant potential for improving oil recovery through spontaneous imbibition. Herein, a high-temperature-tolerant lower-phase microemulsion using a microemulsion dilution method was developed. The properties and morphological characteristics of the microemulsion were evaluated and proposed a mechanism for enhanced spontaneous imbibition oil recovery using imbibition tests and CT scanning technology. The results of the study showed that the optimum concentration of the microemulsion was 0.2 wt% and that it had good thermal stability, small droplet size, lower interfacial tension, good wettability alteration ability, and minimum adsorption loss. The imbibition and CT experiments demonstrated that the reduction in oil/solid adhesion was due to the synergistic effect of IFT reduction and wettability alteration and the ability to increase the imbibition distance through a larger self-driving force. The study concludes that the solubilization coefficient and self-driving force were defined and calculated to quantitatively analyze the imbibition mechanisms and the results showed that the reduction in oil/solid adhesion was due to the synergistic effect of IFT reduction and wettability alteration and the ability to increase the imbibition distance through a larger self-driving force.
Gas flooding and foam flooding are potential technologies for tertiary oil recovery in fractured-vuggy reservoirs. The development and mechanism research of fractured-vuggy reservoirs is difficult ...due to the complex structures and the strong heterogeneity of fractured-vuggy reservoirs. Visualization simulation is one of the effective methods to study the flow behavior of fluid in fractured-vuggy reservoirs. In this study, an upscaling method of visualization simulation from one dimension (1D) to three dimensions (3D) was established, and the physical models of fractured-vuggy reservoirs were designed and fabricated. Water flooding, gas flooding, and gel foam flooding were carried out in the models. The experimental results showed that gas flooding has a single flow channel and water flooding has multiple flow channels in fractures and vugs. Gel foam with an excellent capability of mobility control and a high microscopic displacement efficiency swept in all directions at a uniform velocity. The EOR mechanisms of gel foam in fractured-vuggy reservoirs were mainly as follows: reducing interfacial tension, increasing mobility ratio, selectively plugging high permeability channels, and discontinuous flow. In the displacement process of fractured-vuggy reservoirs, water should be injected from the well at the bottom of the reservoir, and gas should be injected from the well located in the vug at the high part of the reservoir. Gel foam with strong stability and high viscosity should be selected and injected in most kinds of injection wells in fractured-vuggy reservoirs. This study provides a complete method of visualization simulation for the study of flow behavior in fractured-vuggy reservoirs and provides theoretical support for the application of gas flooding and gel foam flooding in fractured-vuggy reservoirs.
Polymer flooding is an effective development technology to enhance oil recovery, and it has been widely used all over the world. However, after long-term polymer flooding, a large number of oilfields ...have experienced a sharp decline in reservoir development efficiency. High water cut wells, serious dispersion of residual oil distribution and complex reservoir conditions all bring great challenges to enhance oil recovery. In this study, the method of enhancing oil recovery after polymer flooding was studied by taking the S Oilfield as an example. A surfactant–polymer system suitable for high-permeability heterogeneous oilfields was developed, comprising biogenic surfactants and polymers. Microscopic displacement experiments were conducted using cast thin sections from the S Oilfield, and nuclear magnetic resonance was employed for core displacement experiments. Numerical simulation experiments were also conducted on the S Oilfield. The results show that the enhanced oil recovery mechanism of the surfactant–polymer system is to adjust the flow direction, expand the swept volume, emulsify crude oil and reduce interfacial tension. Surfactant–polymer flooding proves to be effective in improving recovery efficiency, significantly reducing the time of flooding and further enhancing the strong swept area. The nuclear magnetic resonance results indicate a high amplitude of passive utilization of residual oil during the surfactant–polymer flooding stage, highlighting the enormous potential for an increased recovery ratio. Surfactant–polymer flooding emerges as a more suitable technique to enhance oil recovery in the post polymer-flooding stage in high-permeability heterogeneous oilfields.
Lower-phase microemulsions with core-shell structure were prepared by microemulsion dilution method. The high temperature resistant systems were screened and the performance evaluation experiments ...were conducted to clarify the spontaneous imbibition mechanisms in ultra-low permeability and tight oil reservoirs, and to direct the field microfracture huff and puff test of oil well. The microemulsion system (O-ME) with cationic-nonionic surfactant as hydrophilic shell, No.3 white oil as oil phase core has the highest imbibition recovery; its spontaneous imbibition mechanisms include: the ultra-low interfacial tension and wettability reversal significantly reduce oil adhesion work to improve oil displacement efficiency, the nanoscale “core-shell structure” formed can easily enter micro-nano pores and throats to expand the swept volume, in addition, the remarkable effect of dispersing and solubilizing crude oil can improve the mobility of crude oil. Based on the experimental results, a microfracture huff and puff test of O-ME was carried out in Well YBD43-X506 of Shengli Oilfield. After being treated, the well had a significant increase of daily fluid production to 5 tons from 1.4 tons, and an increase of daily oil production to 2.7 tons from 1.0 ton before treatment.
Tahe Oilfield, located in northwest China, is an unconventional fracture–vuggy carbonate reservoir. The foam-assisted nitrogen gas flooding technology has been proven to be a potential EOR ...technology. However, the flow behaviors of foam-assisted nitrogen gas in fracture–vuggy structures are not clear due to the complex fracture–vuggy structures and their strong heterogeneity. In this work, a three-dimensional visualized fracture–vuggy model is designed and fabricated to investigate the fluids behaviors of foam-assisted N2 flooding and classify the residual oil types after foam-assisted N2 flooding. Experimental results reveal that foam slug can enlarge the sweep efficiency, suppress the formation of nitrogen gas channeling, and detach the oil film. Additionally, the evolution processes of the gas–oil and oil–water interfaces are investigated and analyzed. Moreover, the residual oil types after foam-assisted N2 flooding and nitrogen gas flooding, respectively, are classified and summarized. Compared to nitrogen gas flooding after water flooding, 12.36% more oil can be recovered through foam-assisted N2 flooding. This work further studies the fluid flow behaviors of foam-assisted N2 in the three-dimensional visualized fracture–vuggy carbonate model and also confirms the previous achievements.
Fines migration induced by injection of low-salinity water (LSW) into porous media can lead to severe pore plugging and consequent permeability reduction. The deep-bed filtration (DBF) theory is used ...to model the aforementioned phenomenon, which allows us to predict the effluent concentration history and the distribution profile of entrapped particles. However, the previous models fail to consider the movement of the waterflood front. In this study, we derive a stochastic model for fines migration during LSW flooding, in which the Rankine-Hugoniot condition is used to calculate the concentration of detached particles behind and ahead of the moving water front. A downscaling procedure is developed to determine the evolution of pore-size distribution from the exact solution of a large-scale equation system. To validate the proposed model, the obtained exact solutions are used to treat the laboratory data of LSW flooding in artificial soil-packed columns. The tuning results show that the proposed model yields a considerably higher value of the coefficient of determination, compared with the previous models, indicating that the new model can successfully capture the effect of the moving water front on fines migration and precisely match the effluent history of the detached particles.
With the gradual declining of oil increment performance of CO2 huff-and-puff wells, the overall oil exchange rate shows a downward tendency. In this regard, CO2 synergistic huff-and-puff technologies ...have been proposed to maintain the excellent effect and extend the technical life of such wells. However, there is no specific research on the mechanism and synergistic mode of CO2 huff and puff in horizontal wells. This study aims to establish the synergistic mode and determine the adaptability and acting mechanism of CO2 synergistic huff and puff. Three synergistic huff-and-puff modes are proposed based on the peculiarity of the fault-block reservoir’s small oil-bearing area and broken geological structure. We establish three typical CO2 synergistic huff-and-puff models and analyze the influence of different geological and development factors on the huff-and-puff performance with numerical simulation. Each factor’s sensitivity is clarified, and the enhanced oil recovery (EOR) mechanism of CO2 synergistic huff and puff is proposed. The sensitivity evaluation results show that the reservoir rhythm, inter-well passage, well spacing, high-position well liquid production rate, and middle-well liquid production rate are extremely sensitive factors; the stratum dip and injection volume allocation scheme are sensitive factors; and the relationship with structural isobaths is insensitive. The EOR mechanism of synergistic huff and puff includes gravity differentiation, supplementary formation energy, CO2 forming foam flooding, and coupling effect of production rate and oil reservoirs. The implementation conditions of the two-well cooperative stimulation mode are the simplest. The two-well model is suitable for thick oil layers with a positive rhythm and large formation dip. The single-well mode requires no channeling between the wells, and the multi-well mode requires multi-well rows and can control the intermediate well’s fluid production rate. Field application at C2X1 block shows a good performance with a total oil increment of 1280 t and an average water-cut reduction of 57.7%.
CO2 and N2 injection is an effective enhanced oil recovery technology in the oilfield especially for low-permeability and extra low-permeability reservoirs. However, these processes can induce an ...asphaltene deposition during oil production. Asphaltene-deposition-induced formation damage is a fairly severe problem. Therefore, predicting the likelihood of asphaltene deposition in reservoir conditions is crucial. This paper presents the results of flash separation experiments used to investigate the composition of crude oil in shallow and buried-hill reservoirs. Then, PVTsim Nova is used to simulate the composition change and asphaltene deposition of crude oil. Simulation tests indicate that the content of light components C1-C4 and heavy components C36+ decrease with increasing CO2 and N2 injection volumes. However, the extraction of CO2 is significantly stronger than that of N2. In shallow reservoirs, as the CO2 injection volume increases, the deposition pressure range decreases and asphaltenes are easily deposited. Conversely, the asphaltene deposition pressure of crude oil injected with N2 is higher and will not cause serious asphaltene deposition. When the CO2-N2 injection ratio reaches 1:1, the deposition pressure range shows a significant transition. In buried-hill reservoirs, asphaltene deposition is unlikely to occur with CO2, N2, and a gas mixture injection.
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