Search

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. [ABSTRACT FROM AUTHOR]

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 simulationsscCO2 can collapse the oil film and channel out a path for CO2 diffusionWater exhibits a negative impact on oil film detachment by scCO2 [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

Inefficient recovery of fracturing fluid leaves much chemical residual (containing polymer friction reducer) in microfractures, which is closely related to relative permeability near fracture, flowback of fracturing fluid, production rate, etc. This work was to investigate rock damage associated with fracturing fluid filtration and its effect on subsequent oil and water flow behavior. First, fracturing fluid filtration test was performed under different core permeability and polymer friction reducer concentration conditions. Second, fractured tight sandstone models were fabricated with different fracture widths. Oil or brine was injected at various velocities before and after fractured tight sandstone models were fluxed with fracturing fluid, and residual resistance factors to oil ( F rr,oil ) and brine ( F rr,brine ) were specified with different fracture widths and polymer friction reducer concentrations. Experimental results showed that core damage occurred and polymer chains were trapped or adsorbed in rock matrix. Higher polymer friction reducer concentration would aggravate core damage in a lower permeability core sample. Residual resistance factor to brine and oil decreased as shear rate increased, and their relationship could be well fitted with a power-law equation. F rr,brine was always larger than F rr,oil , which revealed non-recovered fracturing fluid could selectively reduce the permeability to water more than to oil in microfractures. The reason behind it was elucidated by polymer wall effect. At the same shear rates, smaller fractures presented larger residual resistance factors. Besides, chemical residual grew with an increase in friction reducer concentration, resulting in a higher resistance to fluid flow. This study could provide a constructive guide for flowback after fracturing operations and the development of fracturing fluid. [ABSTRACT FROM AUTHOR]

Universal existence of the filled vug and fracture in carbonate fractured-vuggy reservoir upgrades the complexity of fluid flow as the coexistence of free flow and porous flow. The highly discrete distribution of fracture and vug makes it possible to apply Dykstra-Parsons method in this kind of medium. A modification of Dykstra-Parsons method is proposed to depict the displacement in fracture-vug system, which consists of multiple non-communicating fracture-vug units with each containing fracture, fills, and vug. The displacement front advance equation is derived piecewise corresponding to the position of the front in fracture, fills, and unfilled vug of one unit. The solution to this equation for every fracture-vug unit is used to estimate the production dynamics of the fracture-vug system, including the fractional oil recovery, the water cut, the injected pore volume, and the injectivity ratio. A calculating example with log-normal distribution for fracture aperture is involved to make the sensitivity analysis of gravity number, viscosity ratio, fills properties, and variation of the fracture aperture. In terms of increased oil recovery, decreased water cut, and delayed water breakthrough, it was found that a better performance reached in the condition of weak heterogeneity of fracture, large gravity number, and lower oil//water viscosity ratio; the fills with low permeability and high filling degree is favorable when all vugs are filled identically. [ABSTRACT FROM AUTHOR]

Tahe oil field is a fractured-vuggy carbonate oil field in China. The fluid flow behaviors in this type of reservoir are complex due to multiple flow paths through the matrix, fractures and vugs. The main challenges of production include complicated oil-water distributions, rising state of water cone in different flow units, unclear multiphase flow behaviors, and lack of understanding of the fluid flow mechanism. Based on a geological map of the Tahe oil field, a physical 3-D fractured-vuggy model was designed and fabricated. Water and gas flooding experiments were performed, while the multiphase flow behaviors were captured with a high-resolution camera system. The pressure response was also monitored at different oil displacement stages. The results show that the 3-D physical model can be used to systematically and comprehensively investigate the fluid flow behaviors during the oil displacement process. The oil-water interfaces of prolific wells rise more rapidly than that from the stripper wells, leading to an uneven distribution of internal flow fields and cross-well interferences. Water breaks through early and water channeling is more significant in fractured than vuggy wells. The oil-water flow behavior in fractured-vuggy combinations is mainly determined by fractured-vuggy structure, viscous force, wettability, and the ratio of displacement forces to gravity. During nitrogen gas flooding, gas caps occur from gas displacing the remaining oil at the top of the reservoir. The synergistic interaction between nitrogen gas and injected water contributes to additional oil recovery. This study provides a guide for improving production performance in fractured-vuggy carbonate reservoirs. [ABSTRACT FROM AUTHOR]

Fractures and heterogeneity commonly exist in ultra-low permeability reservoirs, which will cause serious gas channeling phenomena and lead to poor oil recovery during CO 2 immiscible flooding. CO 2 water alternating gas (WAG) flooding combined with gas channeling control treatments are recognized as effective approaches to enlarge the sweep efficiency of CO 2 . Performance of gel systems were evaluated to screen out a high-strength gel which can be utilized as fracture blocking agent. Then, performance of small molecule amines were evaluated to screen out a kind of small molecule amine which can be utilized as rock-matrix blocking agent. Performance evaluation results showed that high-strength gel with 8% modified starch + acrylic amide, 0.05% crosslinking agent, 0.15% initiator and 0.15% stabilizer could be served as fracture blocking agent, while etheylenediamine was proposed as rock-matrix blocking agent which could react with CO 2 and generate solid particles to improve the heterogeneity of the reservoirs. To examine gas channeling control effect in actual reservoir conditions, a 3D radial flow model with complex fractures and heterogeneity was designed according to the actual oilfield, and five-spot pattern was employed in the model. Waterflooding, continuous CO 2 flooding, and gas channeling control using high-strength gel, etheylenediamine and CO 2 WAG flooding were conducted successively in the 3D radial flow model. After a series of treatments, the oil recovery was enhanced by 15.09%, which was significant for CO 2 immiscible flooding in the field application. The gas channeling along major fracture and microfractures of the model was effectively controlled by high-strength gel, while fluid diversion could occurred after ethylenediamine injection due to the solid particles which could mitigate gas channeling along relatively high permeability areas of the rock-matrix, and the gas channeling phenomena can be further mitigated by the mobility control ability of CO 2 WAG flooding. [ABSTRACT FROM AUTHOR]

Most of major oilfields in China have reached high water cut stage, but still, they contribute to more than 70% of domestic oil production. How to extract more oil from mature oilfields has become a hot topic in petroleum engineering. Carbon dioxide flooding is a win–win strategy because it can enhance oil recovery and simultaneously reduce CO 2 emissions into the atmosphere. In order to evaluate the potentials of CO 2 flooding in high water cut oil reservoirs, various 3-D heterogeneous geological models were built based on Guan 104 fault block in Dagang Oilfield to perform reservoir simulations. The D-optimal design was applied to build and verify the Rapid Assessment Model of CO 2 flooding in high water cut oil reservoirs. Five quantitative variables were considered, including average horizontal permeability, permeability variation coefficient, ratio of vertical to horizontal permeability, net thickness of formation and percentage of recoverable reserves by water flooding. The process of weighting emphasized the contributions of linear terms, quadratic terms and first-order interactions of five quantitative parameters to improved recovery factor and Net Present Value of CO 2 flooding. Using the Rapid Assessment Model of CO 2 flooding in high water cut oil reservoirs, significant first-order interactions were sorted out and type curves were established and analyzed for the evaluation of technical and economic efficiency of CO 2 flooding in high water cut oil reservoirs. Aimed at oil reservoirs with the similar geological conditions and fluid properties as Guan 104 fault block, the Rapid Assessment Model and type curves of CO 2 flooding in high water cut oil reservoirs can be applied to predict improved recovery factor and Net Present Value of water-alternating-CO 2 flooding at different conditions of reservoir parameters and development parameter. The approach could serve as a guide for the application and spread of CO 2 -EOR projects. [ABSTRACT FROM AUTHOR]

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%. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

The technical feasibility of using organic alkali instead of an inorganic one during alkaline/surfactant/polymer (ASP) flooding in a heterogeneous reservoir under a high temperature of 95 °C in China was investigated. Laboratory experiments were performed to evaluate the alkali consumption, adsorption, and retention in formation and its formation damage. Also viscosity of the ASP compound flooding system, oil/water interfacial tension, and chromatographic separation were investigated. A comparison of results obtained through organic alkali with those obtained from inorganic alkali was conducted to evaluate the flooding effect of this system, and the mechanism of increasing recovery ratio was analyzed. Experimental results indicated that the consumption and dynamic adsorption of ethanolamine and formation damage observed through the organic alkali were significantly lower than those observed through the inorganic alkali. When compounded with the surfactant, ethanolamine could further decrease the oil/water interfacial tension. Moreover, ethanolamine exerted a protective effect on the surfactant, thereby decreasing adsorption loss. A flooding experiment with a 5-spot pattern was performed on a heterogeneous reservoir. Findings revealed that the organic ASP (OASP) compound flooding system achieves good displacement effects and mobility control even under high temperature conditions and significantly improved recovery ratios. As such, the proposed method is feasible for compound flooding in high-temperature reservoirs. The mechanism of OASP compound flooding was discussed to provide a theoretical basis for optimizing compound flooding systems for high-temperature heterogeneous reservoirs. [ABSTRACT FROM AUTHOR]

Multi-thermal fluid is a new heat-carrier proposed in decades. This paper introduces multi-thermal fluid into the thermal recovery process of thick heavy oil reservoir (THOR). First, using the method of physical simulation, the superiority of multi-thermal fluid is investigated from the Pressure–Volume–Temperature (PVT) performance and displacing characteristics. Thereafter, based on multi-thermal fluid injection technology and steam-assisted-gravity-drainage (SAGD) theory, a new Improved-Oil-Recovery technique for THORs, Multi-thermal Fluid Assisted Gravity Drainage (MFAGD) technique is proposed in this paper. Applying the dimensionless scaling criterion of gravity-drainage process, two 3D gravity-drainage experiments (SAGD, SAGD-to-MFAGD) are conducted. Thus, the enhanced-oil-recovery (EOR) mechanisms of multi-thermal fluid in heavy oil reservoirs are analyzed, and the thermal recovery performance of MFAGD process is discussed. Results indicate that compared with SAGD process, MFAGD process has a higher recovery rate, and it could further improve the gravity-drainage effect in THOR. Besides the conventional operation of SAGD, the EOR mechanisms of MFAGD technique also include heat insulation, energy recovery, gas dissolution and auxiliary cleanup of non-condensable gas. This method technologically supports the effective and efficient development of THORs. [ABSTRACT FROM AUTHOR]

• Alkylamine modified MoS 2 nanosheets are promising for enhanced oil recovery. • MoS 2 nanosheets alter the wettability of the core even at very low concentrations. • Residual oil recovery of 21.18% was obtained at 0.005 wt% of MoS 2 nanofluid. • MoS 2 can recover even heavy oil from low-permeability cores. Chemical enhanced oil recovery (C-EOR) agents, such as polymer and surfactants, have been used to recover residual oil from reservoirs. The investigation for finding more efficient and more economic agents has never been stopped. Here, we demonstrate the potential of two-dimensional MoS 2 nanosheets as a C-EOR agent. The synthesized amphiphilic MoS 2 nanosheets function as a surfactant by altering the wettability of the core even at very low concentrations. The laboratory core flooding experiments were performed in the man-made core samples with various permeabilities in range of 2.5–2500 mD saturated with crude oil (100 cP) and model oil (25 cP). The brine with the salinity of 98,171 mg/L is used for secondary flooding and nanofluid containing 0.005 wt% of nanosheets is used for tertiary flooding. We observe 21.18% and 18.25% of residual oil is recovered during tertiary flooding in 25 mD core samples saturated with model and crude oil respectively. This work reveals the new possibilities for economical production of oil using nanosheet based materials. [ABSTRACT FROM AUTHOR]

CO 2 flooding is a promising technology used to enhance oil recovery as it increases oil production and sequesters CO 2 in low permeability oil reservoirs. However, the areal heterogeneity of a reservoir can seriously affect CO 2 flooding efficiency. The importance of production control treatments (sweeping area regulation, differential production pressure control, and real-time producing regulation) are thus proposed to improve the performance of CO 2 flooding in areal heterogeneous reservoirs. Three dimensional (3D) physical models and core-scale numerical models with areal heterogeneity and 5-spot patterns are designed using dimensionless scaling groups. Conventional CO 2 flooding and CO 2 production control flooding are conducted successively in the 3D models, and flooding efficiency is evaluated through oil recovery increments and changes in the displacement pressure drop curves. Mechanisms of CO 2 performance improvement using production control treatments are also discussed through the analytical analysis of gas distribution and gas/oil mobility ratio. 3D experimental and numerical simulation results show that CO 2 is displaced unevenly in the areal heterogeneous reservoir, leaving plenty of oil in the area of relatively low permeability. However, oil recovery of CO 2 flooding in the areal heterogeneous reservoir can be doubled using production control treatments (sweeping area regulation, differential pressure control, or real-time producing regulation). The oil remaining in the area of relatively low permeability can be effectively displaced using sweeping area regulation, and both a larger sweeping area and a better CO 2 flooding profile can be obtained using differential pressure control and real-time producing regulation. Through the analytical analysis of gas distribution and gas/oil mobility ratio, it is found that gas/oil mobility ratio is more sensitive to the areal heterogeneity, and real-time producing regulation has a powerful mobility control ability for CO 2 -EOR. Improvements in the performance of CO 2 flooding using production control treatments provide a feasible technical strategy to treat with the areal heterogeneity and enhance the oil recovery for 5-spot well patterns in the areal heterogeneous reservoir. [ABSTRACT FROM AUTHOR]

• A comprehensive literature review was conducted on CO 2 -EOR in tight oil reservoirs. • Specialized technologies are needed in the exploitation of China's tight reservoirs. • The effect of CO 2 diffusion is relatively exaggerated in experimental results. • CO 2 -crude oil interaction in nanopores may lead to an oil recovery increment. • CO 2 -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 CO 2 enhanced oil recovery (CO 2 -EOR) potential in tight reservoirs; however, some results conflict with each other. The objectives of this paper are to fully understand the CO 2 -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 CO 2 -oil contact. The effect of CO 2 molecular diffusion is relatively exaggerated in experimental results, which can be attributed to the dual restrictions of exposure time and oil-CO 2 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. CO 2 -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 CO 2 -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 CO 2 -EOR. [ABSTRACT FROM AUTHOR]

Emulsions, including oil-in-water (O/W) and water-in-oil (W/O) emulsions, can play important roles in both controlling reservoir conformance and displacing residual oil for enhanced oil recovery (EOR) projects. However, current methods, like high-shear mixing, high-pressure homogenizing, sonicators and others, often use lots of extra energy to prepare the emulsions with high costs but very low energy efficiency. In recent decades, spontaneous emulsification methods, which allow one to create micro- and nano-droplets with very low or even no mechanical energy input, have been launched as an overall less expensive and more efficient alternatives to current high extra energy methods. Herein, we primarily review the basic concepts on spontaneous emulsification, including mechanisms, methods and influenced parameters, which are relevant for fundamental applications for industrials. The spontaneity of the emulsification process is influenced by the following variables: surfactant structure, concentration and initial location, oil phase composition, addition of co-surfactant and non-aqueous solvent, as well as salinity and temperature. Then, we focus on the description of importance for emulsions in EOR processes from advances and categories to improving oil recovery mechanisms, including both sweep efficiency and displacement efficiency aspects. Finally, we systematically address the applications and outlooks based on the use of spontaneous emulsification in the practical oil reservoirs for EOR processes, in which conventional, heavy, high-temperature, high-salinity and low-permeability oil reservoirs, as well as wastewater treatments after EOR processes are involved. Unlabelled Image • Mechanisms, methods and influenced parameters for spontaneous emulsification are summarized. • Emulsion-based techniques for EOR are addressed based on displacement and sweep efficiencies. • Insightful applications and outlooks on spontaneous emulsification for EOR process in practical oil reservoirs are proposed. [ABSTRACT FROM AUTHOR]