Jingchun Wu

Aiming at the characteristics of high viscosity and poor fluidity of high waxy ordinary heavy oil, a Janus silica-based nanosheet composite viscosity reducer was designed and prepared in this paper. The viscosity reducer was assembled by asymmetric Gemini viscosity reducer and silica nanosheets through dehydration condensation reaction, and its structure was verified by FT-IR, ¹HNMR, XPS and DLS. The viscosity reduction performance, emulsion stability, interfacial tension and flow performance of the viscosity reducer were systematically evaluated by taking heavy oil with wax content of 35.7% and viscosity of 237 mPa·s at 30 °C as the research object. The results showed that, at an oil-to-viscosity-reducer-solution volume ratio of 3:7 and a viscosity reducer mass fraction of 0.3%, the maximum viscosity reduction rate reached 94.5% at 30 °C, calculated relative to the viscosity of the dehydrated original heavy oil. The oil–water interfacial tension was significantly reduced, and the 24 h bleeding ratio, defined as the volume percentage of separated water relative to the initial aqueous phase volume, was only 7.3%, indicating good emulsion stability. The core flow experiment shows that the resistance coefficient is reduced to the lowest at 0.3% concentration, and the seepage capacity is significantly improved. The analysis of total hydrocarbon gas chromatography showed that the content of high-carbon wax components in the C₂₃-C₃₀ range decreased by 4.79 percentage points after treatment, indicating that the viscosity reducer preferentially interacted with high-carbon wax molecules and promoted wax-crystal dispersion, thereby weakening the three-dimensional wax-crystal network. The viscosity reducer has the synergistic effect of dispersing wax crystals, reducing interfacial tension and stabilizing emulsification, which provides a low-cost and high-performance technical approach for the efficient exploitation of high waxy ordinary heavy oil.

To address gas channeling, low sweep efficiency, and water sensitivity in CO₂ flooding of shale reservoirs, amidine-functionalized graphene quantum dots (FN-GQDs) were synthesized via amidation of citric acid-derived GQDs. FTIR and UV-Vis confirmed successful grafting. Conductometric titration showed an optimal reaction time of 24 h with a grafting ratio of 58%, in good agreement with the 60% saturation predicted by molecular dynamics simulation. Upon CO₂ introduction, protonation of amidine groups induced a nonlinear viscosity increase from 0.298 to 2.0 mPa·s at 0.02 wt% via electrostatic attraction and hydrogen bonding, forming a dynamic crosslinking network. FN-GQDs maintained low oil-water interfacial tension of 0.12–0.25 mN/m at 80–120 °C and rapidly reversed rock wettability from strongly oil-wet to water-wet, reducing the contact angle from 141.7° to 38.9° within 80 min. The positively charged surface inhibited clay swelling, achieving 92% at 0.20 wt%. Core flooding and NMR T₂ spectra revealed that alternating CO₂ and FN-GQDs injection at a 2:1 gas–water ratio achieved a final oil recovery of 52.5%, significantly higher than pure CO₂ flooding. Through synergistic effects of interfacial tension reduction, wettability alteration, viscosity enhancement, and anti-swelling, FN-GQDs improve microscopic displacement efficiency and macroscopic sweep volume, showing great potential for CO₂-enhanced oil recovery in shale reservoirs.

Background: Strongly water-sensitive reservoirs with high clay content face challenges in conventional development due to clay swelling and impeded seepage. CO₂ injection shows potential for enhanced oil recovery (EOR) and carbon sequestration; however, the role of clay minerals in regulating CO₂-induced asphaltene deposition and sequestration remains unclear. Methodology: We conducted experiments on clay-oil interactions, nuclear magnetic resonance (NMR), measurements of crude oil properties, and long core water flooding tests to evaluate deposition, reservoir damage, and CO₂ sequestration. Conclusions/Significance: Results demonstrate that clay minerals significantly promote CO₂-induced asphaltene deposition, with the deposition amount in clay-containing crude oil increasing by 37% compared to clay-free systems. The interfacial tension (IFT) between crude oil and CO₂ decreases from 15.68 to 12.53 mN/m at 10 MPa with increasing clay content, while crude oil viscosity reduces by up to 43.58% when CO₂ injection exceeds 30 mol%. Microscale NMR analysis confirms that clay-asphaltene aggregates preferentially block large pores, reducing reservoir heterogeneity and enhancing CO₂ sequestration in medium/small pores. Macroscale long-core experiments highlight the significance of high clay mineral content for geological sequestration, showing that the CO₂ sequestration rate increases from 43.15% to 48.21% as clay content rises from 8.35% to 29.92%. Although deposition slightly impairs permeability, it drives CO₂ into medium/small pores, thereby achieving a balance between oil recovery efficiency and long-term storage stability.

Aiming at the problems of high clay mineral content in strong water-sensitive reservoirs and easy hydration expansion caused by foreign fluids, a clay inhibitor (silyl quaternary ammonium salt DSC) was prepared using 2-(dimethylamino)­ethyl methacrylate and (3-chloropropyl)­trimethoxysilane as raw materials. This is the first report on the synergistic application of silyl quaternary ammonium salt (DSC) and CO₂ for enhanced oil recovery in strongly water-sensitive reservoirs, realizing the dual effects of clay stabilization and CO₂ seepage enhancement. It is demonstrated that the synergy of DSC/CO₂ increases the oil recovery rate by 47.29% compared to traditional water flooding, with a 0.35 PV delay in gas channeling. The DSC system, composed of DSC, ethylene glycol, inorganic salt, and nonionic surfactant, stabilizes pore structures through synergistic charge neutralization, hydrogen bond inhibition, and electric double-layer compression, with an antiswelling rate of 93.92% and dissolution rate of 5.32%. The study on the synergistic effect of the DSC system and CO₂ found that the CO₂ diffusion coefficient in DSC-saturated cores increased to 9.226 × 10^–9 m²/s (16 times higher than that in formation water-saturated cores), the initiation pressure gradient was reduced by 2 orders of magnitude compared with simulated water flooding, and the antiswelling rate decreased by only 13.72% after multiple rounds of flushing in an acidic environment. It was confirmed that DSC reconstructed the pore surface energy through silyl bonding, significantly improving the CO₂ seepage capacity. Nuclear magnetic resonance (NMR) proved from a microscopic perspective that the synergy of DSC and CO₂ increased the recovery rate of the remaining oil in small pores by 25.08%. Macroscopic oil displacement experiments further showed that the total recovery rate of DSC system flooding + gas–liquid alternating flooding reached 62.85%. The proposed technical model of “dual-effect stable flow-synergistic oil recovery-delayed gas channeling” provides a solution with both technical feasibility and economic rationality for the development of low-permeability water-sensitive reservoirs and CO₂ geological storage. Future research will focus on formula optimization and adaptability studies for reservoirs with different clay compositions.

This study targeted a highly water-sensitive reservoir with high clay content (average 23.87%, mainly montmorillonite and illite), where waterflooding development induces hydration swelling of clay minerals, leading to pore-throat narrowing. The anti-swelling system and CO₂ were found to mitigate this phenomenon. The research investigated the dissolution, diffusion, and synergistic effects of CO₂ in the anti-swelling system/crude oil within the context of Carbon Capture, Utilization and Storage-Enhanced Oil Recovery (CCUS-EOR). Using the pressure decay method, core flooding experiments, microscopic visualization of oil displacement, and an improved mathematical model. We systematically investigated the influence of clay minerals on the balance between CO₂ storage and enhanced oil recovery (EOR). It was found that the diffusion coefficient of supercritical CO₂ increased rapidly and then levelled off with increasing pressure, which indicated that clay minerals hindered CO₂ diffusion. The anti-swelling system increases the effective pore connectivity by suppressing clay swelling, which increases the diffusion coefficient by 20–28%. The enhanced mathematical model combines the oil-water phase partition coefficients with the PR-EOS equation of state to accurately describe the multiphase interactions. The calculation results fit the experimental data by 92%, which is better than the traditional single-phase model. Through microscopic oil displacement experiments, core flooding tests, and quantitative analysis of full-cycle CO₂ saturation evolution. It is demonstrated that the sweep efficiency is anti-swelling system-CO₂ flooding is a higher sweep efficiency (73.95%) and achieves 58.12% oil recovery and 46.16% CO₂ sequestration efficiency in a core with a permeability of 102.95 × 10⁻³ μm². The full-cycle CO₂ saturation change rule was quantified, and the saturation cloud map was drawn. It is proven that the technology has the synergistic mechanism of ‘stabilising pore structure-reducing oil viscosity-efficient sequestration’, which combines significant oil recovery and carbon sequestration benefits, and provides theoretical and practical guidance for the low-carbon development of strong water-sensitive oilfields.

A controllable particle size mono-dispersing nanofluid system has been developed to address the challenges of low porosity and low-permeability in low to ultra-low-permeability reservoirs. This system combines high dispersion stability with enhanced oil recovery performance, and its effectiveness in improving recovery rates in low-permeability reservoirs, where conventional chemical flooding is ineffective, has been well demonstrated. Using the in situ method to prepare monodispersed nano-silica particles, the effects of the water concentration, ammonia concentration, and silica precursor concentration on the morphology, particle size, and formation time of the silica spherical particles were analyzed. Building on this foundation, a partially hydrophobic modified nano-silica oil displacement fluid was synthesized in situ. The system’s dispersion stability, ability to reduce oil-water interfacial tension, and capacity to alter rock wettability were evaluated. Core physical models were used to evaluate the oil displacement efficiency and the permeability applicability limits of the self-dispersing nano-silica oil displacement system. The experiments confirmed that the particle size distribution of the self-dispersing nano-silica oil displacement system can be controlled within a range of 10 nm to 300 nm. The nanofluids exhibited excellent stability, effectively altering the rock wettability from oil-wet to water-wet and reducing the oil-water interfacial tension to approximately 10⁻¹ mN/m. The nano-displacement system increased the recovery rate of the low permeability reservoirs by more than 17%. The in situ modification method used to prepare these self-dispersing nanoparticles provides valuable insights for synergistic enhancement of recovery when combined with other systems, such as surfactants and CO₂. This approach also opens up new possibilities and drives further development in the field of nano-enhanced oil recovery chemistry.

The global oil and gas exploration targets are gradually moving towards a new field of oil and gas accumulation with nanopore throats, ranging from millimeter scale to micro-nano pore throats. The development method of tight oil reservoirs is different from that of conventional oil reservoirs, and the development efficiency is constrained. Therefore, it is necessary to construct a nanoscale fluid with strong diffusion and dispersion and improve its permeability, suction, and displacement capabilities. Under the background of CCUS, carbon dioxide flooding is a better way to develop tight reservoirs. However, in order to solve the problem of gas channeling, this paper developed a carbon dioxide-responsive graphene point type surfactant, which has a good gas–liquid synergistic effect. At the same time, graphene nanomaterials are carbon-based and create no environmental damage in oil reservoirs. In this study, graphene quantum dots (GQDs) were prepared using the hydrothermal method, and functional graphene quantum dots (F-GQDs) responsive to carbon dioxide stimulation were synthesized by covalent grafting of amidine functional groups. By characterizing its structure and physical and chemical properties, and by conducting imbibition simulation experiments, its imbibition and drainage ability in nanopore throats is elucidated. Infrared spectrum measurement shows that after functional modification, the quantum dots exhibited new characteristic peaks at 1600 cm⁻¹ to 1300 cm⁻¹, considering the N-H plane-stretching characteristic peak. The fluorescence spectra showed that the fluorescence intensity of F-GQDs was increased after functional modification, which indicated that F-GQDs were successfully synthesized. Through measurements of interfacial activity and adhesion work calculations, the oil–water interfacial tension can achieve ultra-low values within the range of 10⁻² to 10⁻³ mN/m. Oil sand cleaning experiments and indoor simulations of spontaneous imbibition in tight cores demonstrate that F-GQDs exhibit effective oil-washing capabilities and a strong response to carbon dioxide. When combined with carbon dioxide, the system enhances both the rate and efficiency of oil washing. Imbibition recovery can reach more than 50%. The research results provide a certain theoretical basis and data reference for the efficient development of tight reservoirs.

The global oil and gas exploration targets are gradually moving towards a new field of oil and gas accumulation with nano pore throats, ranging from millimeter scale to micro nano pore throats.There are difficulties in fluid transport in nano confined pore throats, such as strong adsorption, which greatly increases the difficulty of starting crude oil.Therefore, it is necessary to construct a nanoscale fluid with strong diffusion and dispersion, and improve its permeability, suction, and displacement capabilities.This article develops a carbon dioxide responsive graphene dot type surfactant.By characterizing its structure, physical and chemical properties, and conducting infiltration simulation experiments, its infiltration and drainage ability in nanopore throats is elucidated.Infrared spectrum measurement shows that after functional modification exhibit new characteristic peaks at 1600 cm-1 to 1300 cm-1, considering the N-H plane stretching characteristic peak.The fluorescence spectra showed that the fluorescence intensity of F-GQDs was increased after functional modification, which indicated that F-GQDs was successfully synthesized.Through measurements of interfacial activity and adhesion work calculations, the oil-water interfacial tension can achieve ultra-low values within the range of 10-2 to 10-3 mN/m. Oil sand cleaning experiments and indoor simulations of spontaneous imbibition in tight cores demonstrate that F-GQDs exhibit effective oil washing capabilities and a strong response to carbon dioxide. When combined with carbon dioxide, the system enhances both the rate and efficiency of oil washing.Imbibition recovery can reach more than 50%.The research results provide a certain theoretical basis and data reference for the efficient development of tight reservoirs.

As an important means to enhance oil recovery, ternary composite flooding (ASP flooding for short) technology has achieved remarkable results in Daqing Oilfield. Alkalis, surfactants and polymers are mixed in specific proportions and injected into the reservoir to give full play to the synergistic effect of each component, which can effectively enhance the fluidity of crude oil and greatly improve the oil recovery. At present, the technology for further improving oil recovery after ternary composite flooding is not mature and belongs to the stage of technical exploration. The presence of alkaline substances significantly alters the reservoir’s physical properties and causes considerable corrosion to the equipment used in its development. This is detrimental to both the environment and production. Therefore, it is necessary to develop green displacement control agents. In the reservoir environment post-ASP flooding, 2-(methylamino)ethyl methacrylate and glycidyl methacrylate were chosen as monomers to synthesize a polymer responsive to alkali, and then grafted with cellulose nanocrystals to form microspheres of alkali-resistant swelling hydrogel. Cellulose nanocrystals (CNCs) modified with functional groups and other materials were utilized to fabricate hydrogel microspheres. The product’s structure was characterized and validated using Fourier transform infrared spectroscopy and X-ray diffraction. The infrared spectrum revealed characteristic absorption peaks of CNCs at 1165 cm⁻¹, 1577 cm⁻¹, 1746 cm⁻¹, and 3342 cm⁻¹. The diffraction spectrum corroborated the findings of the infrared analysis, indicating that the functional modification occurred on the CNC surface. After evaluating the swelling and erosion resistance of the hydrogel microspheres under various alkaline conditions, the optimal particle size for compatibility with the target reservoir was determined to be 6 μm. The potential of cellulose-based gel microspheres to enhance oil recovery was assessed through the evaluation of Zeta potential and laboratory physical simulations of oil displacement. The study revealed that the absolute value of the Zeta potential for gel microspheres exceeds 30 in an alkaline environment with pH values ranging from 7 to 14, exhibiting a phenomenon where stronger alkalinity correlates with a greater absolute value of Zeta potential. The dispersion stability spans from good to excellent. The laboratory oil displacement simulation experiment was conducted using a cellulose-based gel microsphere system following weak alkali ASP flooding within the pH value range from 7 to 10. The experimental interventions yielded recovery rates of 2.98%, 3.20%, 3.31%, and 3.38%, respectively. The study indicates that cellulose-based gel microspheres exhibit good adaptability in alkaline reservoirs. This research offers a theoretical foundation and experimental approaches to enhance oil recovery techniques post-ASP flooding.

Carbon Capture, Utilization, and Storage (CCUS) stands as one of the effective means to reduce carbon emissions and serves as a crucial technical pillar for achieving experimental carbon neutrality. CO₂-enhanced oil recovery (CO₂-EOR) represents the foremost method for CO₂ utilization. CO₂-EOR represents a favorable technical means of efficiently developing extra-low-permeability reservoirs. Nevertheless, the process known as the direct injection of CO₂ is highly susceptible to gas scrambling, which reduces the exposure time and contact area between CO₂ and the extra-low-permeability oil matrix, making it challenging to utilize CO₂ molecular diffusion effectively. In this paper, a comprehensive study involving the application of a CO₂ nanobubble system in extra-low-permeability reservoirs is presented. A modified nano-SiO₂ particle with pro-CO₂ properties was designed using the Pickering emulsion template method and employed as a CO₂ nanobubble stabilizer. The suitability of the CO₂ nanobubbles for use in extra-low-permeability reservoirs was evaluated in terms of their temperature resistance, oil resistance, dimensional stability, interfacial properties, and wetting-reversal properties. The enhanced oil recovery (EOR) effect of the CO₂ nanobubble system was evaluated through core experiments. The results indicate that the CO₂ nanobubble system can suppress the phenomena of channeling and gravity overlap in the formation. Additionally, the system can alter the wettability, thereby improving interfacial activity. Furthermore, the system can reduce the interfacial tension, thus expanding the wave efficiency of the repellent phase fluids. The system can also improve the ability of CO₂ to displace the crude oil or water in the pore space. The CO₂ nanobubble system can take advantage of its size and high mass transfer efficiency, among other advantages. Injection of the gas into the extra-low-permeability reservoir can be used to block high-gas-capacity channels. The injected gas is forced to enter the low-permeability layer or matrix, with the results of core simulation experiments indicating a recovery rate of 66.28%. Nanobubble technology, the subject of this paper, has significant practical implications for enhancing the efficiency of CO₂-EOR and geologic sequestration, as well as providing an environmentally friendly method as part of larger CCUS-EOR.