In recent years, declining production of conventional light oil, together with steadily increasing global energy demand, has elevated the strategic importance of heavy oil resources. However, the intrinsically high viscosity of heavy oil severely limits the effectiveness of conventional recovery methods, with typical recovery factors generally below 15%. Thermal recovery technologies enhance oil mobility by injecting heat carriers into the reservoir, thereby substantially improving recovery efficiency. Nevertheless, the generation of thermal agents relies on large-scale fuel combustion and is associated with considerable CO2 emissions, rendering traditional thermal processes increasingly incompatible with current goals of green and low-carbon oilfield development. Against this background, low-carbon development technologies for heavy oil reservoirs have emerged as major research and application frontiers. Representative approaches include expanding-solvent SAGD (ES-SAGD), noncondensable gas-assisted SAGD (NCG-SAGD), in-situ reflux (ISR), vapor extraction (VAPEX), cyclic solvent injection (CSI) and in-situ hydrogen generation (ISHG). Despite growing research efforts, a comprehensive understanding of their underlying mechanisms, field performance, and carbon emission reduction potential in enhancing oil recovery (EOR) remains limited, which constrains objective assessments of engineering applicability and rational technology selection. To address this gap, this study provides an integrated review of representative mentioned six low-to zero-carbon emission heavy oil EOR technologies, focusing on their fundamental mechanisms, carbon emission reduction potential, technical advantages and limitations, and future development trends. These findings provide scientifically grounded screening criteria and practical references for the low-to zero-carbon development of heavy oil reservoirs, thereby supporting the green and sustainable development of heavy oil reservoirs worldwide.

Pressure supplementation before fracturing operations refers to the technical measure conducted before the main fracturing or the next stage of staged fracturing, where chemical systems are preinjected to improve rock wettability and reduce interfacial tension (IFT), thereby stabilizing the formation pressure at its original level. By doing so, it enhances the overall dynamic behavior of the reservoir, thereby improving fracturing stimulation effectiveness and increasing matrix recovery rates through enhanced imbibition. The change in wettability from oil- wet to water- wet and the decrease in IFT are usually regarded as the main imbibition mechanisms. However, the effect of pore size on wettability change and the optimal range of IFT for imbibition remain unclear. In this paper, based on nuclear magnetic resonance (NMR) imbibition experiments, we investigate the interfacial interactions between different imbibition fluids and cores with different mineral compositions, as well as the enhanced imbibition mechanism, from the perspectives of pore wettability changes and optimal IFT ranges. The contribution of various influencing factors to imbibition recovery is also analyzed. The mineral component differences between shale and tight sandstone make them, respectively, exhibit oil- wet and weakly water- wet properties. Spontaneous imbibition mainly occurs in relatively small pores, showing mixed wettability. As the pore radius increases, the pores become more oil- wet. The crude oil displaced by the imbibition of shale and tight cores mainly comes from small pores, with contribution degrees reaching 53.3% to 60.7% and 39.1% to 72.2%, respectively. After enhanced imbibition, the wettability alteration degrees of micropores, small pores, and mesopores in the core gradually decrease, and the corresponding imbibition efficiency gradually decreases. The wettability change in the small pore range (10-100 nm) has a greater impact on the imbibition recovery rate, which is conducive to the precise assessment of tight oil production. The optimal IFT ranges corresponding to shale and tight sandstone are 0.09 similar to 6.90 mN/m and 0.12 similar to 9.40 mN/m, respectively. Petroleum sulfonates and nanofluids achieve optimal imbibition recovery by synergistically reducing contact angles to <60 degrees (strongly water- wet) and targeting small pores, where low IFT (0.5 similar to 0.6 mN/m) enables capillary- driven oil deformation, contributing 53 similar to 72% of total recovery, whereas low- salinity water (LSW) and Bohai drilling (BH) systems exhibit weak wettability reversal (>88.8 degrees) and rely on inefficient gravity drainage in oil- wet mesopores, limiting small- pore efficiency to 39 similar to 60%. The weight coefficients of the factors influencing the enhanced imbibition of tight oil are as follows: core characteristic value > wettability > IFT. The physical properties of the reservoir itself are the fundamental restrictive factors for the imbibition effect. Wettability affects the capillary force direction and the imbibition recovery rate. IFT should be optimized in coordination with other factors. Pursuing ultralow IFT alone may have limited effects. The research results of this paper are helpful for designing scientific enhanced oil recovery (EOR) strategies in tight oil reservoirs.

Gas channeling during CO2 geological storage reduces sweep efficiency and increases leakage risk, while conventional anti-channeling agents suffer from limited stability and retention. In this study, a novel CO2-responsive in-situ mineralization plugging (RIMP) system, composed of aqueous ammonia (NH4OH) and calcium chloride (CaCl2), simultaneously achieves CO2 in-situ mineralization and mitigates channeling. The optimized RIMP formulation, determined through compatibility and mineralization capacity tests, demonstrated a CO2 mineralization capacity of 6.13 mg CO2/g RIMP with 1.6 wt% CaCl2 and 1.0 wt% NH4OH. Real-time monitoring of pH, mass change, Ca2+ concentration, and in-situ infrared spectra revealed a four-stage mineralization process governed by seven elementary reactions. XPS, XRD, SEM, and FTIR analyses showed that the mineralization product was composed of 84.4% calcite and 15.6% vaterite. Microscopic visualization and numerical simulations of in-situ CO2 mineralization in capillaries showed that CaCO3 particles form at the gas-liquid interface, diffuse into the liquid phase due to concentration gradients, and adhere to the capillary wall when the adsorption force dominates, resulting in localized accumulation. A reaction-diffusion model, established based on Fick's law and the Stokes-Einstein equation, showed that the distribution of mineralization products is mainly influenced by shut-in periods and pore size. Coreflooding tests demonstrated that the RIMP system increased plugging efficiency from 65.25% to 88.16% after 40 h of shut-in, and CO2 storage and mineralization efficiencies improved by 26.3% and 23.5%, respectively, consistent with the reaction-diffusion model predictions. The CO2-responsive insitu mineralization characteristic of RIMP offers a promising dual-function solution that mitigates gas channeling and enhances CO2 storage security through permanent mineral trapping.

Gel treatments have been widely applied to control water production in oil and gas reservoirs. However, for water shutoff in dense gas reservoirs, most gel-based treatments focus on individual wells rather than the entire reservoir, exhibiting limited treatment depth, poor durability, and inadequate repeatability Notably, formation damage is a primary consideration in treatment design—most dense gas reservoirs have a permeability of less than 1 mD, making them highly susceptible to damage by formation water, let alone viscous polymer gels. Constrained by well completion methods, gelant can only be bullheaded into deep gas wells in most scenarios. Due to the poor gas/water selective plugging capability of conventional gels, the injected gelant tends to enter both gas and water zones, simultaneously plugging fluid flow in both. Although several techniques have been developed to re-establish gas flow paths post-treatment, treating gas-producing zones remains risky when no effective barrier exists between water and gas strata. Additionally, most water/gas selective plugging materials lack sufficient thermal stability under high-temperature and high-salinity (HTHS) gas reservoir conditions, and their injectivity and field feasibility still require further optimization. To address these challenges, treatment design should be optimized using non-selective gel materials, shifting the focus from directly preventing formation water invasion into individual wells to mitigating or slowing water invasion across the entire gas reservoir. This approach can be achieved by placing large-volume gels along major water flow paths via fully watered-out wells located at structurally lower positions. Furthermore, the drainage capacity of these wells can be preserved by displacing the gel slug to the far-wellbore region, thereby dissipating water-driven energy. This study evaluates the viability of placing gels in fully watered-out wells at structurally lower positions in an edge-water drive gas reservoir to slow water invasion into structurally higher production wells interconnected via numerous microfractures and high-permeability streaks. The gel system primarily comprises polyethyleneimine (PEI), a terpolymer, and nanofibers. Key properties of the gel system are as follows: Static gelation time: 6 h; Elastic modulus of fully crosslinked gel: 8.6 Pa; Thermal stability: Stable in formation water at 130 °C for over 3 months; Injectivity: Easily placed in a 219 mD rock matrix with an injection pressure gradient of 0.8 MPa/m at an injection rate of 1 mL/min; and Plugging performance: Excellent sealing effect on microfractures, with a water breakthrough pressure gradient of 2.25 MPa/m in 0.1 mm fractures. During field implementation, cyclic gelant injections combined with over-displacement techniques were employed to push the gel slug deep into the reservoir while maintaining well drainage capacity. The total volumes of injected fluid and gelant were 2865 m3 and 1400 m3, respectively. Production data and tracer test results from adjacent wells confirmed that the water invasion rate was successfully reduced from 59 m/d to 35 m/d. The pilot test results validate that placing gels in fully watered-out wells at structurally lower positions is a viable strategy to protect the production of gas wells at structurally higher positions.

Heavy oil reservoirs possess substantial reserves exceeding 600 billion tons. However, the recovery factor is estimated around 11 % due to high oil viscosity, indicating substantial potential for further enhancement of oil recovery. Traditional enhancing heavy oil recovery (EHOR) technologies, such as thermal recovery, are often constrained by high energy consumption and significant CO2 emissions. To achieve green and significant improvements in heavy oil recovery, this study proposes an innovative hybrid approach: CO2-based cyclic solvent injection (CO2-CSI) and polymer flooding alternation process. Five experimental groups were conducted using 1D sand-pack model to evaluate EHOR potential and operational parameters. A maximum oil recovery of 70.72 % was achieved when the final CO₂-CSI cycle was alternated with 1000 ppm polymer flooding. The enhanced performance is attributed to two synergistic mechanisms: CO2-CSI phase effectively mobilizes and produces heavy oil while reducing the residual oil viscosity; The alternating polymer flooding facilitates the formation of oil bank for CO2-CSI, which enhances the efficiency of subsequent CO2-CSI cycles. Furthermore, a novel ‘dual-mobility-ratio-control’ concept is introduced and validated as a key mechanism for optimizing mobility ratios in both displacing and displaced phases. Economic analysis indicated that the new proposed technology exhibited excellent economic benefits, reducing material costs by over 70 %. The EHOR technique proposed in this study demonstrates high efficiency, cost-effectiveness, and low carbon emissions, offering new insights and guidance for the development of heavy oil reservoirs.

Pre-pressure energy storage to enhance imbibition is a key technology to improve the production efficiency of tight oil and shale oil in matrix pores, but the mechanism of pore structure and mineral composition on imbibition is still unclear. In this paper, the imbibition behavior of shale and tight sandstone is compared from the perspective of mineral composition and fractal pore structure, and a prediction model of the enhanced imbibition effect is established. Feldspar accounts for 67.7% of the shale, and the micromorphology of shale is mainly intergranular pores, feldspar dissolution pores, and tubular throats. The proportion of quartz and clay in tight sandstone is 70.8% and 16.8%, respectively. The compaction and cementation of quartz and the irregular distribution of clay minerals increase the complexity of pore structure. The pore and throat distribution of shale core is more concentrated, while the pore and throat distribution of tight sandstone is wider, less frequent and more heterogeneous. The calculated average imbibition index Qk of shale and tight sandstone is 0.0128 and 0.0082, respectively. The pore structure of shale is more conducive to imbibition. The modified Qmk value of shale is in the range of 0.0015–0.0081, and the final imbibition efficiency is in the range of 22.12% to 37.61%. The Qmk value of tight sandstone ranges from 0.0010 to 0.0052, and the final imbibition efficiency ranges from 15.35% to 32.28%. The research content of this paper is helpful to deepen the understanding of enhanced imbibition from the perspective of fractal pore structure and mineral composition.

Applying chemical enhanced oil recovery (EOR) to shale and tight formations is expected to accelerate China’s Shale Revolution as it did in conventional reservoirs. However, its screening and modeling are more complex. EOR operations are faced with choices of chemicals including traditional surfactant solutions, surfactant solutions in the form of micro-emulsions (nano-emulsions), and nano-fluids, which have similar effects to surfactant solutions. This study presents a systematic comparative analysis composed of laboratory screening and numerical modeling. It was conducted on three scales: tests of chemical morphology and properties, analysis of micro-oil-displacing performance, and simulation of macro-oil-increasing effect. The results showed that although all surfactant solutions had the effects of reducing interfacial tension, altering wettability, and enhancing imbibition, the nano-emulsion with the lowest hydrodynamic radius is the optimal selection. This is attributed to the fact that the properties of the nano-emulsion match well with the characteristics of these shale and tight reservoirs. The nano-emulsion is capable of integrating into the tight matrix, interacting with the oil and rock, and supplying the energy for oil to flow out. This study provides a comprehensive understanding of the role that surfactant solutions could play in the EOR of unconventional reservoirs.

This study presents a novel Enhanced Oil Recovery (EOR) method using Smart Black Nanocards (SLNs) to mitigate the environmental impact of conventional thermal recovery, especially under global warming. Unlike prior studies focusing on wettability alteration via adsorption, this research innovatively models ‘oil film detachment’ in a reservoir simulator to achieve wettability alteration. Using the CMG-STARS (2020) simulator, this study highlights SLNs’ superior performance over traditional chemical EOR and spherical nanoparticles by reducing residual oil saturation and shifting wettability toward water-wet conditions. The structural disjoining pressure (SDP) of SLNs reaches 20.99 × 103 Pa, 16.5 times higher than spherical particles with an 18.5 nm diameter. Supported by the Percus–Yevick (PY) theory, the numerical model achieves high accuracy in production history matching, with oil recovery and water cut fitting within precision error ranges of 0.02 and 0.05, respectively. This research advances chemical EOR technologies and offers an environmentally sustainable, efficient recovery strategy for low-permeability and heavy oil reservoirs, serving as a promising alternative to thermal methods.

Long-term water flooding leads to changes in pore throat structure, resulting in alterations in macroscopic reservoir petrophysical parameters. However, commercial numerical simulation software does not have this capability. Ignoring variations in physical parameters during the formulation of development plans and numerical simulations can lead to significant prediction errors, which severely impacts oil field recovery. This paper, based on an analysis of effective flow rate and waterflood intensity, proposes a new erosion degree characterization parameter: Effective water flux, to represent the time-varying patterns of physical parameters. It is embedded into a black oil model to develop a time-variation simulator, whose accuracy and stability in both black oil and time-variation models are validated through comparison with the commercial numerical simulation software CMG. The study further explores the effects of different parameter variations on the development process. It was found that increases in permeability and oil viscosity exacerbate heterogeneity and reduce displacement efficiency, while decreases in residual oil saturation and water phase permeability under residual oil saturation enhance water flooding efficiency. In complex models, the effects of variations in different parameters intertwine, collectively influencing development outcomes. This paper advances the development of time-variation numerical simulation technology.

As the global demand for energy escalates, the depletion of conventional oil and gas reserves has necessitated a shift towards unconventional reservoirs. These reservoirs, however, present significant challenges for oil recovery due to their complex rock properties, compositional heterogeneity, small pore throat size, low permeability, and low fluid mobility. Traditional methods, such as the injection of chemical agents to alter the oil-water interfacial properties, have proven less effective due to the intricacies of unconventional reservoirs. Moreover, while fracturing technologies can enhance permeability to some extent, they are yet to overcome issues of rapid production decline and final recovery rates below 10

As one important crude oil recovery method, gas miscible flooding was widely adopted for EOR. However, the effect of crude oil components, injecting gas types, and pressure on miscible performance were scarcely discussed. In this work, molecular dynamics simulation method was employed to investigate the miscible mechanism of four-components crude oil in injecting gases of CO2 and CH4, respectively. The driving force and hindrance force in oil and gas miscible process was discussed to uncover the underlying miscible mechanism. The driving force mainly comes from the interaction between oil and gas, which induces the interdiffusion between oil and gas. The repulsive force stems from the association of oil components, which inhibits the dissolution of oil out of the crude oil colloidal structure. Furthermore, one evaluation standard of miscibility degree oil in gas was proposed based on solubility capability of oil component in injecting gas. Simulation results indicate the CO2 have better miscibility than that of CH4, and the miscibility of four crude oil components follows order of saturates > aromatics > resins > asphaltenes. The miscibility of all four oil components improves with increasing pressure. It is interesting that the miscibility of asphaltene is insensitive to pressure. Our work provides molecular level insight into the oil gas miscible behavior based on multiple components crude oil, and provide quantitative evaluation on miscibility of each oil component. These simulation results might be helpful to theoretical guidance for gas injection development.

A smart response fluid was designed and developed to overcome the challenges of gas channeling during CO2 flooding in low-permeability, tight oil reservoirs. The fluid is based on Gemini surfactant with self-assembly capabilities, and the tertiary amine group serves as the response component. The responsive characteristics and corresponding mechanism of the smart fluid during the interaction with CO2/oil were studied, followed by the shear characteristics of the thickened aggregates obtained by the smart fluid responding to CO2. The temperature and salt resistance of the smart fluid and the aggregates were evaluated, and their feasibility and effectiveness in sweep-controlling during the CO2 flooding were confirmed. This research reveals: (1) Thickened aggregates could be assembled since the smart fluid interacted with CO2. When the mass fraction of the smart fluid ranged from 0.05% to 2.50%, the thickening ratio changed from 9 to 246, with viscosity reaching 13 to 3100 mPa·s. As a result, the sweep efficiency in low-permeability core models could be increased in our experiments. (2) When the smart fluid (0.5% to 1.0%) was exposed to simulated oil, the oil/fluid interfacial tension decreased to the level of 1×10−2 mN/m. Furthermore, the vesicle-like micelles in the smart fluid completely transformed into spherical micelles when the fluid was exposed to simulated oil with the saturation greater than 10%. As a result, the smart fluid could maintain low oil/fluid interfacial tension, and would not be thickened after oil exposure. (3) When the smart fluid interacted with CO2, the aggregates showed self-healing properties in terms of shear-thinning, static-thickening, and structural integrity after several shear-static cycles. Therefore, this fluid is safe to be placed in deep reservoirs. (4) The long-term temperature and salt resistance of the smart fluid and thickened aggregates have been confirmed.

微乳液具有超低界面张力、乳化、增溶、分散、起泡、润滑和柔软性等优异性能,在石油行业中被广泛用作储层改造液体体系.综述了微乳液的形成理论、基本组成、制备方法以及国内外研究进展.介绍了课题组自主研发的纳米流体增渗驱油体系,可用于致密油储集层压裂驱油增产、降压增注补充地层能量、驱替与吞吐提高原油采收率等领域,为致密油有效动用与高效开发及持续提高采收率提供技术支撑.

为了构建适用于泡沫驱的高稳定泡沫,从液膜渗透率角度阐明气/液介质对泡沫稳定性的影响机制.以氮气和二氧化碳为气体介质,利用气泡缩减法,测定了7种起泡体系的泡沫液膜渗透率以及起泡性能、析液半衰期和泡沫半衰期.研究结果表明,对于同一种气体介质,表面活性剂分子疏水碳链数目越多,液膜上表面活性剂分子之间相互作用越强,泡沫液膜渗透率越小;CO2泡沫的液膜渗透率是N2泡沫的1～3倍,CO2泡沫稳定性比N2泡沫的低;泡沫液膜渗透率与泡沫半衰期呈现出良好的相关性,随着液膜渗透率升高,CO2泡沫半衰期快速递减.

Determination of the diffusion coefficient of a miscible Supercritical CO2 (ScCO2) and oil system is substantial for guiding the CO2 EOR and greenhouse gas geological storage practices. Based on the oil droplet interface shrinkage behavoir after reaching miscibility with the surrounding CO2, the diffusion coefficients of a miscible ScCO2/paraffin system were measured with the Dynamic Pendant Drop Volume Analysis (DPDVA) technique. A refined diffusion coefficient derivation model was proposed and validated for the CO2/oil system at the Minimum Miscibility Pressure (MMP) points. The measurements were performed under pressure range of 9-21 MPa and temperature range of 40.6-81.2 celcius. Exponential relationships have been obtaind between the diffusion coefficient and the pressure and the intrinsic oil viscosity, revealing the fact that the diffusion rate increases significantly with the system pressure after reaching miscibility. On the other hand, it is found higher temperature could retard the diffusion process between the ScCO2 and the oil phases under miscible conditions.