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Rate transient analysis (RTA) is a practical and cost‐effective method for CO2 injection data analysis and storage capacity evaluation of saline aquifers. However, the nonlinear behavior introduced by two‐phase CO2–brine flow, coupled with pressure‐dependent fluid and rock properties, significantly limits the applicability of conventional production‐based RTA models, which typically assume single‐phase flow and rely solely on pressure propagation. To overcome these limitations, this study presents a novel two‐phase RTA method that, for the first time, explicitly incorporates both pressure evolution and CO2 front migration, while accounting for the nonlinearities associated with brine displacement and pressure‐sensitive reservoir behavior. First, a two‐phase flow model is developed for CO2 injection in saline aquifers, and an analytical solution is derived by introducing new definitions of pseudo‐pressure and pseudo‐time that capture the effects of both multiphase flow and pressure‐dependent properties. By introducing distinct definitions of the radius of investigation (ROI) for the pressure front and the CO2 front, average pressure and saturation are evaluated based on their respective controlling regions and incorporated into the estimation of pseudotime. Second, a two‐step RTA approach is proposed to analyze CO2 injection data, including flow regime identification using a two‐phase diagnostic plot and subsurface properties estimation using a specialty plot. Finally, we provide a workflow that integrates formation properties evaluation with storage capacity prediction under the more realistic conditions of variable injection. The proposed method is validated using synthetic data from numerical simulations and a field example from the Illinois Basin Decatur Project (IBDP). The close estimation of CO2 storage capacity, reservoir pore‐volume, and permeability confirm the accuracy of the proposed model and demonstrate the method's reliability compared with numerical simulations for rapid assessment of storage potential and analytical RTA methods for considering the specific nonlinearities. With the proposed approach, the scattered CO2 injection pressure and rate data are, for the first time, transformed into clear straight‐line behaviors with unique slope, revealing the underlying two‐phase flow characteristics during CO2 injection up to the injection limit.

Gel systems are widely used as plugging materials in the oil and gas industry. Gas channeling can be mitigated by reducing the heterogeneity of the formation and the mobility ratio of CO2 to crude oil. Cracks and other CO2 leaking pathways can be plugged during the geological storage of CO2 to increase the storage stability. By adding CO2-responsive groups to the classic polymer gel’s molecular chain, CO2 responsive gel is able to seal and recognize CO2 in the formation while maintaining the superior performance of traditional polymer gel. The application of CO2 responsive gels in oil and gas production is still in the stage of laboratory testing on the whole. To actually achieve the commercial application of CO2 responsive gels in the oil and gas industry, it is imperative to thoroughly understand the CO2 responsive mechanisms of the various types of CO2 responsive gels, as well as the advantages and drawbacks of the gels and the direction of future development prospects. This work provides an overview of the research progress and response mechanisms of various types of CO2 responsive groups and CO2 responsive gels. Studies of the CO2 responsive gel development, injectivity, and plugging performance are comprehensively reviewed and summarized. The shortcomings of the existing CO2 responsive gels system are discussed and the paths for future CO2 responsive gel development are suggested.

Crude oil is generally produced with water, and the water cut produced by oil wells is increasingly common over their lifetime, so it is inevitable to create emulsions during oil production. However, the formation of emulsions presents a costly problem in surface process particularly, both in terms of transportation energy consumption and separation efficiency. To deal with the production and operational problems which are related to crude oil emulsions, especially to ensure the separation and transportation of crude oil-water systems, it is necessary to better understand the emulsification mechanism of crude oil under different conditions from the aspects of bulk and interfacial properties. The concept of shearing energy was introduced in this study to reveal the driving force for emulsification. The relationship between shearing stress in the flow field and interfacial tension (IFT) was established, and the correlation between shearing energy and interfacial Gibbs free energy was developed. The potential of the developed correlation model was validated using the experimental and field data on emulsification behavior. It was also shown how droplet deformation could be predicted from a random deformation degree and orientation angle. The results indicated that shearing energy as the energy produced by shearing stress working in the flow field is the driving force activating the emulsification behavior. The deformation degree and orientation angle of dispersed phase droplet are associated with the interfacial properties, rheological properties and the experienced turbulence degree. The correlation between shearing stress and IFT can be quantified if droplet deformation degree vs. droplet orientation angle data is available. When the water cut is close to the inversion point of waxy crude oil emulsion, the interfacial Gibbs free energy change decreased and the shearing energy increased. This feature is also presented in the special regions where the suddenly changed flow field can be formed. Hence, the shearing energy is an effective form that can show the contribution of kinetic energy for the oil-water mixtures to interfacial Gibbs free energy in emulsification process, and the emulsification mechanism of waxy crude oil-water emulsions was further explained from the theoretical level.

Although technical advances in hydraulically fracturing and drilling enable commercial production from tight reservoirs, oil/gas recovery remains at a low level. Due to the technical and economic limitations of well-testing operations in tight reservoirs, rate-transient analysis (RTA) has become a more attractive option. However, current RTA models hardly consider the effect of the non-uniform production on rate decline behaviors. In fact, PLT results demonstrate that production profile is non-uniform. To fill this gap, this paper presents an improved RTA model of multi-fractured horizontal wells (MFHWs) to investigate the effects of non-uniform properties of hydraulic fractures (production of fractures, fracture half-length, number of fractures, fracture conductivity, and vertical permeability) on rate transient behaviors through the diagnostic type curves. Results indicate obvious differences on the rate decline curves among the type curves of uniform properties of fractures (UPF) and non-uniform properties of fractures (NPF). The use of dimensionless production integral derivative curve magnifies the differences so that we can diagnose the phenomenon of non-uniform production. Therefore, it’s significant to incorporate the effects of NPF into the RDA models of MFHWs, and the model proposed in this paper enables us to better evaluate well performance based on long-term production data.

Integrating of carbon capture, utilization, and storage with poverty alleviation strategies presents an innovative and sustainable development paradigm. Regional poverty, often exacerbated by challenging geographical conditions, can be transformed into opportunities for carbon storage development, promoting energy and economic rebalancing while avoiding poverty and resource traps. By introducing an evaluation index grounded in Sustainable Development Goals and technical requirements, we achieve a harmonious balance between potential and economic development. Techno-economic analysis in coal plant renovation and oil field projects demonstrates this project triggers a 7.70% growth in local gross domestic product per capita, and a decrease of 4.85% in local carbon dioxide emissions. Construction costs in impoverished regions can be over 20% lower than in more affluent areas for projects of the same scale because of cheaper labor and lower transportation and storage costs, highlighting the cost-effectiveness of pursuing poverty alleviation through carbon capture, utilization, and storage in China. This paper also emphasized the carbon storage demand in future’s energy transition of China. The status of policy implementation underscored the significant potential of carbon capture, utilization, and storage in contributing to poverty alleviation in the world’s largest carbon emitter and developing country, potentially serving as a critical testbed globally. In China, coal plant renovation and oil field carbon capture utilization and storage projects could increase local per capita income and decrease carbon dioxide emissions, according to an analysis that uses an index that integrates geological, energy, and economic development data.

Drill string torsional and longitudinal oscillation can significantly reduce axial drag in horizontal drilling. An improved theoretical model for the analysis of the frictional force was proposed based on microscopic contact deformation theory and a bristle model. The established model, an improved dynamic friction model established for drill strings in a wellbore, was used to determine the relationship of friction force changes and the drill string torsional vibration. The model results were in good agreement with the experimental data, verifying the accuracy of the established model. The analysis of the influence of drilling mud properties indicated that there is an approximately linear relationship between the axial friction force and dynamic shear and viscosity. The influence of drill string torsional oscillation on the axial friction force is discussed. The results indicated that the drill string transverse velocity is a prerequisite for reducing axial friction. In addition, low amplitude of torsional vibration speed can significantly reduce axial friction. Then, increasing the amplitude of transverse vibration speed, the effect of axial reduction is not significant. In addition, by involving general field drilling parameters, this model can accurately describe the friction behavior and quantitatively predict the frictional resistance in horizontal drilling.

Proppant concentration and fracture surface morphology are two significant fractures that can affect proppant transport and deposition behavior especially in tight and oil and gas reservoirs. This paper proposed a new set of similarity criteria for proppant experimental design by incorporating proppant concentration and fracture roughness. Based on the proposed criterion, proppant transport experiments in hydraulic fractures of tight oil and gas reservoirs were conducted to explore the proppant placement behavior and identify the key parameters that affected the fracture propping efficiency. Results showed that the proposed similarity criterion can be used to evaluate the onsite proppant transport behavior and optimize hydraulic fracturing parameters. Results showed that the fracture placement efficiency of LD C7 tight oil reservoir is mainly affected by sand ratio and fracturing fluid viscosity. The sand ratio in the LD C7 tight oil reservoir should not be less than 8%, and the optimal carrying fluid viscosity is 5 mPa s. The proppant placement efficiency of the SLG H8 tight gas reservoir is mainly affected by the displacement rate and frac fluid viscosity. The displacement rate of SLG H8 tight gas reservoir should not be less than 3.5 m3/min, and the optimal carrying fluid viscosity is 15 mPa s.

High-pressure fluid transport in nanoporous media such as shale formations requires further understanding because conventional continuum approaches become inadequate due to their ultralow permeability and complexity of transport mechanisms. We propose a species-based approach for modelling two partially miscible, multicomponent fluids in nanoporous media – one that does not rely on conventional bulk fluid transport frameworks but on species movement. We develop a numerical model for species transport of partially miscible, non-ideal fluid mixtures using the chemical potential gradient as the driving force. The model considers the binary friction concept to include the friction between fluid molecules as well as between fluid molecules and pore walls, and incorporates the key multicomponent transport mechanisms – Knudsen, viscous and molecular diffusion. Under single-phase conditions, the system under consideration is quantified by introducing multicomponent Sherwood number (Sh), Péclet number (Pe) and fluid–solid friction modulus (φ). Despite the complexity of fluid transport in nanopores, the steady-state single-phase transport results reveal the contribution of diffusion in nanopores, where all parameters collapse on a set of master curves for the multicomponent Sh with a dependence on multicomponent Pe and φ. Unsteady state, two-phase transport modelling of the codiffusion process shows that light and intermediate alkanes are produced much higher than heavy alkanes when the vapour phase appears. We demonstrate that the pressure gradient is also crucial in promoting CO2 and alkane mixing during counterdiffusion processes. These results stress the need for a paradigm shift from classical bulk flow modelling to species-based transport modelling in nanoporous media.

Abstract During the long-term process of CO2 injection and storage, CO2 may undergo phase transition with changes in underground pressure and temperature. This requires a thorough understanding of CO2 and its impact on rock elastic parameters in order to effectively utilize seismic data to evaluate CO2 storage. This study monitored the changes in fluid parameters during CO2 injection into rocks in the laboratory and recorded the signals of P- and S-waves transmitting in rocks. Values of pore pressure (Pp), gas content (n), and compressibility factor (Z) during CO2 injection were analyzed, and the physical parameters of CO2 under temperature and pressure conditions were calculated according to the True Gas Law. Using CH4 injection data as a comparative analysis of the influence of pore pressure can help explain the phase changes during CO2 injection. The changes in velocity and amplitude were analyzed based on P- and S-wave signals, and the influence of pore pressure, fluid parameters on rock velocity was calibrated using a rock physics model. Through simultaneous monitoring of multiple physical fields and theoretical analysis, the behavior of CO2 phase transition is revealed by multiple physical parameters. The physical properties of CO2, such as density and bulk modulus, significantly increase after transitioning from a gaseous state to a supercritical state. This causes a significant decrease in rock velocity, but its impact on amplitude is not as significant as the impact of pore pressure. The rock physics models can accurately calculate the velocity of porous sandstone during CO2 injection and phase transition. Understanding the phase state of CO2 and its impact on rock elastic parameters is crucial for CO2 storage. This study can help to monitor and evaluate CO2 storage using time-lapse seismic data.

Abstract Accurate estimation of crude oil viscosity is crucial for formulating optimal hydrocarbon recovery strategies. Nuclear magnetic resonance (NMR) is a non-destructive technique for viscosity characterization with a longitudinal and transverse relaxation times (T₁ and T₂), diffusion coefficient, or apparent hydrogen index derived from ¹H signals. In this review, the theoretical methods for crude oil viscosity characterization with NMR are systematically sorted, which is crucial for novices and petroleum engineers. First, the basic principles of NMR are introduced, and the theoretical basis of NMR-based crude oil viscosity characterization is described in terms of relaxation times, diffusion coefficient, and apparent hydrogen index. Then, a systematic review is conducted for NMR-based crude oil viscosity characterization method developed over the past three decades. Finally, four kinds of influence factor—instrument parameters, temperature, crude oil type, and gas oil ratio—are analyzed. The results emphasize the importance of selecting a suitable viscosity model based on reservoir type and formation conditions. Two-dimensional NMR T1−T2 techniques demonstrate potential for addressing crude oil viscosity characterization challenges. In general, the key to crude oil viscosity characterization with NMR is selecting the appropriate NMR method rationally based on clear reservoir characteristics. This study aims to assess the existing methods and their limitations critically while providing guidance toward more robust viscosity quantification protocols.