Unconventional oil and gas development (UOGD) has enabled the extraction of previously inaccessible hydrocarbon resources, leading to a rapid proliferation of well sites across shale regions, often in close proximity to residential communities. Air emissions from UOGD pose potential health risks, yet few studies have captured their full complexity or temporal variability using long-term, high-resolution monitoring. We conducted one year of continuous stationary air pollution monitoring in Loving, New Mexico, a high-production area of the western Permian Basin. Measurements included nitrogen oxides (NO x ), sulfur dioxide (SO2), hydrogen sulfide (H2S), methane (CH4), carbon dioxide (CO2), carbon monoxide (CO), radon, particle radioactivity, and 20 speciated volatile organic compounds (VOCs). We observed exceptionally high hydrocarbon concentrations and identified air quality impacts from multiple UOGD-related sources including gas flaring and midstream facilities. To characterize dominant emission sources, we applied non-negative matrix factorization to the multivariate time series. This approach resolved five distinct factors: fugitive/vented emissions, produced water, traffic, flaring, and other area sources, which together explained 95% of the variance in the combined data set. Most VOCs, along with CH4, CO, CO2, NO x , and radioactivity were primarily attributed to UOGD activities rather than to transportation, which itself is linked to UOGD operations in the area. Our findings provide a detailed, high-resolution source profile of UOGD-related air pollution in the Permian Basin and demonstrate the value of source apportionment modeling for disentangling overlapping emission sources in oil- and gas-producing regions.

Geologically deep learning for high-resolution sparse 3D oil reservoir modeling

With the rapid increase in the exploitation of oil and gas resources, conventional oil and gas resources in most oil and gas fields in China are being depleted at an accelerating pace, and research on the exploitation of unconventional oil and gas resources has become a crucial approach to safeguarding national energy security. China is endowed with abundant low-permeability reservoir resources with great application potential, yet their exploitation is fraught with considerable challenges. Water injection into the formation is a routine practice during the exploitation of low-permeability reservoirs to maintain formation pressure and improve oil recovery efficiency. However, most low-permeability oilfields currently suffer from problems such as high water injection pressure and a high proportion of insufficient injection, which prevent the establishment of effective displacement in oil-water wells and lead to a sharp drop in formation pressure, consequently driving up the exploitation costs of low-permeability reservoirs. The application of suitable formation drag reducers for oil production in the exploitation process of low-permeability reservoirs can significantly reduce water injection pressure and enhance oil recovery efficiency. This paper aims to summarize and sort out the action mechanisms of pressure reduction and injection enhancement, the types of drag reducers, and the current research status of pressure reduction and injection enhancement. Furthermore, it proposes the development directions of drag reducers in the field of pressure reduction and injection enhancement, providing a certain technical reference for improving the exploitation efficiency of low-permeability oilfields.

The development of tight heavy-oil reservoirs is severely hampered by the high viscosity and poor mobility of crude oil caused by strong intermolecular stacking interactions among asphaltenes, coupled with the substantial adsorption loss and inadequate deep transport capacity of conventional displacement agents. By targeted penetrant delivery, a novel nanoemulsion system with a well-defined “core–shell” architecture was synthesized to address these critical challenges. The physicochemical properties, stability and oil displacement performance were evaluated. The prepared nanoemulsion exhibited an ultrasmall and uniform particle size distribution between 10 nm and 20 nm. It also demonstrated exceptional dispersibility in aqueous media and remarkable thermal and salinity stability under reservoir conditions. Furthermore, an ultralow critical micelle concentration of approximately 0.01% could be achieved and the oil–water interfacial tension was reduced to 7.3 × 10−2 mN/m, significantly outperforming the conventional surfactant AES. Core flooding tests revealed that the proposed nanoemulsion enhanced oil recovery by 37.1% and attained a displacement efficiency of 68.9% in oil-wet capillary models. Molecular dynamics simulations further elucidated the underlying synergistic mechanism. The hydrophilic shell minimized adsorption on rock surfaces, facilitating deep migration within nanoporous channels. The hydrophobic core, containing terpinene as a penetrant, effectively disrupted the π-π stacking of asphaltenes due to its nonplanar molecular configuration. This disruption transformed the asphaltene aggregates from a tightly packed state to a dispersed state, resulting in substantial viscosity reduction. This work elucidated the mechanism of asphaltene aggregate disruption by nanoemulsions at the molecular level, offering a promising and theoretically grounded strategy for the efficient exploitation of tight heavy-oil reservoirs.

Unconventional oil is a significant alternative energy source. However, its low porosity and permeability present technical challenges, making it difficult to inject water and extract oil effectively. Replenishing formation energy and hydraulic fracturing for oil recovery are effective development methods. This paper combines both methods and proposes the use of nanofluid for prefracturing re-energization. We first analyze the characteristics of nanofluid and the process of prefracturing re-energization. Laboratory experiments were conducted to evaluate the benefits of nanofluid. Numerical simulation was then employed to characterize the prefracturing re-energization process, focusing on flow laws and flow space. A mechanistic model was developed to analyze the injection pressure and sweep efficiency during the prefracturing re-energization process. A predictive mechanistic simulation framework was developed that establishes a direct mapping between the nanofluid's functionalities and dynamic reservoir parameters. Simulation results quantitatively demonstrated that the nanofluid-based prefracturing re-energization yields significantly higher long-term recovery and more effective pressure maintenance compared to conventional water preinjection or no re-energization, primarily due to enhanced imbibition and improved fluid mobility. Finally, we share the positive outcomes of a pilot test conducted in the Jimusar shale oil reservoir. This paper offers a new approach to addressing the challenges of energy replenishment and fracturing for oil displacement in shale oil development.

Aiming at the inefficiency caused by the separation of schedule and cost control in oil and gas exploration and development projects, a dynamic collaborative management mechanism based on digital twinning and deep reinforcement learning (DRL) is constructed in this study. Through system dynamics modeling, it reveals the dynamic influence of key coupling variables such as geological risk index and engineering complexity on schedule and cost, and puts forward a management framework of "three-layer linkage and dynamic closed loop": using the digital twin platform integrated with Internet of Things and BIM to realize real-time correction of geological risks; The deep Q network (DQN) is used to solve the multi-objective optimal scheduling strategy. Establish a closed-loop process of "early warning-negotiation-adjustment-learning" to improve the management synergy coefficient. Taking Block Y of X Oilfield as an example, after implementation, the project duration was shortened by 2.4 months, the cost overrun rate was reduced by 20.9%, and the inter-departmental decision-making period was shortened to 1.5 days, which verified the remarkable effect of this mechanism in unconventional oil and gas field projects and provided a reusable technical path for project collaborative management under complex geological conditions.

Nanofluid flooding technology has demonstrated enormous potential in enhancing the recovery efficiency of unconventional oil and gas resources. However, due to the complex physicochemical properties of nanofluids and their intricate interaction mechanisms in different reservoir environments, the research and application of nanofluids still face numerous challenges. Although existing review articles have systematically covered various aspects of nanofluid flooding technology and its enhanced oil recovery (EOR) mechanisms, they have not comprehensively addressed all facets of nanofluid-based EOR. In particular, they lack detailed introductions to the field applications of nanofluid flooding technology in reservoirs with different geological structural characteristics, the preparation of bio-based nano-oil displacement materials, the technology of forming nanofluids through in situ self-assembly of silica nanoparticles by reservoir microorganisms, and nanomaterial-mediated carbon dioxide flooding and microbial flooding technologies. This paper aims to identify the existing deficiencies in current nanofluid EOR technologies, especially focusing on the green and low-carbon microbial composite nanofluid flooding technology based on the utilization of reservoir microbial resources. Furthermore, targeted future development directions are proposed, with the goal of providing a more comprehensive, in-depth, and forward-looking reference for the theoretical research and industrial application of nanofluid EOR technologies, thereby further promoting the advancement of EOR technologies for low-permeability and tight oil reservoirs.

During the CO2 fracturing of unconventional oil and gas resources, the structural and operational parameters significantly influence the fracturing effectiveness. To quantitatively reveal the influence mechanisms of key parameters on the CO2 jet flow field through perforations, this study employed computational fluid dynamics (CFD) via Ansys Fluent to simulate and compare the effects of the nozzle contraction angle, injection rate, confining pressure, and fluid temperature. The results indicate that the contraction angles and injection rates have a more significant influence on the jet temperature, pressure, and velocity than the confining pressures and fluid temperatures. As the contraction angle increases, the average velocity of the jet core region increases by 5.0% (with the most significant growth at 35°), and the length of the potential core increases correspondingly. The flow through the perforations is characterized by an instantaneous drop of 2.5 °C in temperature and 2.7 MPa in pressure, then transitions to a regime of temperature recovery and dynamical pressure decay along the fracture. Increasing the fracturing displacement raises the maximum jet velocity to 104.7 m/s (an average increase of 15.5%), extends the potential core length, and amplifies the temperature and pressure drops across the perforation from 1.1 °C and 1.2 MPa to 4.2 °C and 4.8 MPa, respectively. Conversely, higher confining pressure reduces the average jet velocity by 4.3%, shortens the potential core, and diminishes the perforation temperature and pressure drops from 5 °C and 3 MPa to 2 °C and 2.5 MPa. In contrast, elevating the fluid temperature increases the jet velocity by an average of 6.3% but exerts minimal influence on the potential core length; the temperature drop at the perforation remains at approximately 2 °C, while the pressure drop rises from 2.2 MPa to 2.9 MPa. Collectively, both the confining pressure and fluid temperature significantly affect the density and velocity characteristics of the jet. An increase in confining pressure enhances the density of the CO2 jet fluid, which may potentially improve the fracturing impact in actual engineering applications. Quantitatively, the influence of each parameter on the temperature, pressure, and velocity of the CO2 jet is ranked from the most significant to the least as follows: nozzle contraction angle > fracturing injection displacement > formation confining pressure > fluid temperature. The findings of this research have direct implications for practical application, informing the optimization of the fracturing design to achieve greater efficiency and lower risk in CO2 fracturing operations.

In this study, 14 Argentinian unconventional crude oil samples from five source rock extraction of renowned hydrocarbon basins were organically and geochemically characterized by GC-FID to obtain the whole oil paraffins fingerprint and GC-MS to classical biomarkers identification. The implemented methodology was rigorously validated using a reference oil and it proved to be highly precise and accurate; a total of seventy-eight diagnostic ratios were obtained to study the differences between formations and to contribute to the systematic knowledge of source rock origin, depositional conditions, maturity and biodegradation of oils: Pristane/phytane (0.89–1.89), Carbon Preference Index (values close to 1), C29 S/(S + R) sterane (0.49–0.58), moretane/hopane ratio (0.0–0.1), and Gammacerane index (values higher than 0.4). These results indicate that these samples are mature oils, formed in a reducing environment, little to no affected by biodegradation or other alteration processes. Along with geochemical interpretation of the results, a chemometric analysis was performed to help interpret differences between basins and formations. Specifically, Principal Component Analysis (PCA), where the three basins were found to be clearly separated. Analysis performed by hierarchical cluster analysis (HCA) produced similar results to PCA in terms of separation and grouping.

Abstract In the production and transportation of complex energy fluids (such as unconventional oil and gas and geothermal fluids), the entrainment of solid particles poses a serious threat to the safety and operational efficiency of energy infrastructure. Solid deposition leads to pipeline blockage and equipment erosion, directly affecting energy security and clean utilization efficiency. To address this issue, this paper proposes a high-efficiency integrated separation device combining cyclonic separation and gravity settling. Based on Computational Fluid Dynamics (CFD), the RNG k-ε turbulence model and Discrete Phase Model (DPM) were adopted to investigate the synergistic mechanism of the internal flow field. The study focuses on optimizing the geometric parameters of core components to enhance flow field stability and separation efficiency. Numerical simulations and experimental validations indicate that optimizing the underflow pipe length to 350 mm can effectively control the coupling effect between the cyclonic field and the settling zone. Furthermore, a baffle inclination angle of 60° was found to maximize flow field stability and achieve optimal separation performance under various flow velocity conditions.

Hydraulic fracturing technology is widely used to enhance the economic extraction of unconventional oil and gas resources. However, there is a lack of previous research on the hydraulic propagation behaviors of elliptical cracks under biaxial stress conditions. In this study, we combine laboratory experiments with a theoretical model to evaluate the influence of the viscosity of the fracture liquid, the external load, and the elastic modulus of the matrix on the propagation of an elliptical crack. Through experiments, we capture the development of the crack morphology and the evolution of the semi-major and semi-minor axes over time. The experimental observation reveals that the increase in the external loads and the liquid viscosity cause the crack to be more elliptical, while increasing the elastic modulus rounds the crack. Our theoretical model is built on the basis of a mechanical equilibrium between the critical pressure for the propagation of the crack determined by the properties of the material and the combined force of fluid pressure within the crack and external stress. Associated with two correction coefficients, the theoretical prediction is in good agreement with the experimental observation on the size of the crack. More importantly, we capture the systematic variation of the correction coefficient with key parameters, which provides a quantitative basis for parameter optimization based on formation characteristics in the practical hydraulic fracturing design.

Radiological assessment of petroleum source rocks from the Middle Magdalena Valley basin in Colombia.

As a core technology for the efficient and green stimulation of unconventional oil and gas reservoirs, pre-stage carbon dioxide (CO₂) fracturing relies on the unique properties of CO₂ including low viscosity, high diffusivity, easy phase transition, and energy enhancement for flowback improvement. It can effectively reduce reservoir breakdown pressure, activate natural fractures, mitigate water-sensitive formation damage, and facilitate carbon sequestration. However, current field applications are constrained by several critical issues, such as poor matching of injection parameters, insufficient accuracy in fracture network regulation, difficult wellbore phase-state control, and an imbalance between cost and benefit, which severely restrict its stimulation potential. Based on the fundamental mechanisms of pre-stage CO₂ fracturing, this paper systematically analyzes the key influencing factors for process optimization. Combined with the petrophysical properties of shale oil reservoirs in Sichuan, the CO₂ injection volume and rate are optimized, providing theoretical support for the efficient development of this block.

To address the challenges of low accuracy and complex influencing factors in predicting horizontal well fracturing productivity during the development of unconventional oil and gas resources such as tight oil, this paper proposes a productivity prediction framework based on an improved feature selection method and an ensemble learning model. This study employs a fusion analysis using the entropy weight method to combine Pearson correlation analysis and improved gray relational analysis (IGRA) for feature selection. Thirteen machine learning models were tested with six distinct parameter combinations to construct a Stacking-based ensemble learning model, with base models including Random Forest (RF), Ridge Regression (RR), and Artificial Neural Network (ANN). Particle Swarm Optimization (PSO) was employed to optimize hyperparameters, followed by interpretability analysis using SHapley Additive exPlanations (SHAP). The results indicate that the model with fused weights demonstrated optimal performance. The Stacking model achieved significantly improved accuracy after PSO optimization, with the coefficient of determination increasing by 4.9%, outperforming all comparison models. Engineering guidance is provided: Under current geological conditions, sand ratio and displacement fluid volume require fine-tuning to prevent over-treatment. Fracturing design should implement differentiated strategies based on the target sand body thickness. This study not only delivers a high-precision production prediction tool but also offers decision support for efficient unconventional oil and gas field development through its exceptional interpretability.

With the rapid development of unconventional oil and gas resources, shale has become an increasingly important energy source. However, its ultralow permeability and complex pore structure pose major challenges for efficient hydrocarbon recovery. Pore structure evolution induced by stress variation and fluid-rock interactions plays a decisive role in controlling flow pathways, breakthrough behavior, and permeability, yet the underlying mechanisms remain poorly understood. In this study, pore-scale computational fluid dynamics (CFD) simulations, stress sensitivity experiments, and nuclear magnetic resonance (NMR) pore structure characterization were integrated to investigate the coupled mechanical and chemical effects on permeability evolution in shale. Two-phase displacement simulations using the Volume of Fluid (VOF) method revealed that narrowing pore throats concentrates flow into fewer pathways, leading to earlier breakthrough and reduced sweep efficiency. Stress sensitivity experiments demonstrate severe permeability degradation, with maximum damage reaching up to 95.01% and irreversible losses as high as 73.33% in felsic shale, indicating the strong susceptibility of pore networks to effective stress. NMR results further show that slickwater exposure alters pore structure by reducing the fraction of clay interlayer pores from approximately 61.8% to 58.9%, accompanied by clay swelling and pore throat blockage. Notably, although total porosity slightly increases after fluid exposure, permeability decreases, highlighting the dominant role of pore connectivity loss over pore volume change. This integrated pore-scale and experimental investigation provides new insights into the mechanisms linking structural evolution to permeability decline, offering practical guidance for stimulation fluid design and pressure management strategies to reduce formation damage and enhance recovery.

As two important unconventional oil and gas resources, the in-situ pyrolysis technologies of tar-rich Coal and oil shale are key approaches to realize the clean and efficient utilization of resources, alleviate the contradiction between oil and gas supply and demand, and help achieve the “double carbon” goals. Both of them share the core characteristic of being rich in organic matter and convertible into oil and gas products through pyrolysis, yet they exhibit significant differences in resource endowments, pyrolysis characteristics and technological applications. This paper systematically combs the technical principles of in-situ pyrolysis for tar-rich Coal and oil shale, focuses on a comparative analysis of their similarities and differences in pyrolysis kinetics, process routes, key technologies and environmental impacts, and deeply analyzes the common bottlenecks and personalized challenges faced by the current in-situ pyrolysis technologies. It provides theoretical support and practical reference for the optimization and industrial promotion of in-situ pyrolysis technologies for tar-rich Coal and oil shale.

Editorial: advances in accumulation conditions of unconventional oil and gas resources in complicated structure areas

Pressure-regulated pore structure evolution and dielectric performance enhancement in MgO/epoxy composite systems

Unconventional oil production forecasting based on PiAM meta-learning

With the development of unconventional oil and gas resources (such as shale gas and tight oil/gas), the widespread application of multistage fracturing technology has significantly increased the difficulty of wellbore integrity maintaining. The cement sheath serves as the core barrier for preserving wellbore integrity, particularly at the first interface (cement–casing) and the second interface (cement–formation). The high temperature, high pressure, and cyclic dynamic loading imposed by multistage fracturing represent severe challenges to the integrity of cement sheath. To simulate underground conditions realistically, a high-temperature, complex stress path loading system coupled with real-time gas flow monitoring was developed. Using this system, gas leakage monitoring and displacement-controlled cyclic loading tests were conducted on cement–steel (simulating the first interface) and cement–shale (simulating the second interface) composite specimens. It focused on investigating the effects of different temperatures, cyclic stress levels, and cycle counts on the sealing performance of the cement–steel and cement–shale composites. The findings reveal that elevated temperatures significantly degrade cement properties and accelerate damage accumulation. Cyclic stress levels and cycle counts are core drivers of interface fatigue failure, exhibiting synergistic destructive effects with temperature. The first interface is more prone to seal failure due to material property differences and a relatively high stress level. This research elucidates the cumulative damage mechanism underlying interfacial seal failure. It is of significant engineering implications for enhancing well safety and development efficiency.