This study provides a comprehensive review of nano-particles and nano-composites applications in oilfield, focusing on their roles in enhanced oil recovery (EOR), asphaltene deposition mitigation, and CO₂ storage. Building on prior research, it identifies the most promising nanotechnology-based approaches and outlines a detailed roadmap for future breakthroughs. Thus, in this regard, the review evaluates 21 nanomaterials, including Al₂O₃ (γ/α phases), SiO₂, MgO, CuO, ZrO₂, NiO, graphene oxide (GO), SnO, CaCO₃, CeO₂, TiO₂, carbon nanotubes (CNT), and hybrid composites (e.g., SiO₂/γ-Al₂O₃, TiO₂/MgO, ZnO/γ-Al₂O₃, ZnO/CuO, ZnO/ZrO₂, TiO₂/SiO₂, TiO₂/ZnO, Fe₃O₄/SiO₂, and CuO/Al₂O₃), demonstrating their superior performance in improving operational efficiency. The findings demonstrate that nanotechnology offers superior performance, highlighting its potential to revolutionize the oil industry by improving oil production efficiency. On the other hand, nano-particles such as ZnO, Al₂O₃, SiO₂, and TiO₂ stand out due to their strong adsorption capacity, thermal stability, and ability to tune deposition mechanisms. Also, notably, nano-composites (such as SiO₂+Al₂O₃ and Fe₂O₃+Al₂O₃) excel in asphaltene inhibition due to synergistic nano-particle-hydrocarbon interactions. The results also show that nano-composites (TiO₂@SiO₂) increase the integrity of CO₂ storage. Generally, this study highlights key challenges hindering large-scale implementation and serves as a critical resource for researchers advancing nanotechnology in petroleum engineering.

A comprehensive study was conducted on the hydrocarbon generation potential of the deeply buried Permian source rocks with high-over mature in the southwestern part of the Central Depression, Junggar Basin. Using rock-eval pyrolysis, carbon-sulfur analysis, kerogen macerals analysis, adamantane quantification, molecular geochemistry, and major and trace element analysis, coupled with organic carbon recovery methods. The evaluation primarily focused on thermal maturation, types, and abundance of organic matter, with an emphasis on summarizing methods for evaluating high-over mature source rocks. The results demonstrate that the Permian source rocks in the Shawan Sag (Well Zhengshen-101) and the Penyijingxi Sag (Well Zhuangshen-1) have reached a high-over mature stage, as evidenced by vitrinite reflectance (Ro), adamantane parameters, methyl phenanthrene indices (MPI), and Laser Raman spectroscopy. Horizontally, for the Fengcheng (P₁f) and Lower Wuerhe (P₂w) formations, the Well Zhengshen-101 in the Shawan Sag is thermally more matured than the Well Zhuangshen-1 in the Penyijingxi Sag, while vertically, both wells show that the P₁f is thermally more mature than the P₂w. Raman and Fourier transform infrared (FTIR) spectroscopy confirm that Type II kerogen is the dominant organic matter type. Through material balance, degradation ratio, and inorganic element methods, obtain the original content of organic carbon (TOC₀) and hydrocarbon generation potential (S₁+S₂). After restoration, the P₁f samples from Well Zhengshen-101 in the Shawan Sag show moderate to high-quality organic matter abundance, predominantly high-quality; the P₂w samples are classified as high-quality source rocks. The Xiazijie Formation (P₂x) and the P₂w samples from Well Zhuangshen-1 in the Penyijingxi Sag range from poor to high-quality, predominantly good to high-quality. Horizontally, the P₂w samples from Well Zhengshen-101 in the Shawan Sag exhibit higher organic matter abundance compared to those from Well Zhuangshen-1 in the Penyijingxi Sag. Notably, the P₂x source rocks in the Penyijingxi Sag demonstrate superior potential compared to the P₂w, highlighting their underexplored significance. Comprehensive analysis of the depositional environment in the study area indicates that the Well Zhengshen-101 in the Shawan Sag may experience a deeper, stable reducing environment with moderate sedimentation rates, stable water stratification, and a more abundant nutrient supply, all of which favor organic matter enrichment. This systematic evaluation advances methodologies for assessing high-over mature source rocks and underscores the exploration potential of high-over mature Permian source rocks in the Junggar Basin. Meanwhile, comparison with the highly mature marine shales of the Sichuan Basin further accentuates the methodological innovation of this study.

The Obaiyed Gas Field is a significant gas-producing field in the northern Western Desert of Egypt. It is considered a tight gas reservoir because of its highly compact nature resulting from its intensive diagenetic history. This study presents a profound investigation and an integrated assessment of petrophysical and geological data, comprising core measurements, well logs for formation evaluation, sedimentological studies, and diagenetic modifications. The investigation focuses on characterizing the heterogeneous reservoirs of the siliciclastic sequences of the Lower Paleozoic-Middle Jurassic sequence, intending to aid in the exploration and development of hydrocarbon reservoirs in the Obaiyed Field. Several petrophysical parameters, such as the discrete rock type, reservoir quality index, normalized porosity index, flow zone indicator, and effective pore throat radius, were calculated to assess the quality of the reservoirs being studied. Seven microfacies were identified and summed into 5 reservoir rock types (RRTs). The quartz arenite and kaolinitic quartz arenite of the Lower Safa Member had the best reservoir quality. The micaceous clayey and siliceous quartz arenite of the Shifah Formation have the lowest quality. The main dominant key diagenetic features that control reservoir quality are compaction, cementation, quartz overgrowth, dispersed authigenic minerals, fracturing, and dissolution. Reservoir zonation shows that the Shifah Formation is not as promising as the Lower Safa Member because of its highly heterogeneous nature. The southeastern and central regions of the field exhibit a significant increase in the reservoir quality. The applied workflow is applicable to the other gas/condensate fields in the Western Desert and NE Africa, which are similar in the same stratigraphic and structural settings.

Silica fume (SF) is commonly added to lightweight cement slurry (LWCS) to enhance strength and stability due to its nanoscale properties. However, the long-term strength development of SF-modified cement remains unclear. This study explores the effect of SF on the long-term strength of LWCS cured at 75 °C, 90 °C, and 105 °C, using compressive strength tests and microstructural analyses (XRD, SEM, EDS, TGA). SF initially improves strength through pozzolanic reactions, but over time, the C-S-H gel formed during hydration becomes more porous and looser. The addition of SF promotes the transformation of the C-S-H gel from a high Ca/Si ratio to a lower one, with rapid CH consumption accelerating porosity development. This weakens the bond between cement and hollow glass microspheres (HGMs), causing microcracks from stress differentials. These changes lead to internal bond deterioration and up to 56.76% strength reduction. While SF enhances early strength, it negatively affects long-term strength, raising the risk of cementing failure in oil and gas wells. Future research should focus on addressing long-term strength decline at higher temperatures and identifying alternative materials to mitigate this issue.

High-pressure and high-temperature (HPHT) drilling environments challenge the stability and efficiency of conventional oil-based drilling fluids (OBDFs). This study introduces a novel dual-organoclay (OC) formulation combining Claytone-II and Claytone-IMG 400 at a 1:1 ratio, designed to enhance OBDF performance under HPHT conditions. The selected OCs possess distinct mineralogies: one is rich in anorthite, while the other is dominated by montmorillonite, offering complementary properties. Comprehensive characterization using X-ray diffraction (XRD), X-ray fluorescence (XRF), scanning electron microscopy (SEM), and particle size distribution (PSD) analysis revealed significant structural and compositional differences that underpin the observed synergy.

Experimental evaluation showed that the OC mixture outperformed individual OCs and a commercial benchmark (MC-TONE) in critical areas including rheology, filtration, and sag stability. Under 275 °F and 500 psi conditions, the dual-OC system improved plastic viscosity by 15.5%, yield point by 33%, and reduced filtrate volume and filter cake thickness by 16.5% and 11.5%, respectively. These enhancements contribute to better cuttings transport, reduced fluid loss, and improved wellbore stability.

The approach offers a cost-neutral yet performance-enhancing solution using commercially available OCs. It holds promise for extending OBDF applicability in HPHT wells while supporting safer, more efficient, and environmentally responsible drilling operations.

Cementing in deep and ultra-deep reservoirs often faces the critical challenge of additive degradation in high-temperature environments. Addressing this, 1-vinylimidazole (VM) was incorporated into the copolymerization of N,N-dimethylacrylamide, itaconic acid, and 2-acrylamido-2-methylpropanesulfonic acid to synthesize a tetrapolymer (PDVI). Using aqueous free radical polymerization optimized by response surface methodology, the resulting PDVI exhibited superior fluid loss reduction in high-temperature and high-salinity conditions. Compared to the control sample PDI, PDVI reduced fluid loss from 64.7 mL to 25 mL at 200 °C and from 105.7 mL to 42.5 mL at 240 °C, while maintaining filtration below 70 mL in 20% NaCl. Structural characterization via 1H NMR and FTIR, combined with TGA and aging tests, confirmed that VM's rigid five-membered ring significantly enhanced thermal stability; molecular weight retention after aging at 220 °C increased from 46.13% to 68.31%. Furthermore, DLS, SEM, and zeta potential analyses indicated that VM's cationic nature facilitates robust polymer adsorption on cement particles. This mechanism ensures effective particle dispersion and the formation of a dense filter cake even under extreme conditions. These findings provide essential insights for developing high-performance polymeric additives for cementing in complex downhole environments.

With the continuous growth of global energy demand, shale oil, as an important unconventional oil and gas resource, is increasingly highlighting its strategic position. As one of the key means of shale oil development, supercritical carbon dioxide (CO₂) flooding technology has significant advantages in reducing crude oil viscosity, improving reservoir pore structure and fluid occurrence state, thereby effectively enhancing oil recovery. The molecular simulation method provides an effective way to reveal the microscopic mechanism of CO₂ flooding. In this paper, based on the molecular dynamics simulation method, a multi-component system model including supercritical CO₂, organic-inorganic composite wall and crude oil is constructed. The microscopic mechanism of competitive adsorption between supercritical CO₂ and components in both single-component and multi-component oil phase is systematically investigated. The effects of wall type, temperature and CO₂ injection pressure on competitive adsorption behavior are clarified. The results show that the competitive adsorption of supercritical CO₂ varies significantly among different shale oil compoents. The competitive adsorption efficiencies of supercritical CO₂ for the single-component systems, n-hexane, toluene, acetic acid, and n-dodecane, are 55.17%, 51.72%, 44.83%, and 27.59%, respectively. In the multi-component oil system, the competitive adsorption efficiencies of supercritical CO₂ are as follows: n-hexane (66.58%), n-dodecane (47.06%), toluene (49.46%), and acetic acid (78.78%). This indicates that the competitive adsorption efficiency is closely related to the molecular polarity, molecular weight and the component's position in the adsorption layer. In addition, the competitive adsorption efficiency of CO₂ for n-hexane first increases and then decreases with increasing temperature, reaching a maximum of 50.57% at 383.15K and the injection pressure of 10.5 MPa. The increase of injection pressure significantly improves the competitive adsorption efficiency, and 10.5 MPa is considered as the minimum miscibility pressure (MMP). This study reveals the competitive adsorption mechanism between supercritical CO₂ and shale oil at the molecular scale, thus providing theoretical support for the technical optimization and scheme design of shale oil of efficienyt development through CO₂ injection.

This study presents recent advances in modeling capacity and provides optimization guidelines for key operational parameters controlling well performance, using real well data. A new Gaussian solution method can both accurately forecast well rates prior to drilling and history match actual well performance after completion once early production data become available. Unlike other history-matching tools, excellent matches are achieved with daily production data spanning just a few months. The study also addresses key challenges in achieving precision in hydraulic fracturing and horizontal well design, emphasizing unresolved subsurface heterogeneity, variability in treatment quality, and modeling tool limitations. Advanced analytical methods, such as the Gaussian Production Forecasting (GPT) method, offer improved accuracy and computational efficiency for production predictions. Empirical data from the Eagle Ford and Wolfcamp formations demonstrate significant performance gains over the past decade, driven by optimized fracture spacing, increased lateral lengths, and enhanced proppant usage. However, performance gaps persist due to poor proppant conductivity, closure stress impacts, and proppant transport inefficiencies. This study highlights the critical impact of fracture conductivity damage on shale well performance, as revealed by Gaussian well performance curves derived from historical data. The findings emphasize the need for integrating advanced modeling tools, optimizing proppant delivery strategies, and improving transport simulations to achieve sustained productivity gains in shale reservoirs.

Laminated continental shale oil reservoirs have the potential for commercial development. In this paper, a new simulation method for interlayer and intra-layer coupled flow in laminated shale reservoirs is established. This method simulates the structural characteristics of shale-sandstone longitudinal interlayer distribution by dual-porositysystem, and combines with chemical reaction model to characterize the desorption process of ad-/absorbed oil from kerogen in shale layers. Then, the intra-layer and interlayer interfacial flow mechanism in the depletion process is investigated, and the contribution of interfacial flow and desorption is analyzed. The results indicate that the sandstone layer is the main oil-producing layer, accounting for over 90% of the total oil production. However, the interlayer flow and kerogen desorption in the shale layers make significant contributions, resulting in an enhancement of 13.41% and 42.64% in the total oil production, respectively. Additionally, the desorption of ad-/absorbed oil from kerogen enhances the energy of both the shale and sandstone layers, significantly increasing their production. Moreover, higher pressure drawdown, total organic carbon (TOC) content, desorption rate, and horizontal permeability of sandstone layers are advantageous for the exploitation of shale oil.

CO₂ flooding has emerged as a valuable method for enhancing oil recovery (EOR) in fossil fuel reservoirs. However, the impact of micro-heterogeneity, particularly variations in pore sizes, on CO₂ flooding following water flooding in conglomerate reservoirs remains insufficiently understood. This study introduces an advanced visual model integrating outcrop and nuclear magnetic resonance (NMR) analyses to overcome the limitations of traditional micromodels. Simulating reservoir conditions, the model evaluates oil displacement and sweep efficiency through a fractal-based pore classification system, categorizing pores into four types: small pores (P1), medium pores (P2 and P3), and large pores (P4). This classification provides a comprehensive analysis of residual oil patterns during water and CO₂ flooding. Results show that water flooding primarily displaces oil from larger pores (P3 and P4), leaving residual oil trapped in smaller pores (P1 and P2). After 0.4 PV injection, oil begins migrating from smaller to larger pores(P4), reaching an oil recovery efficiency of 28.91% at 0.8 PV. In contrast, CO₂ flooding significantly expands the sweep area and improves displacement efficiency despite minor gas channeling. NMR analysis indicates that CO₂ flooding rapidly mobilizes oil in large pores (P4), while its effect on smaller pores (P1 and P2) remains limited. The cumulative signal amplitude decreases from 2914 to 2498, resulting in a displacement efficiency of 10.15% and a total recovery factor of 39.06%. This study provides valuable insights into optimizing CO₂ immiscible flooding strategies and improving oil recovery efficiency in tight conglomerate reservoirs.

As one of the most probable natural hazards leading to technological disasters, lightning can easily damage analytical instruments in oil and gas stations, resulting in data loss and operational anomalies. Compared with other equipment, Natural Gas Automated Metering Systems (NGAMS), which comprise various precision analytical instruments, are more susceptible to lightning strikes. This vulnerability often leads to production shutdowns, inaccurate metering, and commercial disputes. A quantitative risk assessment model for lightning-induced failures in NGAMS is proposed to enhance the integrity management of metering stations. The model consists of a lightning failure probability model and a consequence evaluation method that incorporates reputational loss. First, a lightning identification criterion is established based on the electro-geometric model, and a basic lightning probability model is developed using Monte Carlo simulations. Second, a basic failure probability model is constructed by modeling the system's equivalent circuit and incorporating the insulation withstand characteristics of the equipment. Two correction factors, specifically the location factor and lightning protection measures, are subsequently incorporated to establish the comprehensive lightning failure probability model. Furthermore, a reputational loss evaluation method is proposed by developing a reputation loss indicator system and integrating the Z-BWM method with cloud model. Case study results show that when the average lightning probability is 1.03 × 10⁻², the maximum system failure probability reaches 4.14 × 10⁻⁵, representing a 35.29% increase over the inherent failure probability. The corresponding reputational loss is classified as low risk, verifying the effectiveness and practicality of the proposed model.

In response to the increasing risk of well integrity failure during carbon dioxide capture, utilization and storage (CCUS), a multi-index evaluation and recommendation model based on the game theory combination-authority-DHHFLOWLAD was proposed to achieve the risk assessment of well integrity in CCUS and the selection of risky well treatment solutions in the same model. Through literature research, reference to relevant safety standards and norms, and expert inquiries, the Bow-tie diagram of wellbore integrity failure was established, the wellbore failure mechanism was analyzed, and the dual-layer hesitation fuzzy language (DHHFL) characteristics were combined to screen evaluation indicators to construct the CCUS wellbore integrity risk evaluation index system. Experts were invited to use DHHFL data for complex language evaluation and expected value transformation. Game theory combined analytic hierarchy process (AHP) and entropy weight method were used to complete the optimization of comprehensive weights. The ordered weighted logarithmic mean distance (OWLAD) operator was introduced to aggregate the distance measurement between the well shaft and the scheme by combining the optimization weights of different indicators. Complete the recommendation of well risk assessment and management recommendations, and provide more accurate, scientific and practical guidance for CCUS well integrity evaluation and management.