Search Results (140)

Underground gas storage (UGS) in heterogeneous carbonate reservoirs is crucial for energy security but frequently faces wellbore instability challenges, which traditional static methods struggle to address due to dynamic full life cycle changes. This study systematically analyzes the dynamic evolution of wellbore stress in the Bs8 well (Qianmiqiao carbonate UGS) during drilling, acidizing, and injection-production operations, establishing a quantitative risk assessment model based on the Mohr–Coulomb criterion. Results indicate a significantly higher wellbore instability risk during drilling and initial gas injection stages, primarily manifested as shear failure, with greater severity observed in deeper well sections (e.g., 4277 m) due to higher in situ stresses. During acidizing, while the wellbore acid column pressure can reduce principal stress differences, the process also significantly weakens rock strength (e.g., by approximately 30%), inherently increasing the risk of wellbore instability, though the primary collapse mode remains shallow shear breakout. In the injection-production phase, increasing formation pressure is identified as the dominant factor, shifting the collapse mode from initial shallow shear failure to predominant wide shear collapse, notably at 90°/270° from the maximum horizontal stress direction, thereby significantly expanding the unstable zone. This dynamic assessment method provides crucial theoretical support for full life cycle integrity management and optimizing safe operation strategies for carbonate gas storage wells. Full article

The sedimentary characteristics and model of the shallow-water delta front are of great significance for the development of oil and gas reservoirs. At present, there are great differences in the understanding of the distribution patterns of estuary dams in the shallow-water delta front. Therefore, this paper reveals the distribution characteristics of estuary dams through the detailed dissection of the Qing 1 Member in the Daqingzijing area and establishes a completely new distribution pattern of estuary dams. By using geological data such as logging and core measurements, sedimentary microfacies at the shallow-water delta front are classified and logging facies identification charts for each sedimentary microfacies are developed. Based on the analysis of single-well and profile facies, the sedimentary evolution laws of the Qing 1 Member reservoirs are analyzed. On this basis, the sedimentary characteristics and model of the lacustrine shallow-water delta front are established. The results indicate that the Qing 1 Member in the Daqingzijing area exhibits a transitional sequence from a delta front to pro-delta facies and finally to deep lacustrine facies, with sediments continuously retrograding upward. Subaqueous distributary channels and estuary dams constitute the skeletal sand bodies of the retrogradational shallow-water delta. The estuary dam sand bodies are distributed on both sides of the subaqueous distributary channels, with sand body development gradually decreasing in scale from bottom to top. These bodies are intermittently distributed, overlapping, and laterally connected in plan view, challenging the conventional understanding that estuary dams only occur at the bifurcation points of underwater distributary channels. Establishing the sedimentary characteristics and model of the shallow-water delta front is of great significance for the exploration and development of reservoirs with similar sedimentary settings. Full article

In comparison to shallow coal seams, deep coal seams exhibit characteristics of high temperature, pressure, and in-situ stress, leading to significant differences in reservoir properties that constrain the effective development of deep coalbed methane (CBM). This study takes the Carboniferous deep 8# coal seam in the Yulin area of Ordos basin as the research subject. Based on the test results from core drilling wells, a comprehensive analysis of the characteristics and variation patterns of coal reservoir properties and a comparative analysis of the exploration and development potential of deep CBM are conducted, aiming to provide guidance for the development of deep CBM in the Ordos basin. The research results indicate that the coal seams are primarily composed of primary structure coal, with semi-bright to bright being the dominant macroscopic coal types. The maximum vitrinite reflectance (R_o,max) ranges between 1.99% and 2.24%, the organic is type III, and the high Vitrinite content provides a substantial material basis for the generation of CBM. Longitudinally, influenced by sedimentary environment and plant types, the lower part of the coal seam exhibits higher Vitrinite content and fixed carbon (FC_ad). The pore morphology is mainly characterized by wedge-shaped/parallel plate-shaped pores and open ventilation pores, with good connectivity, which is favorable for the storage and output of CBM. Micropores (<2 nm) have the highest volume proportion, showing an increasing trend with burial depth, and due to interlayer sliding and capillary condensation, the pore size (<2 nm) distribution follows an N shape. The full-scale pore heterogeneity (fractal dimension) gradually increases with increasing buried depth. Macroscopic fractures are mostly found in bright coal bands, while microscopic fractures are more developed in Vitrinite, showing a positive correlation between fracture density and Vitrinite content. The porosity and permeability conditions of reservoirs are comparable to the Daning–Jixian block, mostly constituting oversaturated gas reservoirs with a critical depth of 2400–2600 m and a high proportion of free gas, exhibiting promising development prospects, and the middle and upper coal seams are favorable intervals. In terms of resource conditions, preservation conditions, and reservoir alterability, the development potential of CBM from the Carboniferous deep 8# coal seam is comparable to the Linxing block but inferior to the Daning–Jixian block and Baijiahai uplift. Full article

The Jidong Oilfield No. 2 Underground Gas Storage (UGS), located in an active fault zone in Northern China, is a key facility for ensuring natural gas supply and peak regulation in the Beijing–Tianjin–Hebei region. To evaluate the effectiveness of a combined surface and shallow borehole monitoring system under deep reservoir conditions, a 90-day microseismic monitoring trial was conducted over a full injection cycle using 16 surface stations and 1 shallow borehole station. A total of 35 low-magnitude microseismic events were identified and located using beamforming techniques. Results show that event frequency correlates positively with wellhead pressure variations instead of the injection volume, suggesting that stress perturbations predominantly control microseismic triggering. Events were mainly concentrated near the bottom of injection wells, with an average location error of approximately 87.5 m and generally shallow focal depths, revealing limitations in vertical resolution. To enhance long-term monitoring performance, this study recommends deploying geophones closer to the reservoir, constructing a 3D velocity model, applying AI-based phase picking, expanding array coverage, and developing a microseismic-injection coupling early warning system. These findings provide technical guidance for the design and deployment of long-term monitoring systems for deep reservoir conversions into UGS facilities. Full article

As a strategic replacement area for hydrocarbon exploration in the Tarim Basin, the Kuqa Depression has been the subject of relatively limited research on the sedimentary characteristics of the Triassic strata within its western Wushi Sag, which constrains exploration deployment in this region. This study focuses on the Wushi Sag, systematically analyzing the sedimentary facies types, the evolution of sedimentary systems, and the distribution patterns of the Triassic Kelamayi and Huangshanjie formations. This analysis integrates field outcrops, drilling cores, wireline logs, and 2D seismic data, employing methodologies grounded in foreland basin theory and clastic sedimentary petrology. The paleo-geomorphology preceding sedimentation was reconstructed through balanced section restoration to investigate the controlling influence of foreland tectonic movements on the distribution of sedimentary systems. By interpreting key seismic profiles and analyzing vertical facies successions, the study classifies and evaluates the petroleum accumulation elements and favorable source–reservoir-seal assemblages, culminating in the prediction of prospective exploration areas. The research shows that: (1) The Triassic in the Wushi Sag mainly develops fan-delta, braided-river-delta, and lacustrine–shallow lacustrine sedimentary systems, with strong planar distribution regularity. The exposed strata in the northern part are predominantly fan-delta and lacustrine systems, while the southern part is dominated by braided-river-delta and lacustrine systems. (2) The spatial distribution of sedimentary systems was demonstrably influenced by tectonic activity. Paleogeomorphological reconstructions indicate that fan-delta and braided-river-delta sedimentary bodies preferentially developed within zones encompassing fault-superposition belts, fault-transfer zones, and paleovalleys. Furthermore, Triassic foreland tectonic movements during its deposition significantly altered basin configuration, thereby driving lacustrine expansion. (3) The Wushi Sag exhibits favorable hydrocarbon accumulation configurations, featuring two principal source–reservoir assemblages: self-sourced structural-lithologic gas reservoirs with vertical migration pathways, and lower-source-upper-reservoir structural-lithologic gas reservoirs with lateral migration. This demonstrates substantial petroleum exploration potential. The results provide insights for identifying favorable exploration targets within the Triassic sequences of the Wushi Sag and western Kuqa Depression. Full article

Organic matter pores constitute a significant storage space in shale gas reservoirs, contributing to approximately 50% of the total porosity. This study employed a comprehensive approach, utilizing scanning electron microscopy, low-pressure N₂ adsorption, thermal analysis, image statistics, and fractal theory, to quantitatively characterize the structure and complexity of organic matter pores in the Wufeng–lower Longmaxi Formations (WLLFs). The WLLFs exhibit a high organic matter content, averaging 3.20%. Organic matter pores are typically well-developed, predominantly observed within organic matter clusters, organic matter–clay mineral complexes, and the internal organic matter of pyrite framboid. The morphology of these pores is generally elliptical and spindle-shaped, with the primary pore diameter displaying a bimodal distribution at 10~40 nm and 100~160 nm, potentially influenced by the observational limit of scanning electron microscopy. Shales from greater burial depths within the same gas well contain more organic matter pores; however, the development of organic matter pores in deep gas wells is roughly equivalent to that in medium and shallow gas wells. Fractal dimension values can be utilized to characterize the complexity of organic matter pores, with organic matter macropores (D_>50) being more complex than organic matter mesopores (D_2–50), which in turn are more complex than organic matter micropores (D_<2). The development of macropores and mesopores is a key factor in the heterogeneity of organic matter pores. The complexity of organic matter pores in the same well increases gradually with the burial depth of the shale, and the complexity of organic matter pores in deep gas wells is roughly equivalent to that in medium and shallow gas wells. The structure and fractal characteristics of organic matter pores in shale are primarily controlled by components, diagenesis, tectonism, etc. The lower Longmaxi shale exhibit a high biogenic quartz content and robust hydrocarbon generation from organic matter. This composition effectively shields organic matter pores from multi-directional extrusion, leading to the formation of macropores and mesopores without specific orientation. High-quality shale sections (one and two sublayers) have relatively high fractal dimension D_2–50 and D_>50 values of organic matter pores and gas content. Consequently, the quality parameters of shale and fractal dimension characteristics can be comprehensively evaluated to identify high-quality shale sections. Full article

Pore pressure prediction gives drillers an early warning of potential oil and gas kicks, enabling them to adjust mud weight pre-emptively. A kick causes a delay in drilling practices, blowouts, and jeopardization of the wells. Changes in pore pressure affect the type of fluid contact in the reservoir. This study predicted the pore pressure and determined fluid contacts within the Lower Cretaceous and early Upper Cretaceous (Barremian to early Cenomanian) sandstone reservoirs of the Bredasdorp Basin using well logs and repeat formation test (RFT) data from three wells: E-BK1, E-AJ1, and E-CB1. Eaton’s method of developing a depth-dependent Normal Compact Trend (NCT), using resistivity and sonic wireline logs, as well as other methods including the Mathews and Kelly, Baker and Wood, and Modified Eaton and Bowers methods, were employed for pore pressure prediction. Eaton’s method provided reliable pore pressure results in all the wells when compared to alternative methods in this study. Overburden gradient and predicted pore pressures ranged from 1.84 gm/cc to 2.07 gm/cc and from 3563.74 psi to 4310.06 psi, respectively. Eaton’s resistivity and density/neutron log method results indicated normal pressure in E-BK1 and E-AJ1, as well as overpressured zones in E-AJ1. However, in E-CB1, the results showed only overpressured zones. The E-AJ1 significant overpressures were from 2685 m to 2716 m and from 2716 m to 2735 m in the pores exceeding 7991.54 psi. Gas–water contact (GOC) was encountered at 2967.5 m in E-BK1, while oil–gas contact (OGC) was at 2523 m in E-CB1, and gas–oil and oil–water contacts (GOC and OWC) were at 2699 m and 2723 m, respectively, in E-AJ1. In E-CB1, oil–water contact (OWC) was at 2528.5 m. Fluid contacts observed from the well logs and RFT data were in close agreement in E-AJ1, whereas there was no agreement in E-CB1 because the well log observations showed a shallower depth compared to RFT data with a difference of 5.5 m. This study illustrated the significance of an integrated approach to predicting fluid contacts and pore pressure within the reservoirs by showing that fluid contacts associated with overpressures were gas–water and oil–water contacts. In contrast, gas–oil contact was associated with normal pressure and under pressure. Full article

Numerous uncertainties persist regarding the differential enrichment mechanisms of shale gas reservoirs in southern China. This investigation systematically examines the sedimentary environments and reservoir characteristics of the Wufeng–Longmaxi formations in the Changning area of the Sichuan Basin, through the integration of comprehensive drilling data, core samples, and analytical measurements. Multivariate sedimentary proxies (including redox conditions, terrigenous detrital influx, basinal water restriction, paleoclimatic parameters, paleowater depth variations, and paleo-marine productivity) were employed to elucidate environmental controls on reservoir development. The research findings demonstrate that during the depositional period of the Wufeng Formation in the Changning area, the bottom water was characterized by suboxic to anoxic conditions under a warm-humid paleoclimate, with limited terrigenous detrital input and strong water column restriction throughout the interval. Within the Longmaxi Formation, the depositional environment evolved from intensely anoxic conditions in the LM1 through suboxic states in the LM3 interval, approaching toxic conditions by the LM2 depositional phase. Concurrently, the paleoclimate transitioned towards warmer and more humid conditions, accompanied by progressively intensified terrigenous input from the LM1-LM6, while maintaining semi-restricted water circulation. Both paleowater depth and paleoproductivity peaked from the Wufeng Formation to the LM1 interval, followed by gradual shallowing of water depth and declining productivity during the LM3–LM6 depositional phases. Comparative analysis of depositional environments and reservoir characteristics reveals that sedimentary conditions exert a controlling influence on multiple reservoir parameters, including shale mineral composition, organic matter enrichment, pore architecture, petrophysical properties (e.g., porosity, permeability), and gas-bearing potential. Full article

Recently, shallow gas fields and hydrate-bearing sand in the deepwater area of the northern South China Sea have been successively discovered, and the accurate prediction of shallow sands is an important foundation. However, most of the current prediction methods are mainly for deep oil and gas reservoirs. Compared with those reservoirs with high degree of consolidation, shallow sandy reservoirs are loose and unconsolidated, whose geophysical characteristics are not well understood. This paper analyzes the logging data of shallow sandy reservoirs recovered in the South China Sea recently, which show that the sand content has a significant influence on Young’s modulus and Poisson’s ratio of the sediments. Therefore, this paper firstly constructs a new petrophysical model of unconsolidated strata targeting sandy content and qualitatively links the mineral composition and the elastic parameters of the shallow marine sediments and defines a new indicator for sandy content: the modified brittleness index (MBI). The effectiveness of MBI in predicting sandy content is then verified by measured well data. Based on pre-stack seismic inversion, the MBI is then inverted, which will identify the sandy deposits. The method proposed provides technical support for the subsequent shallow gas and hydrate exploration in the South China Sea. Full article

Paleoenvironmental knowledge holds significant scientific value for elucidating the evolutionary history of Earth’s crust and for guiding the exploration of oil and gas resources. This study presents a comprehensive analysis of sporopollen–algae fossils from Well DW-2, located in the Zhu II Depression of the eastern South China Sea. The sampled strata of the well were from 0 to 3230 m in depth, with a substantial number of sporopollen–algae fossils identified within the Enping and Zhuhai Formations spanning from 2501 to 3227 m. Two distinct sporopollen–algae assemblages were delineated from bottom to top. The sporopollen characteristics reveal a transition from tropical and subtropical to subtropical and temperate plant communities, reflecting the warm and humid climate during the formation of the Enping Formation and the relatively cool and dry climate during the formation of the Zhuhai Formation. A significant number of marine dinoflagellate fossils were identified, and the observed changes in algal characteristics suggest that the Enping Formation was accumulated in a shallow marine environment, while the Zhuhai Formation was predominantly formed in a transitional setting between marine and terrestrial conditions at the shelf margin. These findings not only enhance our understanding of the paleoenvironmental conditions in the South China Sea region but also have broader implications for reconstructing global paleoclimates and identifying potential hydrocarbon reservoirs in similar sedimentary basins. Full article

As the energy sector transitions toward decarbonisation, low-to-intermediate temperature geothermal resources in sedimentary basins—particularly repurposed oil and gas fields—have emerged as promising candidates for sustainable heat and power generation. Despite their widespread availability, the development of these systems is hindered by gaps in methodology, oversimplified modelling assumptions, and a lack of integrated analyses accounting for long-term reservoir and wellbore dynamics. This study presents a detailed, simulation-based framework to evaluate geothermal energy extraction from depleted petroleum reservoirs, with a focus on low-enthalpy resources (<150 °C). By examining coupling reservoir behaviour, wellbore heat loss, reinjection cooling, and surface energy conversion, the framework provides dynamic insights into system sustainability and net energy output. Through a series of parametric analyses—including production rate, doublet spacing, reservoir temperature, and field configuration—key performance indicators such as gross power, pumping requirements, and thermal breakthrough are quantified. The findings reveal that: (1) net energy output is maximised at optimal flow rate (~70 kg/s for a 90 °C reservoir), beyond which increased pumping offsets thermal gains; (2) doublet spacing has a non-linear impact on reinjection cooling, with larger distances reducing thermal interference and pumping energy; (3) reservoirs with higher temperatures (<120°C) offer significantly better thermodynamic and hydraulic performance, enabling pump-free or low-duty operations at higher flow rates; and (4) wellbore thermal losses and reinjection effects are critical in determining long-term viability, especially in low-permeability or shallow fields. This work demonstrates the importance of a coupled, site-specific modelling in assessing the geothermal viability of petroleum fields and provides a foundation for future techno-economic and sustainability assessments. The results inform optimal design strategies and highlight scenarios where the geothermal development of oil and gas fields can be both technically and energetically viable. Full article

This study identifies the following three key factors controlling shale gas reservoirs in the lower Cambrian Niutitang Formation, northern Guizhou, China: sedimentary features, diagenetic modification, and stable tectonic conditions. This research addresses gaps in previous studies by investigating how tectonic and diagenetic conditions contribute to the unique characteristics of shale gas enrichment in tectonically complex areas with high thermal maturity (R_o > 2.5%). Sedimentary conditions revealed a positive correlation between total organic carbon (TOC) content and gas adsorption capacity, with higher TOC enhancing adsorption. Experimental data indicate that the TOC content (2.33%–9.07%) significantly correlates with methane adsorption capacity (Langmuir volume VL = 1.87–8.78 cm³/g at 30 °C and 10 MPa), as evidenced by the linear relationship between TOC and VL in shale samples. Clay mineral content exhibited a dual role as moderate levels (15%–25%) improved adsorption, while excessive amounts (>30%) reduced efficiency due to pore occlusion. Diagenesis, including compaction, cementation, and thermal evolution of organic matter, significantly reshaped reservoir porosity. Quantitative analysis of core samples demonstrates that compaction caused a porosity reduction of 18%–25% in samples with burial depths exceeding 1500 m, thereby influencing gas retention capacity. The reservoir has entered the anchizone (average vitrinite reflectance R_o = 2.54%), characterized by advanced organic matter maturation and widespread organic porosity development. Tectonic activity was critical for gas retention; intense tectonic activity led to shallower burial depths and gas loss, whereas structurally stable areas favored preservation. This study emphasizes the significance of tectonic conditions and their role in maintaining gas reservoirs in the anchizone, reconciling discrepancies in gas storage mechanisms observed in basins with similar TOC and thermal maturity. In summary, deep marine shale gas enrichment relies on the synergistic effects of high-quality sedimentary foundations (TOC > 4%, quartz > 30%), diagenetic evolution optimizing pore structures, and stable tectonic conditions ensuring gas retention. These findings provide new insights into the exploration of shale gas in complex tectonic regions and offer a framework for improving prediction models in shale gas enrichment by integrating micro-scale organic–inorganic interactions with macro-scale tectonic controls. Full article

The transition zone between a shallow-water delta and tidal flat is characterized by a high degree of mixed siliciclastic–carbonate sedimentation. There are frequent lateral and vertical variations in sandstone, dolostone, limestone, and mixed siliciclastic–carbonate rock (MSR); however, their influence on reservoir quality remains uncertain. Member B of the Asmari Formation (Asmari B) in Iraq’s C Oilfield was deposited in a remnant ocean basin formed by the closure of the Neo-Tethys Ocean. During the Oligocene–Miocene, frequent exposure of the Arabian Shield provided intermittent sediment sources to the study area. Under shallow water and relatively arid conditions, widespread mixed sedimentation of siliciclastic sand and dolomitic components occurred. Taking Asmari B as a case study, this research employs core and thin-section observations, trace element analyses, and quantitative mineralogical interpretations of logging data to investigate the characteristics of mixed sedimentation and to evaluate its impact on reservoir quality. Four key aspects were identified: (1) Four main types of mixed lithofacies developed in Member B of the Asmari Formation, namely sandstone-bearing dolomite, dolomitic sandstone, dolostone-bearing sand, and sandy dolostone. These lithofacies were deposited in the transition zone between distributary channels and intertidal zone with different water depths. As the terrigenous input decreased, the water depth for sand-bearing facies increased. In particular, sandy dolostone was predominantly formed in subtidal settings under the influence of storm events. (2) MSRs are categorized based on the proportion of the minor component into high and low mixing degrees. Based on mineral compositions interpreted from well logging data, the mixing degree of MSRs was characterized by the thickness ratio, using the thickness of high- and low-mixing-degree MSRs relative to the total thickness of the formation. The MSRs mainly developed in the B1, B2, B3-1, B3-2, and B4 sublayers, where moderate provenance supply facilitated the high mixing of terrigenous clastic and carbonate components. (3) The pore and throat patterns of MSR reservoirs change with the mixing degree index. When the dolomite content in sandstone exceeds 25%, the pore–throat structure changes significantly. A small amount of sand in dolostone has little effect on the pore and throat. Sandy dolostone exhibits the poorest reservoir quality. (4) Mixed sandstone reservoirs are distributed on both sides of the distributary channels and mouth bar. The dolostone-bearing sand reservoirs are distributed in the transition zone between the sandy flat and dolomite flat. Sandy dolostone is mainly thin and isolated due to the influence of storm events. This study provides guidance for understanding the development patterns of MSR reservoirs under similar geological settings, facilitating the next step of oil and gas exploration in these special reservoirs. Full article

On 23 January 2024, a M_S7.1 earthquake struck Wushi County, Xinjiang Uygur Autonomous Region, marking the largest seismic event in the Southern Tianshan (STS) region in the past century. This study investigates the relationship between hydrothermal fluid circulation and seismic activity by analyzing the chemical composition and origin of fluids in natural hot springs along the Maidan Fracture (MDF). Results reveal two distinct hydrochemical water types (Ca-HCO₃ and Ca-Mg-Cl). The δD and δ¹⁸O values indicating spring water are influenced by atmospheric precipitation input and altitude. Circulation depths (621–3492 m) and thermal reservoir temperatures (18–90 °C) were estimated. Notably, the high ³He/⁴He ratios (3.71 Ra) and mantle-derived ³He content reached 46.48%, confirming that complex gas–water–rock interactions occur at fracture intersections. Continuous monitoring at site S13 (144 km from the epicenter of the Wushi M_S7.1 earthquake) captured pre-and post-seismic hydrogeochemical fingerprints linked to the Wushi MS7.1 earthquake. Stress accumulation along the MDF induced permeability changes, perturbing hydrogeochemical equilibrium. At 42 days pre-Wushi M_S7.1 earthquake, δ¹³C DIC exceeded +2σ thresholds (−2.12‰), signaling deep fracture expansion and CO₂ release. By 38 days pre-Wushi M_S7.1 earthquake, Na⁺, SO₄²⁻, and δ¹⁸O surpassed 2σ levels, reflecting hydraulic connection between deep-seated and shallow fracture networks. Ion concentrations and isotope values showed dynamic shifts during the earthquake, which revealed episodic stress transfer along fault asperities. Post-Wushi M_S7.1 earthquake, fracture closure reduced deep fluid input, causing δ¹³C DIC to drop to −4.89‰, with ion concentrations returning to baseline within 34 days. Trace elements such as Be and Sr exhibited anomalies 12 days before the Wushi M_S7.1 earthquake, while elements like Li, B, and Rb showed anomalies 24 days after the Wushi M_S7.1 earthquake. Hydrochemical monitoring of hot springs captures such critical stress-induced signals, offering vital insights for earthquake forecasting in tectonically active regions. Full article

Fuzzy-ball fluids have emerged as a novel class of chemical sealaplugging materials with significant potential for enhancing both traditional oilfield operations and clean energy technologies. They are characterized by unique viscoelastic properties, plugging, self-adapting capabilities, and the ability to regulate multi-phase fluid flow under extreme subsurface conditions. In oilfield applications, fuzzy-ball fluids offer solutions for drilling, hydraulic fracturing, workover operations, and enhanced oil recovery in shallow, deep, and offshore reservoirs. In clean energy fields such as hydrogen storage, carbon capture, utilization, and storage, and geothermal energy, they show promise in improving energy efficiency, storage security, and environmental sustainability. This review explores the fundamental principles and mechanisms behind fuzzy-ball fluids, examines their field applications in the oil and gas industry, and investigates their potential in emerging clean energy technologies. This study also identifies key challenges, including material stability, economic viability, and environmental impact, which must be addressed to ensure the successful deployment of fuzzy-ball fluids. Furthermore, we outline future research directions, emphasizing material optimization, large-scale field trials, environmental impact assessments, and interdisciplinary collaboration to accelerate the commercialization of fuzzy-ball fluid technologies. By addressing these challenges, fuzzy-ball fluids could play a transformative role in both conventional and clean energy fields, contributing to sustainable and efficient energy solutions. Full article