Search Results (87)

Natural fractures in tight sandstone reservoirs are the key factors controlling hydrocarbon flow and productivity. The Bozi-1 gas reservoir in the Kuqa Depression, as a typical ultra-deep tight sandstone gas reservoir, is characterized by low-porosity and ultra-low-permeability sandstones. This study addresses the limitations of previous fracture characterization, which primarily focused on macro-structural fractures while neglecting medium- and small-scale fractures. We integrate multi-source heterogeneous data, including core, well-logging imaging, seismic, and production observations, to systematically conduct multi-scale natural fracture characterization and modeling. First, the overall geology of the study area is briefly introduced, followed by a detailed description of the development characteristics of large-scale and medium–small-scale fractures, achieving a multi-scale representation of complex curved fracture networks. Finally, the three-dimensional multi-scale fracture model is validated using static indicators, including production characteristics, water invasion features, and well leakage data. The main findings are as follows: (1) Large-scale fractures in the Bozi-1 reservoir are mainly oriented near EW, NE–SW, and NW–SE, acting as the primary hydrocarbon migration pathways. Medium–small-scale fractures predominantly develop near SN, NE–SW, NW–SE, and near EW directions, exhibiting strong heterogeneity. (2) The complex curvature of large-scale fractures was captured by the “adaptive sampling + segmented splicing + equivalent distribution of fracture flow capacity” method, while the distribution of effective medium–small-scale fractures across the study area was represented using “single-well Stoneley wave inversion + seismic machine learning prediction”, achieving an 86% match with actual single-well measurements. (3) Model reliability was further verified through static comparisons, including production characteristics (unimpeded flow vs. effective fracture density, R² = 0.92), water invasion features (fracture-dominated water invasion matching fracture distribution), and well leakage characteristics (matching rate of high fracture density zones: 84.2%). The results provide key technical support for the precise characterization of fracture systems and establish a model ready for dynamic simulation in ultra-deep tight sandstone gas reservoirs. Full article

The Tarim Basin is currently the largest petroliferous basin in China, with hydrocarbons primarily hosted in Ordovician marine carbonate paleokarst fracture–vug reservoirs—a typical example being the Tahe Oilfield located in the northern structural uplift of the basin. The principle of “the present is the key to the past” serves as a core method for studying paleokarst fracture–vug reservoirs in the Tahe Oilfield. The deep and ultra-deep carbonate fracture–vug reservoirs in the Tahe Oilfield formed under humid tropical to subtropical paleoclimates during the Paleozoic Era, belonging to a humid tropical–subtropical paleoepikarst dynamic system. Modern karst types in China are diverse, providing abundant modern karst analogs for paleokarst research in the Tarim Basin. Carbonate regions in Eastern China can be divided into two major zones from north to south: the arid to semiarid north karst and the humid tropical–subtropical south karst. Karst in Northern China is characterized by large karst spring systems, with fissure–conduit networks as the primary aquifers; in contrast, karst in Southern China features underground river networks dominated by conduits and caves. From the perspective of karst hydrodynamic conditions, the paleokarst environment of deep fracture–vug reservoirs in the Tarim Basin exhibits high similarity to the modern karst environment in Southern China. The development patterns of karst underground rivers and caves in Southern China can be applied to comparative studies of carbonate fracture–vug reservoir structures in the Tarim Basin. Research on modern and paleokarst systems complements and advances each other, jointly promoting the development of karstology from different perspectives. Full article

Deep and ultra-deep petroleum resources have become major contributors to petroleum reserves. The Tarim Basin has recently witnessed discoveries of several oil reservoirs at depths exceeding 8000 m, which extend the exploration depth limit for crude oil and light oil resources. To clarify the role of overpressure during the critical stage of crude oil cracking (Easy Ro ≈ 1.0–2.0%), this study conducted low-temperature, long-duration, overpressure (150 MPa) gold tube pyrolysis experiments on marine crude oil from the Tarim Basin. Comprehensive analysis of the cracking products (C₁–C₃₀₊) revealed significant differences in the thermal stability and cracking behavior of hydrocarbon molecules with different chain lengths: long-chain hydrocarbons (C₁₂₊) were continuously consumed as the primary reactants, whereas short-chain hydrocarbons (C₆–C₁₂) initially formed as products and subsequently underwent secondary cracking as reactants. During this process, overpressure played a critical role in delaying the yield peak of light hydrocarbons and suppressing their secondary cracking. This mechanism resulted in a slower increase in gaseous hydrocarbon yield under overpressure conditions, and the carbon isotopic composition clearly recorded a shift in the cracking precursors from heavy to light hydrocarbons. Furthermore, fluorescence lifetime, as a sensitive spectroscopic indicator, exhibited delayed decay under overpressure, confirming the inhibition of aromatization and polymerization reactions by overpressure. By illuminating the sequential nature of hydrocarbon cracking and the moderating influence of overpressure at molecular and spectroscopic levels, this work offers crucial evidence for understanding multi-phase hydrocarbon coexistence and forecasting the preservation depth of discrete-phase crude oil in the Shuntuoguole area. Full article

The Shuntuoguole area has become an important oil and gas exploration replacement zone; however, the complexity of its ultra-deep oil and gas phase behavior poses a challenge to petroleum exploration and development. Previous research lacks quantitative modeling of the evolution of the oil and gas phase. In this paper, the phase characteristics, phase evolution processes, and main factors influencing phase differentiation in Ordovician reservoirs of three typical wells in the Shuntuoguole area were studied quantitatively by integrating PVT simulation and basin modeling. The results indicate that the difference in geothermal field between the Shunbei, Shuntuo, and Shunnan areas profoundly influences oil and gas phase differentiation. The Ordovician fluid in well SB5 has remained in the oil phase since the light oil accumulated during the Late Hercynian period. In well MS1, the Ordovician fluid briefly existed in a gas–liquid two-phase state after the light oil accumulated in the Late Caledonian period, then transformed into the liquid phase at 348 Ma and has maintained this state to the present. In the dry gas reservoir of well SN5, the fluid has remained in a single gas phase throughout all stages of reservoir temperature and pressure evolution after accumulation. Full article

The Ordovician No. 6 fault zone reservoir in the Shunbei Oilfield exhibits ultra-deep-burial, high-pressure, and high-temperature conditions. Its pronounced tectonic control and significant heterogeneity render traditional in situ stress prediction methods—based on linear elasticity and anisotropy assumptions—inadequate for accurately characterizing the evolution and uncertainty of carbonate reservoir stiffness. Therefore, quantitatively predicting the development patterns and distribution characteristics of the Shunbei No. 6 structural fault zone is crucial for the exploration and development of Ordovician carbonate reservoirs in the Shunbei region. This study integrates wave impedance inversion with high-confining-pressure PFC particle flow biaxial test results to establish a constitutive calibration system consistent with seismic and experimental data. It introduces a nonlinear weakening function incorporating higher-order derivative constraints to fuse structural fracture and effective stress weakening effects, enabling dynamic correction of elastic parameters. This approach establishes a novel in situ stress prediction model. Simulation results indicate a predicted range for maximum horizontal principal stress between 201 and 261 MPa, with minimum horizontal principal stress ranging from 124 to 173 MPa. Predicted stress values for three key wells exhibit measurement errors within 6.92% compared to actual logging data, displaying a zoned spatial distribution consistent with regional tectonic stress evolution patterns. Simultaneously, sensitivity analysis reveals that the Young’s modulus fitting accuracy improved from 0.89 to 0.95, with a 43% reduction in mean square error, with the proportion of outliers reduced to below 1%. This significantly enhances response continuity and numerical stability in high-gradient disturbance zones and stiffness drop regions. The new model explicitly incorporates the nonlinear coupling between fracture geometry and pore pressure disturbance into the parameter field, eliminating systematic bias along fracture zones. Higher-order derivative constraints suppress numerical oscillations in high-gradient areas, stabilizing variance and preventing anomaly propagation. Residual distributions exhibit enhanced symmetry and reduced spatial autocorrelation, effectively suppressing numerical oscillations and divergence in complex fracture zones while significantly improving stress prediction accuracy for the study area. Overall, this research provides novel methodologies for predicting in situ stresses in ultra-deep carbonate reservoirs, offering engineering guidance and parameterization references for scheme deployment in complex fractured karst systems. Full article

Analysis of pyrobitumen in reservoirs can yield key information about hydrocarbon evolution, which may provide vital insights for deep- to ultra-deep hydrocarbon exploration in high- to over-mature petroliferous deep basins. The Ediacaran Dengying Formation in the Penglai area of the Sichuan Basin contains large-scale gas reservoirs, where pyrobitumen is extensively present. To understand the hydrocarbon accumulation and alteration processes in these reservoirs, in this study, we systematically investigated the characteristics of the reservoir pyrobitumen using detailed petrographic analysis and laser Raman spectroscopy. The results indicated that four types of reservoir pyrobitumen are present: pyrobitumen with isotropic (type I), mosaic (type II), fibrous (type III), and honeycomb (type IV) textures. Pyrobitumen in the dolomite reservoirs of the Deng 2 and Deng 4 members of the Dengying Formation often co-occurs with hydrothermal minerals, including saddle dolomite, quartz, and fluorite. The equivalent vitrinite reflectance (Rmc Ro%) calculated indicated that the pyrobitumen is over-mature, with Rmc Ro% values ranging from 3.46% to 3.89%. In addition, significant differences were observed in the Raman parameters between the four types of pyrobitumen: type IV shows the greatest degree of structural ordering, while type II exhibits the highest level of disordering, with types I and III exhibiting intermediate structural ordering. Finally, the spatial distribution of the four types of pyrobitumen indicated that hydrothermal pulses driven by the Emeishan Large Igneous Province toward the end of the Permian Period may be primarily responsible for the extensive cracking of paleo-oil pools, causing the development of types II–IV pyrobitumen and gas generation. Full article

Deep and ultra-deep oil and gas reservoirs are characterized by extreme temperature and pressure conditions. During drilling, bottomhole temperatures often exceed the tolerance of downhole tools, leading to signal loss and damage to key components. Accurate prediction of the wellbore temperature field is therefore critical for ultra-deep drilling operations. Cementing quality significantly affects heat transfer between the wellbore and the formation, yet its influence is often neglected in existing prediction models. This study incorporates cementing quality into wellbore–formation heat transfer analysis, develops a method to calculate the effective thermal conductivity of cement, and establishes a transient heat transfer model based on energy conservation. The model is discretized and solved using the finite difference method. The effectiveness of the proposed model is validated against the Keller models, with a resulting relative error of 2.3%. Field data from three ultra-deep wells are used to evaluate the performance of the wellbore heat transfer model, incorporating cementing quality. The results indicate that the mean relative error of bottomhole temperature prediction is 0.77%, while that of outlet temperature prediction is 3.06%. This work provides an accurate method for predicting wellbore temperature profiles in ultra-deep wells and offers technical support for temperature-controlled drilling. Full article

Ultra-deep fractured tight sandstone reservoirs are key targets for natural gas development, where gas flow is controlled by pore structure, capillary forces, and water saturation. Using the ultra-deep tight sandstones from the Tarim Basin as study object, this paper investigates the gas flow behavior in matrix and fractured cores under high-temperature, high-pressure, and various water saturation conditions. The controlling factors of gas flow are investigated through scanning electron microscopy, casting thin-section, and high-pressure mercury intrusion measurements. The results show that increasing the water saturation can significantly reduce the permeability. The permeability of matrix and fractured cores decreases by 71.15% and 79.67%, respectively, when water saturation reaches 50%. The gas slippage is negligible, but the effect of gas threshold pressure is significant, which is primarily controlled by the pore structure and water saturation. The threshold pressure gradient of gas flow ranges from 0.0004 to 0.8762 MPa/cm, with the matrix cores exhibiting values approximately 13.21 times higher than the fractured cores. The water phase preferentially occupies the larger pores, forcing gas flow to rely on the finer pores. The pores with a maximum radius of 0.21 μm require 0.66 MPa of driving pressure for gas, whereas pores with a median radius of 0.033 μm require 4.18 MPa. The fracture networks can significantly reduce the lower limit for gas flow, serving as the key flow channels for the efficient development of ultra-deep tight sandstone gas. These findings not only reveal the gas flow mechanisms under water invasion but also provide theoretical and practical guidance for enhancing gas recovery from ultra-deep tight sandstone reservoirs. Full article

Judging from the current global exploration trend, ultra-deep layers have become the main battlefield for energy exploration. China has made great progress in the ultra-deep field in recent decades, with the Tarim Basin and Sichuan Basin as the focus of exploration. The Sichuan Basin is a large superimposed gas-bearing basin that has experienced multiple tectonic movements and has developed multiple sets of reservoir–caprock combinations vertically. Notably, the multi-stage platform margin belt-type reservoirs of the Sinian–Lower Paleozoic exhibit inherited and superimposed development. Source rocks from the Qiongzhusi, Doushantuo, and Maidiping formations are located in close proximity to reservoirs, creating a complex hydrocarbon supply system, resulting in vertical and lateral migration paths. The structural faults connect the source and reservoir, and the source–reservoir–caprock combination is complete, with huge exploration potential. At the same time, the ultra-deep carbonate rock structure in the basin is weakly deformed, the ancient closures are well preserved, and the ancient oil reservoirs are cracked into gas reservoirs in situ, with little loss, which is conducive to the large-scale accumulation of natural gas. Since the Nvji well produced 18,500 cubic meters of gas per day in 1979, the study of ultra-deep layers in the Sichuan Basin has begun. Subsequently, further achievements have been made in the Guanji, Jiulongshan, Longgang, Shuangyushi, Wutan and Penglai gas fields. Since 2000, two trillion cubic meters of exploration areas have been discovered, with huge exploration potential, which is an important area for increasing production by trillion cubic meters in the future. Faced with the ultra-deep high-temperature and high-pressure geological environment and the complex geological conditions formed by multi-stage superimposed tectonic movements, how do we understand the special geological environment of ultra-deep layers? What geological processes have the generation, migration and enrichment of ultra-deep hydrocarbons experienced? What are the laws of distribution of ultra-deep oil and gas reservoirs? Based on the major achievements and important discoveries made in ultra-deep oil and gas exploration in recent years, this paper discusses the formation and enrichment status of ultra-deep oil and gas reservoirs in the Sichuan Basin from the perspective of basin structure, source rocks, reservoirs, caprocks, closures and preservation conditions, and provides support for the optimization of favorable exploration areas in the future. Full article

Hydrocarbon exploration and extraction increasingly rely on drilling fluids that guarantee operating safety and efficiency, particularly in ultra-deep, high-temperature, and unconventional reservoirs. Traditional drilling fluids, especially for water-based muds (WBMs), have several problems, including excessive fluid loss, severe swelling in shale and instability in high-pressure/high-temperature (HPHT) conditions. Polymer nanocomposites (PNCs) are new types of drilling fluid additives that combine the vast surface area and reactivity of nanoparticles (NPs) with the structural flexibility and stability of polymers. This combination enhances rheology, reduces filtrate loss, and, most importantly, creates hydrophobic and pore-blocking barriers that prevent shale from swelling. This review highlights important improvements in drilling fluids with PNCs regarding exceptional rheological properties, low fluid loss, and improved suppression of the shale swelling. The particular focus was placed on the specific mechanisms and role that PNCs play in enhancing shale stability, as well as their responsibilities in improving rheology, heat resistance, and salt tolerance. Current advancements, persistent hurdles, and prospective prospects are rigorously evaluated to emphasize the scientific and industrial trajectories for the development of next-generation, high-performance drilling fluids. Moreover, the current challenges and future opportunities of PNCs in drilling fluids are discussed to motivate future contributions and explore new possibilities. Full article

Understanding gas–water two-phase flow mechanisms in deep tight gas reservoirs is critical for improving production performance and mitigating water invasion. However, the effects of pore-throat-fracture multiscale structures on gas–water flow remain inadequately understood, particularly under high-temperature and high-pressure conditions (HT/HP). In this study, we developed visualizable multiscale throat-pore and throat-pore-fracture physical nanofluidic chip models (feature sizes 500 nm–100 μm) parameterized with Keshen block geological data in the Tarim Basin. We then established an HT/HP nanofluidic platform (rated to 240 °C, 120 MPa; operated at 100 °C, 100 MPa) and, using optical microscopy, directly visualized spontaneous water imbibition and gas–water displacement in the throat-pore and throat-pore-fracture nanofluidic chips and quantified fluid saturation, front velocity, and threshold pressure gradients. The results revealed that the spontaneous imbibition process follows a three-stage evolution controlled by capillarity, gas compression, and pore-scale heterogeneity. Nanoscale throats and microscale pores exhibit good connectivity, facilitating rapid imbibition without significant scale-induced resistance. In contrast, 100 μm fractures create preferential flow paths, leading to enhanced micro-scale water locking and faster gas–water equilibrium. The matrix gas displacement threshold gradient remains below 0.3 MPa/cm, with the cross-scale Jamin effect—rather than capillarity—dominating displacement resistance. At higher pressure gradients (~1 MPa/cm), water is efficiently expelled to low saturations via nanoscale throat networks. This work provides an experimental platform for visualizing gas–water flow in multiscale porous media under ultra-high temperature and pressure conditions and offers mechanistic insights to guide gas injection strategies and water management in deep tight gas reservoirs. Full article

The SHB fault-controlled condensate gas reservoir is the largest ultra-deep carbonate gas reservoir in China, and the accuracy of dynamic reserve calculation is an important basis for developing the development plan. The fault-controlled condensate gas reservoir has some problems, such as “ultra-deep, ultra-high temperature, supercritical”, strong heterogeneity of reservoir space, and difficulty in obtaining real underground reservoir parameters, which seriously affect the results of dynamic reserve evaluation. Combining the quasi-steady flow equation and the flow resistance of a gas well, a new flow material balance method based on the original apparent formation pressure and daily production data is proposed to effectively calculate the dynamic reserves of a gas reservoir. By comparing the calculation results of various dynamic reserves calculation methods for the SHB condensate gas reservoir, it is proven that this method can effectively calculate the dynamic reserves of gas wells and has important guiding significance for the calculation of dynamic reserves of fault control body condensate gas reservoirs. Full article

This study investigates gas injection gravity miscible flooding to enhance oil recovery in fractured-vuggy volatile oil reservoirs of the Fuman area, Tarim Basin. The Fuman 210 reservoir, containing light oil with high maturity, large column heights, and strong fracture control, provides favorable conditions for gravity-driven flooding. Laboratory tests show that natural gas and CO₂ achieve miscibility, while N₂ reaches near-miscibility. Mixed gas injection, especially at a natural gas to nitrogen ratio of 1:4, effectively lowers minimum miscibility pressure and enhances displacement efficiency. Full-diameter core experiments confirm that miscibility improves oil washing and expands the sweep volume. Based on these results, a stepped three-dimensional well network was designed, integrating shallow injection with deep production. Optimal parameters were determined: injection rates of 50,000–100,000 m³/day per well and stage-specific injection–production ratios (1.2–1.5 early, 1.0–1.2 middle, 0.8–1.0 late). Field pilots validated the method, maintaining stable production for seven years and achieving a recovery factor of 30.03%. By contrast, conventional development relies on depletion and limited water flooding, and dry gas injection yields only 12.6%. Thus, the proposed approach improves recovery by 17.4 percentage points. The novelty of this work lies in establishing the feasibility of mixed nitrogen–natural gas miscible flooding for ultra-deep fault-controlled carbonate reservoirs and introducing an innovative stepped well network model. These findings provide new technical guidance for large-scale application in similar reservoirs. Full article

Ultra-deep tight sandstone gas reservoirs are key targets for natural gas exploration, yet their pore structures under high temperature, pressure, and stress greatly affect gas occurrence and flow. This study investigates representative reservoirs in the Kelasu structural belt, Tarim Basin. Porosity–permeability were measured under in situ conditions, and multi-scale pore structures were analyzed using thin sections, a SEM, mercury intrusion, and nitrogen adsorption. The results show that (1) the median permeability of cores at an ambient temperature and a confining stress of 3 MPa is 13.33–29.63 times that under the in situ temperature and pressure conditions. When the core permeability is lower than 0.1 mD, the stress sensitivity effect is significantly enhanced; (2) nanopores and micron-fractures are well developed yet exhibit poor connectivity. The majority of a core’s porosity is derived from the intergranular pores in clay minerals; (3) the volume of nano-sized pores within the 100 nm diameter range is mainly composed of mesopores, with an average proportion of 73.37%, while the average proportions of macropores and micropores are 22.29% and 4.34%, respectively; (4) full-scale pore sizes show bimodal peaks at 100–1000 nm and >100 μm, which are poorly connected; (5) the pore structure exhibits distinct fractal characteristics. The fractal dimension D_f1 (2.65 on average) corresponds to the larger pore diameters of the primary intergranular pores, residual intergranular pores, and intragranular dissolution pores. The fractal dimension D_f2 (2.10 on average) corresponds to the grain margin fractures, micron-fractures and partial throats. The pore types corresponding to the fractal dimensions D_f3 (2.36 on average) and D_f4 (2.58 on average) are mainly intercrystalline pores of clay minerals and a small number of intraparticle dissolution pores. These findings clarify the pore structure of ultra-deep tight sandstones and provide insights into their gas occurrence and flow mechanisms. Full article

Fractured tight sandstone reservoirs pose challenges for gas development due to low matrix porosity and permeability, complex pore structures, and pervasive fractures. This study focuses on the Bashijiqike Formation in the Keshen Gas Field, Kuqa Depression, aiming to clarify the geological controls on reservoir quality. Lithofacies, diagenetic facies, and fracture facies were systematically classified by core analyses, thin sections, scanning electron microscopy (SEM), cathodoluminescence (CL), X-ray diffraction (XRD), grain size analyses, mercury intrusion capillary pressure (MICP), well logs and resistivity imaging logging (FMI). Their impacts on porosity, permeability and gas productivity were quantitatively assessed. A ternary reservoir quality assessment model was established by coupling these three factors. Results show that five lithofacies, four diagenetic facies, and four fracture facies jointly control reservoir performance. The high-energy gravelly sandstone facies exhibit an average porosity of 6.0% and average permeability of 0.066 mD, while the fine-grained sandstone shows poor properties due to compaction and clay content. Unstable component dissolution facies enhance secondary porosity to 6.0% and permeability to 0.093 mD. Reticulate and conjugate fracture patterns correspond to gas production rates two to five times higher than those with single fractures. These findings support targeted reservoir classification and improved development strategies for ultra-deep tight gas reservoirs. Full article