Search Results (62)

The description and assessment of braided river architecture are usually limited by the paucity of real geological datasets from field observations; due to the complexity and diversity of rivers, traditional evaluation models are difficult to apply to braided river systems in different climatic and tectonic settings. This study aims to establish an architectural model suitable for the study area setting by introducing a hierarchical analysis approach through well-exposed three-dimensional outcrops along the Second Songhua River. A micro–macro four-level hierarchical framework is adopted to obtain a detailed anatomy of sedimentary outcrops: lithofacies, elements, element associations, and archetypes. Fourteen lithofacies are identified: three conglomerates, seven sandstones, and four mudstones. Five elements provide the basic components of the river system framework: fluvial channel, laterally accreting bar, downstream accreting bar, abandoned channel, and floodplain. Four combinations of adjacent elements are determined: fluvial channel and downstream accreting bar, fluvial channel and laterally accreting bar, erosionally based fluvial channel and laterally accreting bar, and abandoned channel and floodplain. Considering the sedimentary evolution process, the braided river prototype, which is an element-based channel filling unit, is established by documenting three contact combinations between different elements and six types of fine-grained deposits’ preservation positions in the elements. Empirical relationships are developed among the bankfull channel depth, mean bankfull channel depth, and bankfull channel width. For the braided river systems, the establishment of the model promotes understanding of the architecture and evolution, and the application of the hierarchical analysis approach provides a basis for outcrop, underground reservoir, and tank experiments. Full article

Formation Microresistivity Scanner Imaging (FMI) plays a crucial role in identifying lithology, sedimentary structures, fractures, and reservoir evaluation. However, during the lithology identification process of FMI images relying on transfer learning networks, the limited dataset size of existing models and their relatively primitive architecture substantially compromise the accuracy of well-log interpretation results and practical production efficiency. This study employs the VGG-19 transfer learning model as its core framework to conduct preprocessing, feature extraction, and analysis of FMI well-log images from glutenite formations in an oilfield in Xinjiang, with the objective of achieving rapid and accurate intelligent identification and classification of formation lithology. Simultaneously, this paper emphasizes a systematic comparative analysis of the recognition performance between the VGG-19 model and existing models, such as GoogLeNet and Xception, to screen for the model exhibiting the strongest region-specific applicability. The study finds that lithology can be classified into five types based on physical structures and diagnostic criteria: gray glutenite, brown glutenite, fine sandstone, conglomerate, and mudstone. The research results demonstrate the VGG-19 model exhibits superior accuracy in identifying FMI images compared to the other two models; the VGG-19 model achieves a training accuracy of 99.64%, a loss value of 0.034, and a validation accuracy of 95.6%; the GoogLeNet model achieves a training accuracy of 96.1%, a loss value of 0.05615, and a validation accuracy of 90.38%; and the Xception model achieves a training accuracy of 91.3%, a loss value of 0.0713, and a validation accuracy of 87.15%. These findings are anticipated to provide a significant reference for the in-depth application of VGG-19 transfer learning in FMI well-log interpretation. Full article

Ultra-deep tight sandy conglomerate reservoirs in the Junggar Basin are characterized by vertically alternating lithologies that include mudstone, sandy conglomerate, and sandstone. High in situ stresses and formation temperatures contribute to a brittle–ductile transition process in the reservoir rocks. However, the brittle behavior and ductile hydraulic fracture propagation mechanisms under in situ conditions remain inadequately understood. In this study, ultra-deep core samples were subjected to triaxial compression tests under varying confining pressures and temperatures to simulate different burial depths and evaluate their brittleness. A three-dimensional hydraulic fracture propagation model was developed in ABAQUS 2023 finite element software, incorporating a cohesive zone ductile constitutive model. Numerical simulations were conducted, considering interlayer horizontal stress differences, injection rate, and fracturing fluid viscosity, to systematically analyze the influence of geological and engineering factors on ductile fracture propagation. A fracture length–height competition diagram was constructed to illustrate the propagation mechanisms. The results reveal that high temperatures significantly accelerate the brittle–ductile transition, which occurs at confining pressures between 55 and 65 MPa. Following this transition, failure modes shift from single-shear failure to a multi-localized fracture with bulging deformation. Interlayer horizontal stress differences were found to strongly influence fracture penetration, with larger stress differences hindering vertical growth. Increasing injection rates promoted the uniform distribution of lateral fractures and fracture tip development, while medium- to high-viscosity fracturing fluids enhanced fracture width and vertical stimulation uniformity. These findings provide important insights for optimizing fracturing strategies and expanding the effective stimulation volume in the ultra-deep tight sandy conglomerate reservoirs of the Junggar Basin. Full article

Accurate understanding of natural fractures, faults, in situ stress, and mechanical properties of reservoir rocks is a prerequisite for evaluating well interference. During hydraulic fracturing, hydraulic fractures may connect with natural fractures or fault zones, leading to communication with adjacent wells and resulting in cross-well interference. Additionally, horizontal well spacing is a critical factor influencing the occurrence and severity of interference. The Mahu tight oil reservoir experiences severe fracturing interference issues, presenting multiple challenges. This study employs numerical simulation methods to quantitatively assess the influence of geological and engineering factors, including reservoir depletion volume, well spacing, natural fractures, and fracturing operation parameters on fracturing interference intensity. By integrating geological data, engineering parameters, and production data with microseismic monitoring and pressure information, this research aims to clarify key influencing factors and elucidate the fundamental mechanisms governing fracturing-driven interference occurrences. Through production performance analysis and microseismic monitoring, it has been established that well spacing, fracturing intensity, and natural fracture networks are the primary factors affecting interference in hydraulically fractured horizontal wells. Full article

The Carboniferous reservoirs in the northwestern margin of the Junggar Basin exhibit complex lithological assemblages, primarily composed of siltstone, sandy conglomerate, tuff, and igneous rocks. These reservoirs are rich in oil and gas resources but have entered the middle to late stages of development. The reservoir spaces in the Carboniferous system are mainly composed of pores and fractures, resulting in a complex storage system. To provide effective strategies for stabilizing and enhancing production during the middle to late development stages, it is essential to establish a dual-porosity and dual-permeability model based on a clear understanding of lithological distribution patterns. This will facilitate the identification of favorable zones and the proposal of effective development strategies through numerical simulation. The present study systematically identified the lithology of the study area through microscopic lithological identification combined with logging data, conducted reservoir matrix property research under facies constraints, and established a three-dimensional geological model of lithology and physical properties. To more reasonably study the reservoir development process and establish an optimal development plan, a machine learning model for fracture density was trained using imaging logging interpretation results and conventional logging curve data. The model was then utilized to calculate single-well fracture density. Finally, a fracture model of the study area was established based on the collaborative constraints of fracture density and three-dimensional seismic attributes. Using the results of the established dual-porosity and dual-permeability model and production data, reservoir production evaluation and residual oil distribution research were conducted. The results indicate that the southwestern part of the study area features thick sandy conglomerate reservoirs with good physical properties, continuous lateral distribution, and high residual oil content, making it a dominant area favorable for horizontal well development and production. Additionally, reservoir numerical simulation was employed to study enhanced production development strategies. It is recommended to adopt gas–water alternating injection to improve production, with the optimal gas–water injection ratio of 4:1 yielding the maximum reservoir recovery factor. This study provides theoretical and technical support for the development of complex lithologic buried-hill reservoirs in the Carboniferous system of the western margin of the Junggar Basin. Full article

Lithological mapping using satellite images, particularly hyperspectral data, helps in effectively defining the best initial targets for regional exploration. In this study, ZY1-02D hyperspectral image (HSI) data with moderate spectral and very high spatial resolution were employed for lithological mapping using spectral indices along with support vector machine (SVM) machine learning and spatial–spectral transformer (SSTF) deep learning methods in the Kohat–Pothohar Plateau at the eastern edge of the Main Boundary Thrust (MBT) in Pakistan. The research was accomplished using spectral profiles of minerals accompanied by false color composite (FCC), principal component analysis (PCA), SVM, and SSTF methods for classifying the main lithological units. The lithological discrimination map derived from the ZY1-02D data matched well with the known deposits and field inspections. The principal component analysis (PCA) obtained the highest eigenvalues and provided a significant discrimination of lithologies, particularly with hyperspectral data. The results revealed lithological units, three of which contained limestone and gypsum, while other lithological units were defined as sandstone, clay, and conglomerates. Field investigation and laboratory sample analysis through X-ray diffraction (XRD), photomicrographs, and spectral analysis confirmed the occurrence of limestone, gypsum, and sandstone, which are useful in identifying lithological units in the study area. This study will assist in more accurate geological discrimination and play a vital role in identifying oil and gas reservoirs, coal, gypsum, uranium, salt, and limestone deposits. Furthermore, the results of the SVM and SSTF techniques were quantitatively compared with the geological boundaries mapped in the field, showing an accuracy of nearly 89.7% and 92.1%, respectively. Overall, the methodology adopted showed great performance and strong potential for mapping alteration areas and lithological discriminations applied on the ZY1-02D hyperspectral data. Full article

Unconformity stratigraphic traps are widely developed in the Mahu Sag, on the northwestern margin of the Junggar Basin. It is of great significance for subsequent oil and gas exploration to explore the role of conglomerate accumulation mode and unconformity inner structure in the formation of oil and gas reservoirs. Therefore, this study uses oil and gas geophysical technology combined with geological theory to identify the P/T unconformity structure in the study area, determine the development characteristics and accumulation control of the unconformity structure, and explore the accumulation mode of stratigraphic oil and gas reservoirs. The results show the following: (1) Based on the different logging response characteristics of the upper, middle, and lower layers of the unconformity structure, five types of unconformity structure are divided according to different lithologic combinations. (2) Through experimental and numerical simulation analysis, it was verified that fracture pressure and thickness are important indicators for evaluating the sealing property of unconformity structure. P/T unconformity structure provides good floor conditions for the Baikouquan Formation reservoir, further confirming its key role in the process of oil and gas accumulation and storage. (3) Based on the analysis of actual cases, the accumulation model of stratigraphic oil and gas reservoirs under the control of unconformity structure is summarized as cross-layer accumulation above the source, fault communication source reservoir, unconformity lateral transmission and distribution, and mudstone lateral docking. The research results provide technical support and important reference values for the exploration and development of unconformity-related oil and gas reservoirs in the Junggar Basin. Full article

Recent breakthrough exploration wells in the Huagang Formation in the Y-area of the central anticlinal zone of the Xihu Sag have confirmed the significant exploration potential of structure–lithology complex hydrocarbon reservoirs. However, limited understanding of the provenance system, sedimentary facies, and microfacies has hindered further progress in complex hydrocarbon exploration. Analysis of high-precision stratigraphic sequences and seismic facies data, mudstone core color, grain-size probability cumulative curves, core facies, well logging facies, lithic type, the heavy-mineral ZTR index, and conglomerate combinations in drilling sands reveals characteristics of the source sink system and provenance direction. The Huagang Formation in the Y-area represents an overall continental fluvial delta sedimentary system that evolved from a braided river delta front deposit into a meandering river channel large-scale river deposit. The results indicate that the primary provenance of the Huagang Formation in the Y-area of the Xihu Sag is the long-axis provenance of the Hupi Reef bulge in the northeast, with supplementary input from the short-axis provenance of the western reef bulge. Geochemical analysis of wells F1, F3, and G in the study area suggests that the prevailing sedimentary environment during the period under investigation was characterized by anoxic conditions in nearshore shallow waters. This confirms previous research indicating strong tectonic reversal in the northeast and a small thickness of the central sand body unrelated to the flank slope provenance system. The aforementioned findings deviate from conventional understanding and will serve as a valuable point of reference for future breakthroughs in exploration. Full article

The coiled tubing (CT) fracturing technology offers advantages such as pressurized dragging operation and maintaining a large borehole diameter after fracturing. However, during fracturing in the conglomerate and volcanic rock reservoirs of the Junggar Basin, CT stuck during retrieval occurs frequently. In this study, a model simulating the variation in the in situ stress field during CT hydraulic fracturing is established based on elastic mechanics and the displacement discontinuity method (DDM). Based on the geological characteristics of conglomerate and volcanic rock reservoirs in the Junggar Basin, and considering engineering parameters such as fracture length and fracture count in CT hydraulic fracturing, this study investigates the variation in the in situ stress during CT hydraulic fracturing and explores the stuck mechanism of CT. An index for fracturing completion is constructed to evaluate the stuck of CT during the fracturing process. With the goal of full stimulation of the horizontal section, a quantitative optimization design is conducted for the fracturing stage spacing and number of stages under different geological conditions, resulting in corresponding charts. The results indicate that the stuck mechanism during CT fracturing is caused by the continuous accumulation of stress induced by hydraulic fractures, leading to stress inversion. The fracturing completion increases with the stage spacing and the original horizontal stress difference. The length of the fractured section first increases and then decreases with the increase in stage spacing, while it increases with the original horizontal stress difference. The research findings can be applied to the optimization design of stage spacing and number of stages for CT hydraulic fracturing in conglomerate and volcanic rock reservoirs of the Junggar Basin, effectively preventing and controlling stuck coiled tubing in CT fracturing. Full article

To achieve the efficient utilization of low-permeability tight sand and gravel reservoirs with strong heterogeneity in the Mahu oil area of Xinjiang, CO₂ injection is used to improve oil recovery. The sweep pattern of the injected gas is closely related to the development of reservoir pores and throats. Firstly, a three-dimensional model of the average pore-throat radius was established based on complete two-dimensional nuclear magnetic resonance scanning data of the target layer’s full-diameter core in the Wuerhe Formation. Subsequently, an online NMR injection CO₂ continuous oil displacement experiment was conducted using tight conglomerate rock cores to clarify the rules of CO₂ oil displacement in each pore-throat interval. Finally, the three-dimensional pore-throat model was combined with microscopic utilization patterns to quantitatively characterize the reservoir utilization rate of the CO₂ displacement oil and guide on-site dynamic analysis. The research results indicate that the reservoir space of the Wuerhe Formation is mainly composed of residual intergranular pores, accounting for 40.9% of the pores, followed by intragranular dissolution pores and shrinkage pores. The proportion of pore-throat coordination numbers less than 1 is relatively high, reaching 86.3%. The average pore-throat radius calculation model, established using online NMR data from the continuous coring of full-diameter cores, elucidates the characteristics of the average pore-throat radius in the Wuerhe Formation reservoir. Based on gas displacement experiments that explored the pore-throat behavior at the microscale, the calibrated CO₂ injection oil recovery rate was determined to be 43.9%, and the proportion of reserves utilized within the main range during CO₂ displacement amounted to 60.77%. The injection pressure is negatively correlated with the maximum pore-throat radius of the gas injection well group, and negatively correlated with the proportion of the 0.9~2 μm distribution of large pore throats in each gas injection well group. Full article

Deep well injection and storage is an emerging technology for realizing the low-cost treatment of extremely large quantities of three types of waste in coal mines in China, while simultaneously supporting coordinated development that considers its impact on the ecological environment. There has been significant progress in research on the geological storage of carbon dioxide in China. However, the geological storage of fluids such as mine water and high-salinity water needs to be studied further. Based on a comprehensive analysis of the lithology, mineral composition, physical and mechanical characteristics, and spatial structure of the Liujiagou and Shiqianfeng formations in a mining area in the Ordos Basin, we determined the geological storage space for fluids, predicted the storage potential, and evaluated the feasibility of deep geological storage of high-salinity water in coal mines. In the study area, the Liujiagou Formation is dominated by fine sandstone and siltstone, while the Shiqianfeng Formation is dominated by medium sandstone and conglomerate. The main storage space comprises micro-cracks, as well as intergranular, dissolution, and intergranular pores. Among these, the intergranular pores are the most conducive to reservoir development. The burial depth intervals of 1820–1835 m, 1905–1920 m, and 2082–2098 m are favorable for storage and are characterized by high porosities, permeabilities, and storage capacities. The effective storage capacity within a 100 m radius of the storage well was estimated to be 33.15 × 10⁴ m³. The effective storage capacity in the favorable area is 27.69 × 10⁴ m³, accounting for 83.50% of the total storage capacity. The Liujiagou and Shiqianfeng formations thus can serve as favorable reservoirs for deep well injection and storage of high-salinity water in the Ordos Basin. This research provides new ideas for the treatment of high-salinity water in coal mines in the Ordos Basin and technical support for deep well injection and the storage of high-salinity water. Full article

Unconformities are of significant interest to petroleum geologists because of their crucial roles in influencing reservoir quality and controlling oil and gas migration. This study investigates the impact of unconformities on a reservoir within a prolific oil–gas-bearing zone between the Middle Permian and Lower Triassic strata in the northwestern Junggar Basin, utilizing thin sections, well logging data, seismic profiles, and geochemical analyses. The results reveal a well-developed three-layer unconformity structure characterized by a thick weathered clay layer, which acts as an effective caprock for hydrocarbons. The diagenetic evolution of the Lower Wuerhe Formation in the northwestern Junggar Basin consists of an initial stage of compaction followed by a subsequent stage of dissolution and cementation. Four key factors, including low argillaceous content in sandstone and conglomerate, diagenetic compaction, zeolite dissolution and cementation, and clay mineral infill, have played a crucial role in influencing the reservoir characteristics of the Lower Wuerhe Formation. In addition, the development of unconformities promotes atmospheric freshwater leaching, which enhances the dissolution of the underlying reservoir while developing an extensive network of strike-slip faults that improve connectivity within hydrocarbon reservoirs. This process facilitates both vertical and lateral migration of hydrocarbons along hard rock layers, which allows the unconformity to breach into the overlying conglomerate reservoirs. The results of this study suggest that the reservoir in proximity to the unconformity surface often exhibits high porosity and rich hydrocarbon content, offering valuable insights for future oil and gas exploration and development. Full article

Reservoir heterogeneity significantly affects reservoir flooding efficiency and the formation and distribution of residual oil. As an effective method for enhancing recovery, polymer–surfactant (SP) flooding has a complex mechanism of action in inhomogeneous reservoirs. In this study, the effect of reservoir heterogeneity on the SP drive was investigated by designing core parallel flooding experiments combined with NMR and CT scanning techniques, taking conglomerate reservoirs in a Xinjiang oilfield as the research object. The experimental results show that inter-layer heterogeneity significantly affects water flooding efficiency and SP driving in low-permeability cores—the larger the permeability difference is, the more obvious the effect is—while it has almost no effect on high-permeability cores. The limited recovery enhancement in low-permeability cores is mainly due to the small percentage of contributing pores. When the permeability difference undergoes an extreme increase, the polymer molecular weight is biased towards higher values; when the polymer molecular weight is fixed, the recovery enhancement of low-permeability cores may be comparable to that of high-permeability cores when the permeability difference is extremely small. However, the recovery enhancement of the former is smaller than that of the latter when the permeability difference is extremely large. Due to intra-layer heterogeneity, there is a serious fingering phenomenon in the flooding stage, while in the SP flooding stage, recovery enhancement is most significant in the 5–20 μm pore range. This study provides an important geological basis for the rational development of a chemical flooding programme. Full article

Addressing the issue of poor water injection development effectiveness caused by strong water sensitivity damage in the conglomerate reservoirs of the Xinjiang Oilfield, this paper carries out experimental research on CO₂ displacement and CO₂ huff-n-puff to improve oil recovery in reservoirs under the conditions of reservoirs (86 °C, 44 MPa) by using a high-temperature and high-pressure large physical modeling repulsion device based on the artificial large-scale physical modeling of conglomerate oil reservoirs in the Xinjiang oilfield. The results showed that at any displacement rate, CO₂ displacement exhibits the trend where oil production initially increases and then decreases. The higher the gas injection rate, the higher the initial oil well production, and the shorter the time it takes for CO₂ to break through to the bottom of the well. After a breakthrough, production declines more rapidly. The oil recovery rate varies with different gas injection rates, initially increasing and then decreasing as the injection rate changes. The highest oil recovery rate was observed at an injection rate of 1.5 mL/min (equivalent to 38 t/d in the field). The efficiency of CO₂ displacement with multiple injection-production cycles is low; on the same scale of gas injection, single-cycle injection and production were more effective than multiple-cycle injection and production. CO₂ huff-n-puff can improve oil recovery, with a higher CO₂ injection pressure and a longer shut-in time leading to greater oil recovery. As the shut-in time increases, the efficiency of CO₂ oil exchange also improves. The strong supply capacity of the large physical model results in a tendency for the oil production curves of multiple huff-n-puff cycles to converge. Full article

Tight sandstone gas has become an important field of natural gas development in China. The tight sandstone gas resources of Yan’an gas field in Ordos Basin have made great progress. However, due to the complex gas–water relationship, its exploration and development have been seriously restricted. The occurrence state of water molecules in tight reservoirs, the dynamic change characteristics of gas–water two-phase seepage and its main controlling factors are still unclear. In this paper, the water-occurrence state, gas–water two-phase fluid distribution and dynamic change characteristics of different types of tight reservoir rock samples in Yan’an gas field were studied by means of water vapor isothermal adsorption experiment and nuclear magnetic resonance methane flooding experiment, and the main controlling factors were discussed. The results show that water molecules in different types of tight reservoirs mainly occur in clay minerals and their main participation is in the formation of fractured and parallel plate pores. The adsorption characteristics of water molecules conform to the Dent model; that is, the adsorption is divided into single-layer adsorption, multi-layer adsorption and capillary condensation. In mudstone, limestone and fine sandstone, water mainly occurs in small-sized pores with a diameter of 0.001 μm–0.1 μm. The dynamic change characteristics of gas and water are not obvious and no longer change under 7 MPa displacement pressure, and the gas saturation is low. The gas–water dynamic change characteristics of conglomerate and medium-coarse sandstone are obvious and no longer change under 9 MPa displacement pressure. The gas saturation is high, and the water molecules mainly exist in large-sized pores with a diameter of 0.1 μm–10 μm. The development of organic matter in tight reservoir mudstone is not conducive to the occurrence of water molecules. Clay minerals are the main reason for the high water saturation of different types of tight reservoir rocks. Tight rock reservoirs with large pore size and low clay mineral content are more conducive to natural gas migration and occurrence, which is conducive to tight sandstone gas accumulation. Full article