Search Results (14)

The tight conglomerate oil reservoir in Xinjiang’s Mahu area is situated on the northwestern margin of the Junggar Basin. The reservoir comprises five stacked fan bodies, with the Triassic Baikouquan Formation serving as the primary pay zone. To delineate the study scope and conduct a field validation, the Ma-X well block was selected for investigation. Through triaxial compression tests and large-scale true triaxial hydraulic fracturing simulations, we analyzed the failure mechanisms of tight conglomerates and identified key factors governing hydraulic fracture propagation. The experimental results reveal several important points. (1) Gravel characteristics control failure modes: Larger gravel size and higher content increase inter-gravel stress concentration, promoting gravel crushing under confining pressure. At low-to-medium confining pressures, shear failure primarily occurs within the matrix, forming bypassing fractures around gravel particles. (2) Horizontal stress differential dominates fracture geometry: Fractures preferentially propagate as transverse fractures perpendicular to the wellbore, with stress anisotropy being the primary control factor. (3) Injection rate dictates fracture complexity: Weakly cemented interfaces in conglomerates lead to distinct fracture morphologies—low rates favor interface activation, while high rates enhance penetration through gravels. (4) Stimulation strategy impacts SRV: Multi-cluster perforations show limited effectiveness in enhancing fracture network complexity. In contrast, variable-rate fracturing significantly increases stimulated reservoir volume (SRV) compared to constant-rate methods, as evidenced by microseismic data demonstrating improved interface connectivity and broader fracture coverage. 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

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

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

Pore structure and flow characteristics are key factors affecting oil recovery rates in heterogeneous tight conglomerate reservoirs. Using micron computed tomography (CT) and modular automated processing system (MAPS) techniques, the pore structure of downhole core samples taken from Mahu’s tight conglomerate reservoirs was analyzed in detail, and a two-scale digital core pore network model with both a wide field of view and high resolution was constructed based on these pore structure data; the digital pore model was corrected according to the mercury intrusion pore size distribution date. Finally, we simulated flow characteristics within the digital model and compared the calculated permeability with the indoor permeability test date to verify the dependability of the pore network. The results indicated that the pore–throat of the conglomerate reservoir in Mahu was widely distributed and exhibited significant bimodal characteristics, with main throat channels ranging from 0.5 to 4 μm. The pore structure showed pronounced microscopic heterogeneity and intricate modalities, mainly consisting of dissolved pores, intergranular pores, and microfractures. These pores were primarily strip-like, isolated, and played a more crucial role in enhancing pore connectivity rather than contributing to the overall porosity. The matrix pores depicted by the MAPS were relatively smaller in size and more abundant in number, with no individual pore type forming a functional seepage channel. The permeability parameters obtained from the two-scale coarse-fine coupled pore network aligned with the laboratory experimental results, displaying an average coordination number of two. Flow simulation results indicated that the core’s microscopic pore structure affected the shape of the displacement leading edge, resulting in a tongue-in phenomenon during oil–water flow. The dominant flow channel was mainly dominated by water, while tongue-in and by-pass flow were the primary microscopic seepage mechanisms hindering oil recovery. These findings lay a foundation for characterizing and analyzing pore structure as well as investigating flow mechanisms in conglomerate reservoirs. Full article

Tight-sandstone oil and gas resources are the key areas of unconventional oil and gas resources exploration and development. Because tight-sandstone reservoirs usually have the characteristics of a low porosity and ultralow permeability, large-scale hydraulic fracturing is often required to form artificial fractures with a high conductivity to achieve efficient development. The brittleness of rock is the key mechanical factor for whether fracturing can form a complex fracture network. Previous scholars have carried out a lot of research on the brittleness characteristics of conglomerate and shale reservoirs, but there are few studies on the brittleness characteristics of sandstone with different types and different coring angles in tight-sandstone reservoirs and the fracture propagation law of sandstone with different brittleness characteristics. Based on this, this paper carried out a systematic triaxial compression and hydraulic fracturing experiment on the tight sandstone of Shan 1 and He 8 in the Longdong area of the Changqing oilfield. Combined with CT scanning cracks, the brittleness characteristics and fracturing crack propagation law of different types and different coring angles of sandstone under formation-confining pressure were clarified. The results show that there are great differences between different types of sandstone in the yield stage and the failure stage. The sandstone with a quartz content of 100% has the highest peak strength and a strong brittleness. Sandstones with a high content of natural fractures and dolomite have a lower peak strength and a weaker brittleness. There are also differences in the peak strength and fracture morphology of sandstone with different coring angles due to geological heterogeneity. The sandstone with a comprehensive brittleness index of 70.30 produces a more complex fracture network during triaxial compression and hydraulic fracturing than the sandstone with a comprehensive brittleness index of 14.15. The research results have important guiding significance for on-site fracturing construction of tight-sandstone reservoirs. Full article

In order to improve the recovery efficiency of the Jimusaer tight reservoir in Xinjiang, the nanometer oil displacement agent system suitable for the Jimusaer reservoir was used. In view of the low permeability, high formation temperature, and high salinity characteristics of the prepared water in the Jimusaer tight conglomerate reservoir in Xinjiang, the performance of the nanometer oil displacement agent affecting oil recovery was studied; the study considered interfacial tension, temperature resistance, wetting performance, static oil washing efficiency, and long-term stability. Nanometer oil displacement agent No. 4 had the lowest interfacial tension and could reach the order of 10⁻¹ mN∙m⁻¹; it had excellent temperature resistance and the best static oil washing efficiency and stability. Nano-oil displacement agent No. 2 had the best emulsification performance and wettability and also had good stability. By studying the performance and final oil displacement effect of the nano-oil displacement agent, it was found that the key factor affecting the oil displacement effect of this reservoir was the interfacial activity of the nano-oil displacement agent. When the interfacial tension was lower, it produced strong dialysis for oil displacement. The emulsification effect has a negative effect on low-permeability reservoirs, mainly because the fluid produces strong emulsification in low-permeability reservoirs; thus, it can easily block the formation and cause high pressure. An excessive or small contact angle is not conducive to oil displacement. An excessive contact angle means strong hydrophilicity, which can cause a strong Jamin effect in oil-friendly formations. If the contact angle is too small, it has strong lipophilicity and can lead to poor solubility in water. Nano-oil displacement agent No. 4 had the best oil displacement effect, with an oil recovery increase of 7.35%, followed by nanometer oil displacement agent No. 1, with an oil recovery increase of 5.70%. Based on all the performance results, nanometer oil displacement agent No. 4 was more suitable as the oil displacement agent and can be used to enhance oil recovery in the Jimusaer reservoir. This study has laid a foundation for the chemical flooding development of shale oil in the Xinjiang oilfield. Full article

Conglomerate reservoirs are usually formed in sag slope belts, which have the characteristics of near-source rapid deposition, rapid sedimentary facies change, and distinct reservoir heterogeneity. Therefore, it is difficult to carry out treatments of stimulation because of insufficient understanding of the propagation mechanism of the unique “gravel-bypassing” and “gravel-penetrating” characteristics of fracture morphologies in Mahu conglomerate reservoirs. In order to study the law of hydraulic fracture propagation in conglomerate reservoirs, based on Brazilian splitting test results for conglomerates with different gravel particle sizes and different cementation degrees, true tri-axial fracturing experiments conducted in the laboratory were performed to conduct experimental research on natural conglomerate outcrops and analyze the effects of gravel size, fracturing fluid viscosity, and pumping rate on hydraulic fracture propagation morphology. The results show that: (1) the gravel cementation strength of fracture pressure is higher and the pressure drops preferably after fracturing. The fracture is more inclined to “pass through the gravel” to propagate in large-particle-size gravel. The poor gravel cementation of fracture pressure is relatively low-level and the pressure after fracture drops slightly, and fractures tend to occur at the margin of gravel; (2) using slick water for fracturing tends to initiate and propagate fractures at multiple points on the wellbore, which is conducive to the formation of complex fracture networks and the improvement of volume stimulation effects. Guanidine-gum fracturing has a higher fracture-forming efficiency and higher net pressure; and (3) a low pumping rate will increase the interaction degree between fractures and gravel, and gravels will cause a change in fracture roughness, resulting in small local fracture widths. Full article

The optimization of reservoir sweet spots is the key to the efficient exploration and development of low-permeability and tight sandstone gas reservoirs. However, offshore deep, low-permeability and tight sandstone has the characteristics of large burial depth, large diagenesis heterogeneity and prominent importance of diagenetic facies, which make it difficult to predict reservoir sweet spots. This work comprehensively used logging data, core observation, conventional core analysis, thin section, powder particle size analysis, clay X-ray diffraction analysis, cathode luminescence analysis, scanning electron microscopy and energy spectrum analysis and carried out the study of diagenesis, diagenetic facies and reservoir sweet spots of low-permeability and tight sandstone of H3 and H4 (the third and fourth members of Huagang Formation) members in the Jiaxing area of the Xihu Sag. The results show that the H3 and H4 sandstones were divided into five diagenetic facies types, and chlorite-coated facies and dissolution facies were favorable diagenetic facies belts. The H3 member mainly develops chlorite-coated facies, dissolution facies and quartz-cemented facies, whereas the H4 member primarily develops quartz-cemented facies and chlorite-coated facies. The percentages of type I sweet spot, type II₁ sweet spot and type II₂ sweet spot in the H3 reservoir are approximately 21%, 23% and 26%, respectively, whereas the percentages of type I sweet spot, type II₁ sweet spot and type II₂ sweet spot in the H4 reservoir are about 16%, 15% and 16%, respectively. The distribution rules of reservoir sweet spots were investigated. Type I sweet spot was mainly developed in the areas of chlorite-coated facies and dissolution facies of medium sandstone and coarse sandstone in the channel bar and braided channel sedimentary microfacies. Type II sweet spot was primarily distributed in the areas of quartz-cemented facies, chlorite-coated facies and minor dissolution facies of medium sandstone, fine sandstone and sandy conglomerate in the braided channel, subaqueous distributary channel and channel bar sedimentary microfacies. Type III sweet spot was chiefly developed in the areas of tightly compacted facies, calcite-cemented facies and quartz-cemented facies of fine sandstone, siltstone and a small amount of sandy conglomerate in the subaqueous distributary channel sedimentary microfacies. Full article

The development of the Mahu tight reservoir has adopted horizontal wells with staged fracturing. In the fracturing, there is a problem of a high fracturing pressure. Acid treatment is often used to lower the fracturing pressure on site. At present, the impact of this acid treatment on the physical parameters of the rocks of the reservoir in the Mahu region has not been systematically studied. Aiming to solve this problem, this paper conducted an experimental study on how acid dissolution affects the physical properties of the Mahu conglomerate, including its porosity, permeability, triaxial rock mechanical parameters, tensile strength, and mineral composition. First, the experimental scheme was designed. Next, a series of experiments were conducted. Finally, the experiment results were analyzed comparatively before and after acidizing. The acid composition, concentration, and contact time were the main factors for the analysis, based on which the acid system and related parameters were recommended. This study showed that the Mahu conglomerate exhibited brittle plasticity characteristics under stress. The carbonate content in this region was low, while the feldspar content was high, so it was necessary to use mud acid to effectively dissolve feldspar, clay, and other silicates. After acidizing, the porosity was 200% of the original value. The permeability increased by up to 14 times. The tensile strength decreased significantly by up to 84%. The value of Young’s modulus of the rock decreased by up to 63.6%. The value of Poisson’s ratio was reduced by up to 40.7%. A combination of 6% HF + 15% HCl is recommended, with an effective acid treatment time of over 60 min for the Mahu conglomerate. Acidizing could significantly change the mechanical properties and permeability of the rock of the Mahu conglomerate reservoir, thus effectively reducing the formation fracturing pressure. This research provides technical support for Mahu acid dipping in horizontal well fracturing. Full article

Many factors need to be considered in the evaluation of tight conglomerate reservoirs, including the microscopic pore-throat structure, pore connectivity, lithology, porosity, permeability, and clay mineral content. The contents and types of clay minerals reflect the mineral evolution process during the deposition of the reservoir and can reflect the reservoir’s physical properties to a certain extent. In this study, cores from the Baikouquan Formation in Mahu were used to comprehensively analyze the effects of the clay mineral content on the physical properties of a tight conglomerate reservoir, including field emission scanning electron microscopy (FE-SEM), casting thin section observations, X-ray diffraction (XRD), interface property testing, high-pressure mercury injection, low temperature N₂ adsorption, and nuclear magnetic resonance (NMR)-movable fluid saturation testing. The results revealed that differences in different lithologies lead to differences in clay mineral content and pore structure, which in turn lead to differences in porosity and permeability. The interface electrification, adsorption, and specific surface area of the reservoir are positively correlated with the clay mineral content, which is mainly affected by the smectite content. As the clay mineral content increases, the proportion of nanoscale pore throats increases, and the core becomes denser. The saturation of the movable fluid controlled by the >50 nm pore throats in the tight conglomerate ranges from 8.7% to 33.72%, with an average of 20.24%. The clay mineral content, especially the I/S (mixed layer of Illite and montmorillonite) content, is negatively correlated with the movable fluid. In general, the research results clarified the relationship between the lithology and physical properties of clay minerals and the microscopic pore structure of the tight conglomerate reservoirs in the Baikouquan Formation in the Mahu area. Full article

The conglomerate matrix and fracture propagation are special in tight conglomerate reservoir with small well spacing. In this article, the fractal propagation characteristics of the fracture network in conglomerate reservoirs are described by experiment and a micro-mathematical model. According to the core slice, the conglomerate reservoir matrix presents the multi-modal pore structure, described as the “pseudo-dual-media” model. Given the above, the unsteady seepage mathematical model, comprehensively considering the fractal fracture network, stress sensitivity of main fractures, and threshold pressure gradient of the reservoir matrix, was developed and analytically solved. The Blasingame type curves for production decline analysis were plotted, and the sensitive parameters were analyzed. The field application was performed for validation. The research results show that the fractal dimension decides the complexity of the fracture network distribution. As it increases, the unsteady flow occurs earlier, and the boundary flow is delayed. The anomalous diffusion exponent represents the smoothness of crude oil migration and a higher value leads to higher resistance to oil migration and larger pressure drawdown for the same production rate. The growth of the threshold pressure gradient within a certain range can result in a localized downward shift of the type curves. The field application in a conglomerate oil reservoir showed that the presented model presents a fitting accuracy 10% higher than that of the conventional SRV model and has high reliability and precision for the production performance evaluation of the small-well-spacing development of tight conglomerate reservoirs. Full article

Using the conventional fracture parameters is difficult to characterize and predict the complex natural fractures in the tight conglomerate reservoirs. In order to quantify the fracture behaviors, a fractal method was presented in this work. Firstly, the characteristics of fractures were depicted, then the fracture fractal dimensions were calculated using the box-counting method, and finally the geological significance of the fractal method was discussed. Three types of fractures were identified, including intra-gravel fractures, gravel edge fractures and trans-gravel fractures. The calculations show that the fracture fractal dimensions distribute between 1.20 and 1.50 with correlation coefficients being above 0.98. The fracture fractal dimension has exponential correlation with the fracture areal density, porosity and permeability and can therefore be used to quantify the fracture intensity. The apertures of micro-fractures are distributed between 10 μm and 100 μm, while the apertures of macro-fractures are distributed between 50 μm and 200 μm. The areal densities of fractures are distributed between 20.0 m·m⁻² and 50.0 m·m⁻², with an average of 31.42 m·m⁻². The cumulative frequency distribution of both fracture apertures and areal densities follow power law distribution. The fracture parameters at different scales can be predicted by extrapolating these power law distributions. Full article