The shale oil reservoir of Permian Lucaogou formation in the Jimsar sag of the Junggar Basin can be divided into two sweet spots from top to bottom. These sweet spots vary significantly in productivity and remain unclear for controlling factors, making sweet spot prediction challenging. By using geological, petrophysical experiment, logging, and formation testing data, the enrichment mechanisms of shale oil were identified, the main factors controlling sweet spots in the shale oil reservoir were investigated, sweet spot index was constructed, and a classification standard for sweet spots was established. The research results show that the dominant reservoir rocks in the sweet spots in the study area are silty-fine sandstone and psammitic dolomite, with good pore structure, relatively abundant free oil, and moderate brittleness. The development, distribution, and effectiveness of micro-fractures in the shale oil reservoir are influenced by formation overpressure. The sweet spots in the shale oil reservoir are mainly controlled by free oil saturation, formation overpressure, and brittleness index. The sweet spot index is greater than 45 for Class Ⅰ sweet spots, 25-45 for Class Ⅱ sweet spots, and less than 25 for Class Ⅲ sweet spots. Class Ⅰ and Class Ⅱ sweet spots are considered as prime targets for horizontal wells, while Class Ⅲ sweet spots are reserved for future development.
In order to determine the distribution of the fractures in the fourth member of the Dengying formation (Deng 4 member) in the Shehong-Yanting block of the Penglai gas field, Sichuan Basin, a statistical analysis was conducted on the structural fracture parameters. Based on rock rupture criteria, occurrence evolution conditions, and present-day stress field characteristics, a quantitative prediction of fractures in the ultra-deep carbonate reservoirs of the Deng 4 member were performed through tectonic stress field inversion. The results show that structural shear fractures are well developed in the Deng 4 member, oblique fractures are concentrated in the southeastern structural highs, while high-angle and vertical fractures are mostly distributed near faults. The fracture strikes are predominantly NW-SE, NE-SW and NNW-SSE. The linear density of fracture is generally low in the southeast and high in the northwest, while the fracture aperture shows an opposite distribution pattern. The fracture porosity reflects a relatively small variation. Fracture parameters exhibit different distribution characteristics within fault zones, near faults, and in non-fault areas, with the predicted results being largely consistent with the measured data. The fracture dip, aperture, and porosity significantly influence gas well productivity.
The carbonate reservoirs in the YUEM area of Tarim Basin show differences in natural fracture development. Using the data of outcrop, core, thin section, logging, seismic, and production performance, the differences of natural fractures in development characteristics, formation periods, genesis, and spatial distribution were clarified through fracture parameter statistics, sensitivity analysis of seismic attributes, and numerical simulation of tectonic stress field. Three types of fractures, i.e. diagenetic fractures, tectonic fractures, and composite fractures, corresponding to three development periods are found in the study area. The development of these fractures is controlled by the coupling of tectonics, sedimentation, and karstification. Favorable fracture development zones are identified in oblique-overlap zones, intersections of major and secondary faults, fault tips, algal reef facies belts, and tops and bottoms of karst caves.
The distribution patterns of interlayers in the YM 35 well block of the Tarim Basin are unclear, which poses challenges for subsequent oil and gas exploration and development. To identify the interlayer types in the study area and analyze their spatial distribution characteristics, by integrating the data of cores, conventional logging, laboratory analysis, and imaging logging, the primary interlayer types in the study area were clarified. By using the three-end-member classification method, charts for identifying interlayers were established for sublayers, and identification criteria were proposed. The distribution of interlayers was analyzed laterally and vertically, and the controls of interlayers on remaining oil distribution were investigated. The results show that the study area primarily develops argillaceous interlayers and physical interlayers. Laterally, argillaceous interlayers are mainly concentrated in the lower part of the target layer, with good continuity, while physical interlayers are mainly distributed in the middle-upper part, with smaller thickness but good continuity. On plane, interlayers are mainly concentrated in the central part of the study area, forming a distinct thickness aggregation zone. The interlayer becomes thinner toward its margin as its distance from the central area increases. Controlled by the spatial distribution of interlayers, remaining oil is mainly distributed in the K3 sublayer.
The Tarim Basin is characterized by low surface heat flow and significant variation in formation temperature. To clarify the characteristics and controlling factors of deep geothermal field in the Shuntuoguole area of central Tarim Basin, by using the systematic steady-state temperature measurement data from 33 wells in the Shuntuoguole and surrounding areas, the geothermal gradients and deep temperature distribution characteristics were investigated. On this basis, the geothermal properties of sedimentary rocks and their impacts on heat flow and temperature were analyzed. Coupling with geophysical data, a layering model for the earth’s crust was constructed, and the heat flow density of the crust was calculated. The research results show that in the Shunnan, Shuntuo, and Shunbei areas, the average geothermal gradients at a depth ranging from 0 to 5 km are 22.5°C/km, 20.0°C/km, and 18.6°C/km, respectively, and the average formation temperatures at the depth of 8 km in the 3 areas are approximately 200°C, 175°C, and 135°C, respectively, indicating significant differences in the geothermal fields. The differences in the crustal structure account for variations in the crustal heat flow, and the crustal structure is the primary controlling factor for the geothermal field differences in the study area. The geothermal properties of sedimentary rocks have a negligible impact on the geothermal field. The rapid sedimentation in the Shunbei area since the Pliocene and the deep hydrothermal activity in the Shunnan area have no influence on the present-day geothermal field.
Physical properties, petrological properties, and microscopic pore structure are key factors controlling movable fluids in tight sandstone reservoirs. To reveal the differences of the movable fluids in the reservoirs of the Shan-1 member in the Sulige gas field, northern Ordos Basin and in the Qingyang gas field, southwestern Ordos Basin, by employing multiple techniques such as X-ray diffraction, scanning electron microscopy, cast thin section analysis, high-pressure mercury intrusion, and nuclear magnetic resonance (NMR), the differences in microscopic pore structure of reservoirs were clarified, and then the differences of movable fluids from the Shan-1 member reservoirs in the two areas were identified. The results show that the pore structures in the two parts can be classified into three types based on pore-throat radius distribution and reservoir physical properties. Type I pore structures are relatively well-developed, with movable fluids present across a wide range of pore radii, and the movable fluid content significantly sensitive to the sorting coefficient. Type II pore structures exhibit uneven pore-throat distribution, with the movable fluid content notably affected by the median pore-throat radius. Type III pore structures have a smaller range of pore radius distribution, with movable fluids mainly concentrated in small pores, and the movable fluid content primarily influenced by clay mineral content. In the Sulige gas field, the Shan-1 member is dominated by Type II pore structures, with a movable fluid content of 24.11%, which is influenced by permeability, median pore-throat radius, and illite content. In the Qingyang gas field, the Shan-1 member is dominated by Type III pore structures, with the movable fluid content mainly influenced by porosity, permeabilty, and clay mineral content.
The shale reservoirs of Lower Jurassic Lianggaoshan formation in the Sichuan Basin are well-developed, with nanoscale pores. These reservoirs are characterized by low porosity, low permeability, diverse pore types, complex pore structures, and a wide range of pore radius distribution. Therefore, accurately evaluating pore structure of shale reservoirs is of great significance for reservoir evaluation and sweet spot prediction. Using the data from scanning electron microscopy (SEM), gas adsorption experiments, and nuclear magnetic resonance (NMR) experiments, the pore structures of different lithofacies in the Lianggaoshan formation were characterized. The calculation models for pore radius distribution based on N2 and CO2 adsorption were defined，and the surface relaxation rate, a conversion parameter between pore radius and transverse relaxation time, was determined to enable the characterization of full-size pore radius across lithofacies. And the relationship between surface relaxation rate and mineral contents was investigated. The results show that the surface relaxation rate is inversely proportional to the contents of quartz, plagioclase, and calcite, and directly proportional to the contents of potassium feldspar, siderite, and clay minerals. Chlorite, pyrite, and siderite are paramagnetic materials; as the concentration of paramagnetic ions increases, the magnetic susceptibility of these minerals increases, thereby enhancing the surface relaxation rate.
Based on the development background of the strike-slip fault zone in the Shunbei area of the Tarim Basin, the in-situ stress states, the fracture systems around faults, and the well productivity characteristics in different segments of the Shunbei No.4 strike-slip fault zone were analyzed by using geomechanical theories. According to the reservoir mechanical properties obtained through P-wave and S-wave logging and rock mechanics experiments, a 3D geomechanical model was constructed. Based on the elastoplastic theory, and by using the finite element numerical simulation method, the fracture development characteristics of the target layer controlled by the strike-slip faults were predicted. The research results show that the in-situ stress patterns vary across segments in the fault zone. The differences in structures of geological units control the in-situ stress distribution, and regions with high fracture density typically exhibit a strip-like distribution on both sides of the fault or between faults. High fracture density combined with Anderson-type Ⅰa and Ⅲ stress states is associated with wells exhibiting high yields. The in-situ stress conditions, fracture development characteristics, and key factors controlling high well productivity in different segments in the Shunbei strike-slip fault zone were clarified.
In order to enhance the understanding of mineral features of chlorite and laumontite in the lower Wuerhe formation of Permian in the western Luliang uplift, Junggar Basin, the chemical composition, occurrence states, and impacts on reservoir physical properties were studied by means of thin section, electron probe and X-ray diffraction. It is found that the chlorite has an trioctahedral crystal structure and occurs in three states: pore lining, particle coating, and pore filling. It is classified as an iron-magnesium transitional type, richer in magnesium. Fe replacing Mg mainly occurs in the octahedrons, with the Al/(Al+Mg+Fe) ratio ranging from 0.25 to 0.37. The forming of chlorite is attributed to the alteration of argillaceous rocks and the transformation of mafic rocks, with substantial material input from the hydrolytic dissolution of tuffaceous volcanic materials and the interconversion of clay minerals. Laumontite occurs in three states: crystal aggregate, filling, and replacement. The laumontite in crystal aggregate state is surrounded by numerous debris, which promotes the formation of laumontite. The laumontite in filling state coexists with chlorite, calcite and other minerals, which compete with them for material sources, partially inhibiting the formation of laumontite. The laumontite in replacement state is mainly formed by the replacement of feldspar and debris, resulting in high Si/Al ratio and good acid resistance, which allow the laumontite to be not easily dissolved. Chlorite and laumontite have dual effects on reservoir physical properties. Chlorite can significantly improve reservoir physical properties, resulting in the formation of high-quality reservoirs. In contrast, the effect of laumontite on reservoir properties is limited. With the increase of burial depth, the lower Wuerhe formation presents a variation in diagenetic environment from alkaline to weakly acidic and then to alkaline, with a relatively closed diagenetic system.
Shale oil and gas resources are abundant in China, and hydraulic fracturing to stimulate reservoir is a significant way to efficiently develop these resources. Brittleness is a key parameter for reservoir stimulation and a core indicator for identifying engineering sweet spots. Taking the shale reservoir in the Dongying sag as an example, the rock mechanical properties and brittleness characteristics of the shale reservoir were analyzed through uniaxial, triaxial, and high-temperature, high-pressure (HTHP) compressive tests. Based on the rock energy balance theory and brittleness characteristics, as well as the energy evolution behaviors before and after rock failure, a new method for evaluating shale brittleness was proposed. The research results show that under uniaxial conditions, the shale exhibits significant brittle failure with multiple cracks, which is beneficial for reservoir stimulation. In HTHP conditions, the synergistic effect of temperature and confining pressure suppresses rock brittle fracture but strengthens rock ductility, leading to a significant reduction in brittleness. Based on the proposed brittleness evaluation method, the primary factors controlling shale brittleness were identified. It is found that the rock physical parameters (porosity, density, and acoustic travel time) is weakly correlated with brittleness, while mineral composition and elastic parameters are more effective in assessing brittleness. The effects of temperature and pressure cannot be ignored. The research results are conductive to identifying engineering sweet spots in shale reservoirs and provide a theoretical foundation for efficient reservoir stimulation.
The low to ultra-low permeability reservoirs in the DF A and WC X/Y blocks, western South China Sea, are characterized by complex microscopic structures, making it difficult to understand the lower limits of reservoir physical and electrical properties. Through core single-phase displacement experiments under various pressure differences, and core capillary pressure-lithoelectric experiments at high temperature and high pressure, the lower limits of porosity, permeability, saturation, and resistivity of these low to ultra-low permeability gas reservoirs were examined. On this basis, the variations of the lower limits of these reservoir properties were discussed. The results show that the cores obtained from the gas reservoirs in the DF A block have the physical properties which are positively correlated with gas flow rate, and the cores from the ultra-low permeability gas reservoirs in the WC X/Y block exhibit very low gas flow rate, which couldn’t be improved significantly as the pressure difference was increased. In the presence of irreducible water, as the differential pressure for production increased, the lower limits of porosity and permeability of cores from both blocks declined gradually. As the physical properties of the reservoirs improved, the upper limit of water saturation became lower. As the reservoir physical properties improve, the cores from the DF A block demonstrated an increasing lower limit of resistivity, while the cores from the WC X/Y block reflected a decreasing lower limit. It is supposed that the reason should be attributed to different pore structures and fluid occurrence states of the reservoirs.
The sublayers from N1g45 to N1g16 of the Guantao formation in western Block 7 of the Gudong oilfield are typical of braided river deposits, with complex internal sandbody architectures. A detailed analysis of the reservoir architecture is necessary to understand its impact on oil and gas development. By using the Miall’s architectural element analysis method, and constrained by modern braided river scale, the sandbody architecture was characterized. Combining dynamic and static methods, the reservoir architectures were validated, and their influences on waterflood performance and residual oil distribution were identified. The research results show that the study area exhibits sandy braided river deposits, mainly with four sedimentary architecture units: braided river channels, mid-channel bars, overbanks, and floodplains. The braided flow zone is 150-750 m wide, with a width-to-thickness ratio ranging from 47 to 74. Within the braided flow zone, there are four types of architectural patterns: braided river channel-braided river channel, mid-channel bar-mid-channel bar, braided river channel-mid-channel bar-braided river channel, and mid-channel bar-braided river channel-mid-channel bar. The mid-channel bars have average length of 250-350 m and average width of 110-140 m, with a length-to-width ratio of 2.20-2.50. The ratio of mid-channel bar area to channel area ranges from 0.36 to 0.51. The mid-channel bars typically develop 2-4 fall-silt seams with their extension ranging from 70 to 150 m, which are nearly horizontal, with interlayer dip angles between 0.9° and 2.3°. Production performance reveals that due to poor petrophysical properties at the edges of architecture units, oil and gas flows are impeded at the architectural junctions where residual oil will be enriched locally. In contrast, the main parts of the architecture units show good reservoir connectivity and development effects.
The Jurassic ultra-deep sandstone reservoirs in the Yongjin-Zhengshacun area of the Junggar Basin are tight and heterogeneous, and the standards for evaluating these reservoirs and the favorable reservoir distribution are unclear, restricting oil and gas exploration and development. Based on well logging, coring, and testing data, and by using mineral analysis, nuclear magnetic resonance (NMR), capillary pressure experiments, and core displacement tests, a study was conducted on the pore structure of the Jurassic reservoirs. The lower limit of movable pore radius was determined, and a grading evaluation standard was established with movable fluid porosity as the key indicator. The results show that the reservoir space in the medium- to fine-grained lithic and feldspathic sandstones is composed of intergranular pores, secondary dissolution pores, and microfractures, with small pore radii ranging from 0.005 to 5.000 μm. After calibrating the experimental capillary pressure curves, the lower limit of movable pore radius was determined as 0.100 μm through the NMR T2 spectrum at different displacement states, and then the movable fluid porosity of oil-bearing rocks was clarified. By comprehensively considering the lithoelectric characteristics, pore type and structure, and oil-bearing property, and combining the productivity characteristics of typical wells, a grading reservoir evaluation standard for the study area was established. Based on the standard the reservoirs were classified into Class Ⅰ, Class Ⅱ, and Class Ⅲ. The evaluation provides a basis for subsequent oil and gas field development and well deployment, and offers valuable insights for the exploration and development of ultra-deep tight oil reservoirs in the study area and for reservoir evaluation in neighboring areas.
The structural deformation in the foreland thrust belt of the Kuqa depression mainly occurred during the middle-late Himalayan orogeny. Previous studies primarily identified the initiation timing of shallow postsalt fold deformation, but had no absolute dating constraints on the subsalt thrust deformation and the timing of hydrocarbon accumulation. Taking the Awat area in the Kuqa depression as an example, using the data from petrographic observations, calcite U-Pb dating, and fluid inclusion analysis, the diagenesis, formation timing of calcite veins, and hydrocarbon accumulation process of the Lower Cretaceous Baxigai formation reservoirs were investigated, and the timing of structural deformation and hydrocarbon accumulation in the Awat area was determined. The research results show that two periods of calcite were developed in the Baxigai formation in the Awat area. The early calcite cement formed at (98.0±14.0) Ma, while the late calcite veins formed at (3.7±1.0) Ma, reflecting the time of subsalt thrust deformation. Oil inclusions and gas inclusions of different periods were identified in the calcite veins. Based on the homogenization temperatures of the fluid inclusions, burial history and thermal history, it is inferred that the oil charging occurred at 4.0-3.0 Ma, and gas charging at 3.0-1.0 Ma. The early oil reservoir underwent reworking of gas washing in the late Pliocene, forming the current condensate gas reservoir.
Well S3 drilled in the gentle slope zone of the eastern Shiqiantan sag in the east uplift of the Junggar basin, has produced a high-yield industrial gas flow from the Carboniferous Shiqiantan formation. This significant breakthrough in natural gas exploration in the Shiqiantan formation further confirms the presence of a marine clastic-rock sag rich in natural gas in the eastern Junggar basin. To better understand the geological characteristics and petroleum exploration potential of the Shiqiantan formation in the Shiqiantan sag, a comprehensive study of source rocks, reservoirs, and hydrocarbon accumulation was conducted using seismic, drilling, logging, core, and testing data. The Shiqiantan formation in the study area contains two sets of source rocks, which are generally thick and of high quality, providing a solid material basis for large-scale gas reservoir development. The reservoirs in the Shiqiantan formation are typically composed of tight sandy conglomerate in which a fan delta system with bidirectional provenances in the south and north is found. Large scale delta-front sand bodies are mainly distributed in the slope zone around the sag. The Shiqiantan formation hosts near-source tight lithological sandstone gas reservoirs, making it the key target for gas exploration in the Carboniferous of the Shiqiantan sag. It has favorable source-reservoir assemblages jointly controlled by proximity to the source and sand body size.
The Jurassic strata in the areas around the Yakela fault-bulge in the northern Tarim basin are critical targets for hydrocarbon exploration, where a near-source alluvial fan-fan delta system with the fault-bulge as a provenance is developed. This cannot explain the extensive development of the sandbodies in Jurassic in the southern Yakela fault-bulge. Based on the analysis of the tectonic evolution of the Yakela fault-bulge, together with the seismic and core data and the reservoir characteristics, a comprehensive analysis was conducted on the sedimentary facies to determine the spatial distribution patterns of the sedimentary facies in the Jurassic Yangxia formation around the Yakela fault-bulge. It is found that during the Jurassic deposition the Yakela fault-bulge as a whole was higher in the west than in the east, with erosion occurring in the west and a peneplain state in the east at the late stage of Yangxia formation deposition. The sedimentary system primarily comprises two parts: one sourced from the western Yakela fault-bulge, forming an apron-like distribution of the near-source fan delta deposits along the fault-bulge; the other sourced from the southern Tianshan Mountains, forming a braided river delta system extending from north to south in the eastern Yakela fault-bulge. From the perspective of reservoir characteristics, the fan delta system is characterized by coarse lithology, mainly including conglomerates and gravel-bearing medium-coarse sandstones, with low textural and compositional maturities and poor physical properties. In contrast, the braided river delta system predominantly consists of gravel-bearing medium-fine sandstones, and records a long transport distance, with high textural and compositional maturities and good physical properties. The Yangxia formation in the eastern Yangxia sag may be a potential favorable exploration target.
The deep buried-hill interior reservoirs in the Jizhong depression are key successive zones for oil and gas exploration, and clarifying their genetic mechanisms is particularly important for effective exploration and development. Based on the data of drilling, logging, outcrops, cores, and thin sections, the deep Ordovician dolomite reservoirs were characterized, their controlling factors were analyzed, and the evolution models of high-quality reservoirs were established. The research results show that three sets of high-quality reservoirs are developed in the Ordovician of the Jizhong depression. These reservoirs which are primarily composed of crystalline dolomite and limy dolomite exhibit strong heterogeneity and poor porosity-permeability correlation. Four types of reservoir spaces including intercrystalline pores, dissolved pores, karst caves, and fractures are found in the reservoirs. Dolomitization, dissolution, and tectonic fracturing are identified as constructive diagenetic processes, whereas compaction, cementation, dedolomitization, pyritization, and silicification are classified as destructive diagenetic processes. Sedimentation controlled by periodic sea-level changes and dolomitization provided material basis for the reservoir formation. The diagenetic sequence determined the three stages of pore evolution. Tectonic activities played a dominant role in reservoir reformation. Ultimately, the deep buried-hill type and slope type high-quality dolomite reservoirs were formed after four evolutionary stages.
Micro-minor fractures represent a key type of reservoir space in the thin biolimestones of the Shahejie formation in the Wangxuzhuang oilfield. Due to the lack of effective measurement methods and characterization techniques, it is challenging to understand these fractures, thereby hindering accurate prediction of fluid flow capacity during oil and gas development. By integrating the data of core samples, thin sections, CT scanning, formation micro-resistivity imaging (FMI) logging, and conventional logging, the development of micro-minor fractures was investigated. With a PSO-BP neural network, the fracture development and distribution in the fractured reservoirs of the study area were predicted. Then a discrete fracture network modeling approach was proposed to simulate the spatial distribution of these fractures. The results show that the biolimestone with developed micro-minor fractures exhibits significant amplitude differences between shallow and deep lateral resistivity readings. Micro-minor fractures are well developed in the biolimestones in the study area, which play a crucial role in improving reservoir physical properties and waterflood response directions. These fractures are controlled by fault zones and sedimentary microfacies of the biolimestone. Numerical simulation confirms that the dual-porosity dual-permeability model incorporating micro-minor fractures can provide a better fit for the dynamic behavior of oil-water relations.
The seismic data acquired from Kuqa foreland thrust belt is characterized by low signal-to-noise ratio and high interpretive ambiguity. By using high-resolution 3D seismic data, drilling and lab hydrocarbon analysis data, the stratigraphic assemblages of Kuqa foreland thrust belt were systematically described, the structural model was detailedly interpreted, and the hydrocarbon accumulation system was deeply analyzed. It is found that the Kuqa foreland thrust belt develops two sets of detachment layers: Paleogene and Neogene gypsum-salt rocks, and Triassic and Jurassic coal measures, all of which feature stratified detachment, vertical stacking, and multiphase deformation. Detachment folds in caprocks are found in the shallow structures, while basement-involved imbricate thrust structures are developed in deep strata. Detachment plastic deformation occured in the gypsum-salt and coal layers. Faulting occured in three phases including Caledonian, late Hercynian-Indosinian, and Yanshanian-Himalayan. The late Hercynian-Indosinian tectonics controlled the Mesozoic sedimentation, showing a north-to-south onlap thinning feature. Layered structural deformation in the Kuqa foreland thrust belt governs the stratified accumulation and migration of hydrocarbons. Hydrocarbons in the strata above the coal seam predominantly originated from the Jurassic source rocks, whereas oil and gas in the strata below the coal seam mainly came from the Triassic source rocks which contributs 60% of the hydrocarbons. A substantial quantity of hydrocarbon remains trapped in the formation below the coal layer.
Seismic prediction of fractures is the foundation of fractured reservoir evaluation. Metamorphic buried-hill reservoirs exhibit diverse fracture types, significant variations in fracture development at different reservoir parts, and difficulties in describing fracture heterogeneity. The Z4 metamorphic buried-hill reservoir was investigated for its fracture characteristics and seismic prediction. The development of fractures in the Z4 reservoir has layering characteristics and can be divided into four sections such as weathered-semi-filled fractures at the top, highly developed net-like fractures in the upper part, moderately developed low-angle fractures in the middle part, and poorly developed high-angle fractures at the bottom. A comprehensive fracture prediction technique was proposed, which integrates multi-scale general spectral decomposition, dip-oriented eigenvalue coherent processing, and iterative ant analysis. The fracture orientations and development revealed by cores were compared with the results of seismic prediction, suggesting a high consistency. It is believed that the multi-approach comprehensive fracture seismic prediction technology proposed in this study has high accuracy.
