In order to optimize the sweet spot intervals with natural fractures in the well of Cretaceous ultra-deep tight sandstone reservoirs in the Kuqa Depression of Tarim Basin, the difference of reservoir rock mechanical properties of different sedimentary microfacies in BZ gas field was systematically analyzed by using outcrop, rock slice, imaging logging and other data. Then the geometric parameter models of different sedimentary microfacies in related outcrops were combined to propose a new method to optimize the reservoir rock mechanical parameter model, which improved the prediction accuracy of natural fractures around the wellbore (< 200 m). This research indicates that:(1) There are differences in reservoir rock fabrics and rock combinations (including debris content, matrix content, grain sorting, sand ratio, and sandstone-mudstone combination) among various sedimentary microfacies and different parts of the same microfacies, which affects the Poisson's ratio and Young's modulus of the third member of Bashijiqike Formation in BZ gas field. (2) The degree of crack development varies among different sedimentary microfacies of sand bodies, with the sandstone in the underwater branch channel of fan delta front being the most developed, making it easier to form cracks than the inter bay microfacies of fan delta front and the branch channel microfacies of fan delta plain. (3) So we conclude that different microfacies reservoirs have different rock mechanical parameters. Furthermore, a three-dimensional microfacies model was established based on the geometric parameters of sedimentary microfacies in outcrops and was used to optimize sedimentary microfacies models and rock mechanics parameter models around wellbores, which were applied to fracture prediction around wellbores.

The deformation and connectivity mechanism of high angle near vertical fault surface is revealed through large-scale rock sample mechanical experiments in order to improve the development benefit of ultra-deep fault-controlled carbonate reservoirs. Based on the mechanics and flow coupling principle of high-pressure water injection production, the in-situ stress field and fault activity distribution law of fault-controlled carbonate reser- voirs are clearly determined through geomechanics modeling. It is found that there are obvious differences in fault activity in different directions and fracture cavity connectivity in different parts, and then the development effects of different wellbore trajectories are analyzed. The geology-engineering integration is put forward to scientifically guide the design of wellbore trajectories and the optimization of water injection schemes. The results show that:① Large-scale fractures and high-angle fracture systems in the deformation of strike-slip faults are the key factors affecting reservoir quality. On the one hand, high-pressure water injection can activate preexisting fractures, and on the other hand, it can extend and expand on the basis of preexisting fractures, and even generate new fractures, which promotes the interconnection of the fault-controlled fracture-cavity bodies in the vertical and horizontal direc- tions. ② The coupling change between mechanics and flow occurred inside the fracture body during the process of high pressure water injection, the seepage environment is improved, and the oil and gas recovery factor is improved through cyclic lifting. ③ According to the shape and occurrence of fault body and the dynamic shear deformation connectivity of fault surface, the best well point and well trajectory of directional well can be selected, and the water injection scheme can be optimized. ④ The oil and gas recovery factor of the fault-controlled reservoir test area in the Tarim Basin is increased by five percentage points by high-pressure water injection. This method provides a good theoretical basis and technical support for highly efficient development of ultra-deep fault-controlled oil reservoirs.

In this study, in order to find out the mechanical properties of tight sandstones in Cretaceous Bashijiqike Formation of Kuqa Depression of Tarim Basin, combining with field problems during deep -ultra-deep oil and gas exploration and development, variations of mechanical properties of rocks were quantitatively studied using triaxial compression experiments under the effects of confining pressure and fluid and loading rate, and the reasons were also preliminarily analyzed. The results show that the maximum principal stress difference and elastic modulus of sandstones samples increase significantly with the increase of confining pressure. The microscopic reason is that the increase of confining pressure shortens the distance among particles inside the rock and enhances the cohesion of the rock, hence, particles are not easily separated. Sandstone samples experience the process of brittleness under low confining pressure→brittle-ductile transformation→ductile deformation under high confining pressure. Compared with dry sandstone samples, the reductions of elastic modulus for samples soaked in pure water, 150 g/L solution, 250 g/L solution, and 350 g/L solution were 67. 71%, 61. 45%, 64. 69%, and 57. 32%, respectively. The reduction for the sample soaked in pure water is the largest, and the increase of fluid salinity can weaken the trend of mechanical parameters of rock weakening. The crystallization and changes of electric double layer thickness are important controlling factors for the above changes. At a relatively low loading rate, the maximum principal stress difference, elastic modulus, and Poisson's ratio of the sandstone sample are small, but increase fast relatively with the increase of loading rate. When the loading rate reaches a certain critical value (e.g., about 0.05 mm/min in this experiment), the increase rate of mechanical parameters of rock slows down.

Sweet spot evaluation is of great significance for efficient exploration and development of shale gas reser- voirs. Taking the shale reservoir in Ordovician Wulalike Formation on the western margin of the Ordos Basin as the research object, eight experiments including rock section analysis, X-ray diffraction, SEM scanning electron microscopy, low-temperature nitrogen adsorption, isothermal adsorption, total organic carbon (TOC) content test, organic matter vitrinite reflectance (R_o) test and triaxial rock mechanics test were carried out in this study. It is found that the rock type in the target area is gray brown mud shale, with the pore size in the ranges of 2-4 nm and 35-61 nm, and intergranular pores, clay mineral interlayer pores and intragranular pores are developed. The TOC content is 1.01%, the average R_o value is 1.75%, and the brittleness index is 47.8%. By analyzing the influence of different factors on the selection and evaluation of shale reservoir sweet spots, it is concluded that the content of siliceous minerals, clay minerals, pore specific surface area, TOC content and R_o value play a decisive role on the adsorption perfor-mance of the reservoir, the pore size and the number of pore types control the reservoir property, the content of brittle minerals and rock mechanics parameters affect the compressibility of the reservoir. According to the two indexes of adsorption property and reservoir property evaluated by geological sweet spots and the compressibility index of engineering sweet spots, the parameter indexes corresponding to different characteristics are finely classified, and a classification and evaluation scheme of geological sweet spots and compressibility sweet spots of the marine shale gas reservoir in Ordovi- cian Wulalike Formation in the Ordos Basin is preliminarily established. The results show that all characteristic para- meters in the target area meet the gradeⅡstandard. It could be a sweet spot for shale gas development.

In order to investigate the natural fracture development law and its influencing factors in deep-buried tight oil reservoirs, in this paper, we take the Ⅱ-Ⅵ tight oil formations of the third member of Paleogene Hetaoyuan Formation in southeast An'peng area of the Biyang Sag, Nanxiang Basin as an example. A systematic evaluation has been carried out based on a large number of core, thin section, physical properties, imaging, conventional logging and water flooding data. The Ⅱ-Ⅵ oil formations belongs to fan-delta front deposits with high content of rock debris, which are near-source deposits. There is a good positive correlation between reservoir porosity and permeability. For sandstone reservoirs with different lithologies, fractures are mainly developed in fine sandstone, followed by siltstone, but not in pebbled sandstone. In the target layer, high-angle and vertical fractures are dominant, accounting for 87.8%, while low-angle and horizontal fractures account for 7.3% and 4.9%, respectively. The main controlling factors for fracture development in tight reservoirs in the target formations include lithology, sedimentary microfacies and structural characteristics. Fractures are usually developed in single or composite sand bodies with thinner thickness and finer granularity. Fractures are mainly developed in front channel, the flank of channel, mouth bar and the outer edge of far sand bar body. However, fractures do not develop in sheet sand or front delta microfacies. In addition, fractures mainly develop at the transition end of structure, and mainly at the top and wing of forward structure. The fractures in the target strata are mainly distributed along the WE and NE directions, followed by NW direction. It is believed that the fractures were mainly formed in the Neogene depression period (late Himalaya). Fracture is an important factor leading to water channeling in tight oil reservoirs, so it is necessary to strengthen the dynamic and static monitoring of fracture development degree, expansion scale and direction.

The Longwangmiao Formation in the Penglai gas area has encountered good carbonate reservoirs and good gas shows. It has become one of the key exploration areas of the Longwangmiao Formation after the Anyue gas field in the central Sichuan area. However, the unclear reservoir development law restricts exploration deployment. Based on the latest drilling and testing data, the reservoir characteristics and main controlling factors of Longwangmiao Formation in Penglai gas area are systematically analyzed. The study shows that the Longwangmiao Formation in Penglai gas area has a mixed sedimentary background of terrigenous debris and carbonate, and the reservoirs are mainly distributed in the upper part of the Longwangmiao Formation. The reservoir rock types are mainly (residual) granular dolomite and crystalline dolomite. The reservoir space types are mainly intergranular dissolved pores, intragranular dissolved pores, intercrystalline dissolved pores and microfractures. The reservoir is mainly composed of low porosity and low permeability reservoirs, and the reservoir thickness is mainly between 10-42 m.Reservoir development is controlled by sequence stratigraphy, lithology and diagenesis. The (residual) granular dolomite and crystalline dolomite in the middle and upper parts of the progradational parasequence set and parasequence are the main parts of reservoir development. Atmospheric freshwater dissolution, oil and gas dissolution and fracture are the core constructive diagenesis. Compared with the Moxi-Gaoshiti area in the main area of Anyue gas field, it is considered that the main controlling factors of the reservoir are similar, which are mainly controlled by granular dolomite, dissolution and fracturing. However, the Longwangmiao Formation reservoir in Penglai gas area has the characteristics of high ash content, high terrigenous clastic content and weak penecontemporaneous exposure. Looking for high-energy granular dolomite and fine-grained dolomite exposed in the penecontemporaneous period and dolomite modified by supergene karst are the key reservoir targets in Penglai gas area.

Shenmu Gas Field in Ordos Basin shows the characteristics of low quality gas reservoir, and its development effect is quite different from that of surrounding gas fields, which brings some problems to the exploration deployment and sustainable production of the gas field. In order to reveal the origin of lowquality gas reservoirs, the microscopic characteristics and formation mechanism of Taiyuan Formation reservoirs in Shenmu Gas Field were studied based on microscopic experiments at different scales. The results show that the reservoir of Taiyuan Formation in Shenmu Gas Field is characterized by "rich in quartz, poor in feldspar, and high content of rock detritus". The reservoir of Taiyuan Formation is a low porosity and ultra-low permeability tight sandstone reservoir with small pore-fine throat combination, poor pore throat connectivity, and weak reservoir permeability. The formation of low-quality reservoirs in Taiyuan Formation is affected by the matrix, the content of rock detritus in eruptive rocks and diagenesis. During the late Carboniferous to early Permian, the formation of the reservoir was significantly affected by the volcanic activity of the Inner Mongolia ancient uplift in the north of the Ordos Basin. The content of matrix and rock detritus of the eruptive rock in the sandstone was generally high. The rock detritus of the eruptive rock provided the main material basis for the development of secondary pores. While the matrix blocked the pores, it also produced a certain number of matrix dissolved pores, which had a dual impact on the reservoir. The dissolution during diagenesis is critical to the formation of Taiyuan Formation reservoir, and the increased porosity accounts for 64.3% of the current porosity. At the end of the Late Cretaceous, the late Yanshan movement led to the structural inversion of the Ordos Basin, the readjustment of gas and water, and the escape of natural gas along the fault in the eastern part of the basin. Finally, the low quality gas reservoir of Taiyuan Formation in Shenmu Gas Field is formed. The next exploration focus of Shenmu Gas Field should be based on the clear macro distribution law of diagenesis and favorable lithologic traps, and further search for the development area with high content of eruptive rock detritus and low content of matrix.

Multiple sets of source rocks developed in the Carboniferous on the northeastern margin of Junggar Basin. Modelling the thermal evolution history of source rocks is of great importance to deepen the understanding of hydrocar- bon accumulation. Based on the study of basin evolution and source rock development characteristics, this paper applies a TSM Basin Simulation and Resource Evaluation System to establish one-dimensional and three-dimensional basin simulation models so as to reconstruct the burial, thermal evolution and hydrocarbon generation histories of different structural units. There are obvious differences in the hydrocarbon generation and evolution process of Carboniferous source rocks in different sags on the northeastern margin of the Junggar Basin. The Carboniferous source rocks in the Wulungu Depression entered the low-maturity evolution stage at the end of the Carboniferous, stagnated due to uplifts in the Permian, reached the threshold of secondary hydrocarbon generation at the end of Triassic when burial resumed, and are now in the over-mature stage, mainly generating dry gas (R_o>2.0%). The Carboniferous source rocks in the Sannan Sag entered the low-maturity stage in the Permian and are now in the high-maturity gas-producing stage (R_o=1.5% -1.9%). The Carboniferous source rocks in the Dishuiquan Sag entered the low-maturity stage in the Triassic and are now in the mature oil-producing stage (R_o=0.8%-1.3%). Simulation calculations show that the cumulative hydrocarbon generation of the source rocks in the Carboniferous Jiangbasitao Formation in the Wulungu Depression amounts to 20.5×10⁹ t, in which the cumulative hydrocarbon generation until the end of Carboniferous is 10.3×10⁹ t, which is the main oil generation stage. The cumulative gas generation at the end of Cretaceous is 18.4×10⁹ t, which is the main gas generation period.