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.

To reveal expansion pattern of steam chambers in heavy oil reservoirs during steam-assisted gravity drainage (SAGD), the time-lapse microgravity monitoring technology was employed to investigate the expansion pattern of SAGD steam chambers in the heavy oil reservoirs of the Jurassic Qigu formation in the H well block of the Xinjiang oilfield. This technology provided residual gravity anomaly data reflecting the remaining density of the reservoir. Using these data, a 3D least-squares inversion was performed to accurately depict the vertical distribution of the steam chambers. Furthermore, a method for interpreting the relationship between the steam chamber expansion pattern and residual gravity anomalies was proposed. The results indicate that the evolution of the steam chambers can be divided into three stages: rising, lateral expansion, and downward expansion. The proposed method can effectively explain the expansion patterns of the steam chambers in five well groups in the H well block, and its accuracy and reliability were validated with well temperature data. The method reveals the expansion patterns of the SAGD steam chambers in the reservoirs, providing a technical support for the efficient development of heavy oil reservoirs and aiding in the optimization of production control measures. It also offers a theoretical and practical foundation for similar reservoir development.

Water drive curve method is one of the important methods in dynamically calibrating recoverable reserves. This is a forward estimation method for water flooding reservoir without major adjustment measures and changing development modes, and with basically steady water flooding status. Setting the limit water cut at 0.98 lacks a solid scientific basis. Since the water drive characteristics vary significantly among different reservoirs, it is essential to select a water drive curve that best aligns with the reservoir’s actual behavior from the four water drive characteristic curves, rather than choosing the one with the lowest technically recoverable reserves, which will lead to weak reliability of calibration. Therefore, the four water drive characteristic curves and the production decline method were inverted and optimized for joint elimination, and a new relationship between water/liquid-oil ratio and production decline was established. This can determine the limit water cut and also ensure the uniqueness of the recoverable reserves calibrated by dynamic methods.

The Duong production decline model and modified Duong production decline model widely used for unconventional oil and gas reservoirs are disadvantageous in some aspects, such as incorrect definitions of characteristic parameters, inability to take zero as an independent variable, and lack of flow theoretical basis as a mathematical model. To address these problems, a new production decline equation was proposed by improving the mathematical model of relative permeability of oil phase in fractured reservoirs, and integrating the more applicable water phase relative permeability relational expression and the Welge equation. The new equation is similar in form to the modified Duong model, and can be transformed into the Arps production decline equation when the characteristic parameter A is zero, indicating that the new equation is a generalized production decline equation. The application of the new equation to the tight tuff oil reservoir of the Tiaohu formation in Block Ma56 of Tuha oilfield demonstrated a favorable effect, providing a valuable reference for similar unconventional reservoirs.

Regarding gas channeling during CO₂ flooding in high-salinity, low-permeability reservoirs, taking the H3 block of Changqing oilfield as an example, an enhanced CO₂ foam system with SiO₂ nano-particales was constructed to evaluate its salt tolerance with respect to foam rheology, gas-liquid interfacial tension, liquid film thickness and permeability, and foam microstructure. A parallel core displacement experiment was conducted for the foam system to assess its profile control performance. Based on the experimental results, a foam system of 0.20%(OW-1)+0.30%(OW-4)+0.05%(SiO₂) was developed under reservoir conditions, achieving a comprehensive index of 36,834 mL·min. The microscale salt tolerance evaluation indicates that, as compared with the foaming agents prepared at salinity of 46,357 mg/L and 500 mg/L, the developed foam system exhibits better rheological properties. The gas-liquid interfacial tension increased by only 1 mN/m at 10 MPa, and the liquid film permeability was improved by 0.14 cm/s. However, the foam system still maintains a robust skeletal structure. Thus, it is demonstrated with excellent salt tolerance at the microscale. Furthermore, for parallel cores with the permeability ratio of 15.55, the developed SiO₂ nanoparticle-enhanced CO₂ foam system improves the core profile by 97.28%, suggesting a remarkable enhancement in oil recovery, and demonstrating a good profile control performance.

In low-permeability reservoirs, CO₂ flooding can enhance oil recovery and achieve CO₂ geological storage. Based on the CO₂ storage mechanisms, by using a numerical simulation method, a CO₂ EOR and storage model considering CO₂ structural storage, residual storage, and dissolution storage mechanisms was established. This model was used to analyze the sensitivity of injection-production parameters (e.g. water injection period, CO₂ injection rate, injection-production ratio, lower limit of bottomhole flowing pressure in production wells, upper limit of bottomhole flowing pressure in injection wells, number of cycles, and gas-to-water slug ratio) on CO₂ EOR and CO₂ storage efficiency in low-permeability reservoirs under continuous gas injection and water-alternating-gas (WAG) injection modes. The results demonstrate that CO₂ storage mechanisms have significant impacts on both CO₂ EOR and CO₂ storage. Under the mode of continuous gas injection, CO₂ residual storage aids CO₂ EOR but has minimal effect on CO₂ storage, while dissolution storage hinders CO₂ EOR but benefits CO₂ storage. Under the mode of WAG injection, the storage mechanisms are less favorable for CO₂ EOR but promote CO₂ storage. These findings reveal the influences of storage mechanisms on CO₂ EOR and storage under different injection modes.

Fault-controlled karst fractured-vuggy reservoirs that are characterized by well-developed fault systems exhibit complex reservoir spaces with significant discreteness and heterogeneity, posing great challenges to fault system modeling and description. Guided by the developmental and genetic patterns of fault-controlled karst reservoirs, a multi-scale and multi-constraint geological model of fault-controlled karst reservoir was established. Depending on the genesis of fault-controlled karst, the development of these reservoirs was divided into four stages (Ⅰ-Ⅳ). Based on the reservoir model of Stage Ⅳ, the fault-controlled karst reservoirs were divided into karst cave facies, dissolution pore facies, and dissolution fracture facies. A fracture development probability cube was constructed with multiple constraints which include ant weight sampling, fault displacement model, and fracture parameter characterization, and two groups of small-scale fractures of NW-SE and NE-SW trending were generated by applying a goal-oriented simulation algorithm. A fracture model of fault-controlled karst was established to reflect the development characteristics of the fractures in fault-controlled karst to the greatest extent, for reducing the uncertainty in fracture prediction. Thus, a new method for predicting fractures in fault-controlled karst reservoirs was formed. The reliability of the proposed model has been validated by the application in two wells, which may support subsequent development research.

The low-viscosity reservoirs in the Tuha basin exhibit rapid decline of oil relatively permeability in the initial development stage and slower decline in the late development stage with high water-cut. This paper presents a new mathematical model of oil/water relative permeability. The new model simplifies the determination of parameters and offers a high fitting accuracy. It can describe the oil relative permeability curve and the convex water relative permeability curve, and also the common X-shaped oil/water two-phase relative permeability curve. For convenient application, the new model was configured with a corresponding water flooding analytical method, and then compared with the Gao’s simplified model of oil/water relative permeability. In this way, the linear relationship between the average water saturation of oil layer and the water saturation at the outlet end was further validated. By directly substituting this relationship into the fractional flow equation, a new generalized water cut variation pattern was derived. The actual application of this model shows good results, making it a valuable reference for similar reservoirs.

Based on the configuration theory and the analytic hierarchy process (AHP), the configuration shapes of the combined conventional mercury intrusion-constant rate mercury intrusion (CMI-CRMI) curves were classified, and a universal three-segment configuration pattern for the curves was established. The indicative significance of this pattern to the pore-throat systems and their wetting hysteresis was clarified. The results show that the combined CMI-CRMI curves consist of three configuration segments: a, b, and c, which are interconnected but exhibit distinct shapes. The segment a displays an overlapping shape, indicative of a macro-pore-throat system, where the combined CMI-CRMI curve shows no wetting hysteresis. The segment b demonstrates a separated shape and can be subdivided into subsegments b₁ and b₂. Subsegment b₁ indicates a meso-pore-throat system, where the CRMI intrusion curve shows no wetting hysteresis, but the CMI curve does. Subsegment b₂ also indicates a meso-pore-throat system, where the combined CMI-CRMI curve shows wetting hysteresis. The segment c exhibits an overlapping shape, representing a micro-pore-throat system, where both the CMI and CRMI curves exhibit equal wetting hysteresis. The deformation of the mercury meniscus during CMI is concentrated in the segments b and c, while the deformation of the mercury meniscus during CRMI is concentrated in the segments b₂ and c. Subsegment b₁ in both the CMI and CRMI curves can be used for contact angle correction. This three-segment configuration pattern of the combined CMI-CRMI curves provides a significant guidance for segmental contact angle correction and pore-throat distribution characterization.

Shale reservoirs contribute the most promising unconventional oil and gas resources in China and have become a hotspot in unconventional oil and gas exploration and development. Shale formations in China are mostly continental, with varying lithologies, diverse minerals, poor physical properties, strong heterogeneity, and poor continuity. These characteristics make it difficult to accurately identify lithology only using conventional logging interpretation methods, which in turn hinders the effective characterization of shale reservoirs and severely constrains reserves estimation and oil/gas development activities. In order to effectively identify the lithology of shale formations, the logging-based lithology identification technologies at home and abroad were systematically reviewed, and the lithology identification technologies based on logging interpretation and logging techniques were introduced. The logging lithology identification technologies based on machine learning were dissected in respect to their principles, advantages, disadvantages, and applicability. Finally, the prospects of logging-based lithology identification technologies for shale formations were proposed.