The in-situ stress distribution of Manan glutenite reservoir is highly heterogeneous，and it is urgent to establish an in-situ stress interpretation model suitable for the heterogeneous glutenite reservoir to guide the design of fracturing stages and clusters. In this paper，by conducting rock mechanics and in-situ stress experiments using downhole cores，we obtained the conversion relationship between dynamic and static mechanical parameters of the glutenite reservoir，established the combined spring in-situ stress model for Manan glutenite reservoir and determined the optimal values of key parameters. Based on the in-situ stress calculation results，an unsupervised clustering model of the horizontal principal stress difference was built for the horizontal wellbore，and the decimeter-scale horizontal principal stress difference distribution and clustering categories were obtained. With comprehensive consideration of the inter-fracture stress interference，casing collar position，bridge plug position and in-situ stress clustering results，perforation clusters in a stage were arranged where the horizontal principal stress difference is within the stage average±10%. An optimization method for horizontal well fracture placement in glutenite reservoirs was developed and a computer algorithm was coded. The results show that the in-situ stress calculation error of the combined spring model is 0.7%-1.5%；the standard deviation of the vertical stress of the reservoir is 0.45，with significant heterogeneous distribution characteristics. In-situ stress interpretation and unsupervised clustering fracturing stage/cluster optimization were carried out for a typical glutenite reservoir horizontal well in Manan block. There are 12 categories identified by in-situ stress clustering，and the optimal number of fracturing stages is 17. The perforation clusters within a stage are placed in positions with similar horizontal principal stress differences，which is expected to improve the conformity and effectiveness of fracturing stimulation.
Production of ultra-deep，high pressure，and high production gas reservoirs is often associated with severe sand production. Sand production can cause sand filling in wellbore and erosion of downhole tubing and casing strings and surface equipment，resulting in reduced gas well productivity or even well abandonment. Due to factors such as high in-situ stresses （high principal stress difference），developed fractures，and fast gas flow，it is difficult to predict sand production in ultra-deep high pressure gas wells，and the conventional sand production prediction methods for oil and gas wells presents low applicability. A high pressure，high production sandstone gas reservoir in the southern margin of Junggar Basin is taken as the research object，and the analysis of factors affecting sand production in high pressure，high production gas wells and the study of prediction methods are performed via theoretical derivation analysis，numerical simulation，etc. A prediction model for sand production critical drawdown pressure has been established for ultra-deep，high pressure casing perforated gas wells，and the model applicability evaluation has been carried out to verify its prediction accuracy. The findings of this research provide vital guidance for developing safe production schemes for the subsequent high pressure and high production gas wells in the southern margin of Junggar Basin.
Real-time monitoring of bit wear is crucial for accelerating drilling operations. However，it is challenging to measure on-site parameters that directly reflect levels of bit wear. Currently，there are few means of monitoring bit wear，and in most cases，determination of bit wear is empirically performed by technicians. Quantitatively evaluating the wear of PDC bit has always been a difficult task. The evaluation of bit wear is primarily based on rock breaking efficiency and mechanical specific energy. In this study，a model is proposed for real-time monitoring of PDC bit wear，based on a physical model to calculate mechanical specific energy. Moreover，the wavelet analysis and clustering algorithm are utilized to characterize the bit wear process. Finally，a monitoring model based on Gated Recurrent Unit （GRU） neural network is established，which maps drilling parameters to bit wear levels with 95% accuracy. The model is tested using data from Well A in Xinjiang Oilfield，which demonstrates the capability of the model to accurately estimate current bit wear levels. This model provides a solution for bit wear monitoring，aiding engineers in determining the optimal timing for bit replacement and thereby ensuring higher drilling efficiency.
The evaluation of rock drillability is of great significance in geological prospecting and drilling engineering. The traditional evaluation methods are mainly based on the core drillability testing，but due to the technical difficulties and high costs of coring，new unsupervised learning methods have become increasingly important. This study proposes a continuous formation drillability evaluation method based on well logging big data and unsupervised clustering algorithm to address this issue. Firstly，a self-organizing mapping neural network is used to cluster a large amount of well logging data and effectively extracting and classifying stratigraphic features. Then，by analyzing the penetration rate distribution of the formation corresponding to each cluster，the formation is graded by six drillability levels，thus achieving effective evaluation of the formation drillability. The core value of this study lies in utilizing big data and advanced unsupervised learning algorithms to overcome the reliance on a large number of core drillability test results in traditional methods，and deliver significantly improved evaluation performance. Through this method，the drillability classification of formations of the test well is successfully carried out，which validates the effectiveness of the method. The research results show that as the drillability level increases，the average penetration rate of the formation gradually decreases，and compared with the core test method，no notable deviation of the rock drillability level classification results is observed. This finding further confirms the importance and accuracy of this method in continuous formation drillability evaluation.
Water injection development makes the water breakthrough patterns of low-permeability bottom water reservoirs more complex，requiring further clarification and prediction to guide targeted waterflooded treatment measures. With the advantages of handling multiple regression problems and fast computation，neural network models can be used to analyze the inherent relationship between engineering geological multi-factor parameters and water breakthrough patterns and establish prediction models of the patterns. Based on the classification of water breakthrough patterns，this paper studied the main controlling factors and prediction models of water breakthrough patterns of BLC low-permeability bottom water reservoirs through grey correlation theory and neural network algorithms. The results show that the thickness of the bottom water，the number of interbeds，the length of interbeds，and the height of the water-avoiding perforation section are the main controlling factors affecting the water breakthrough patterns under water injection development of such reservoirs. Based on the main controlling factors and neural network algorithms，a prediction model of water breakthrough patterns was established. By verifying 18 test data sets，the model achieved an average prediction error of 1.4%，with good prediction accuracy. The water break through patterns of low-permeability bottom water reservoirs under water injection development can be quickly predicted through easily obtainable main controlling factors，providing a primary basis for targeted treatment of high-water-containing reservoirs.
Formation pressure is an important factor affecting the injection pressure and water absorption capacity of water injection wells，and maintaining reasonable formation pressure is the basis of stable oilfield production. In view of the oil well production reduction caused by formation pressure difference between Blocks A and B of X Oilfield，this paper evaluates the formation pressure of X Oilfield using the production indicator curve method combined with the production performance of oil and water wells，determines the reasonable formation pressure of X Oilfield，plots the relationship chart between water absorption index and formation pressure in cases of different volumes of injected water，and develops the formation pressure recovery scheme. The results show that the formation pressure of Block A is within the reasonable range，and that of Block B is relatively low，indicating that the injection well should be replenished for more injected water. Moreover，the actual water injection in the two blocks is low，and the intensity of water injection should be further improved. The presented evaluation method of oilfield water absorption capacity based on reasonable formation pressure plays an important role in guiding oilfield waterflooding development.
The MH gas reservoir in Xinjiang has been through many years of depletion recovery. In order to meet the seasonal peak demand，the depleted gas reservoir is being reconstructed into an underground gas storage （UGS）. Due to alternating gas injection-production，the reservoir is prone to sand production during the injection-production process，which impacts on the operation and stability of the UGS. In order to clarify the mechanism of sand production under the alternating injection-production mode of the UGS，this paper used the reservoir cores to carry out the physical property，rock mechanics and alternating flooding experiments. The main composition，cementation and mechanical properties of the cores were analyzed，and the effects of drawdown pressure，confining pressure and alternating injection-production process on sand production were investigated. The experiment results show that the reservoir skeleton presents dissolution sericitization，high kaolinite content in clay minerals，weak mechanical strength properties，and has the risks of sand production under the UGS operating conditions. During cyclic injection and production，an increase in drawdown pressure promotes sand production. When the drawdown pressure exceeds 6 MPa，the rock reaches a critical state of sand production. Increasing confining pressure leads to premature sand production. Moreover，as the confining pressure rises，sand production first increases and then decreases. The extrusion of pore channels is the main driver for the decrease in sand production. In comparison to conventional gas production，the amount of produced sand during the alternating injection-production exhibits a wave-like pattern. The dynamic erosion process and fatigue failure of cementation，induced by multiple rounds of alternating injection-production，are the main contributors to exaggerate sand production from the UGS.
The dynamic sealing performances of the caprock and fault are important evaluation indicators of underground gas storage （UGS） and are of great significance to the safe operation of the UGS. In view of the shortcomings of the static evaluation system of caprocks and faults for the UGS，this paper takes a carbonate gas storage in North China as an example，performs rock mechanical experiments based on well logs，and establishes the dynamic-static conversion model for rock mechanics parameters and a four-dimensional geomechanical UGS model. Based on the developed models，the initial stress field of the UGS geological body is inverted，the pressure-bearing capacity of the UGS geological body is analyzed，and the four-dimensional dynamic stress field information under the UGS injection and production conditions are obtained. Four-dimensional geomechanical calculation results show that the risk of caprock and fault failure is low under the current upper limit pressure （47 MPa）. The caprock and faults will not fail even if the upper limit pressure of the UGS is increased to 49 MPa. As per this combined with the operating capacity of the surface compressor，the upper limit operating pressure of the UGS is determined to be 49 MPa. The establishment of the four-dimensional dynamic stress field provides a scientific basis for the further pressurization and capacity expansion of the UGS.
During the production and laying of submarine oil and gas pipelines，the ovality defects of pipelines may occur，due to the influences of the UOE pipe making process and tensioner. Meanwhile，complex deep-sea service conditions tend to cause local corrosion defects in submarine pipelines. An ABAQUS finite element model is established to address the buckling and collapse of thick-wall high-strength-steel pipe with double defects under complex loading of coexisting external pressure and axial force，considering the geometric and material nonlinearity of the pipe. Based on the analysis of more than 2 400 sets of finite element simulation data incorporating different pipe materials，geometric parameters and defect geometric parameters，the variation law of collapse pressure of high-strength-steel thick-wall pipes with double defects is summarized，and the calculation method of collapse pressure of high-strength-steel thick-wall pipes with double defects is proposed. This method provides a theoretical basis for predicting the buckling load of high-strength-steel thick-wall pipeline in practical engineering projects，so as to ensure the safety of offshore oil and gas transportation.
Chemical flooding plays an important role in improving oilfield recovery. The micro-emulsion system has been widely studied and applied owing to its unique properties. In this experiment，the alcohols with carbon numbers less than five were selected as cosurfactants to optimize the performance of the micro-emulsion system. The dynamic oil displacement process，morphology and distribution of residual oil and displacement performance of micro-emulsion flooding were visualized using microfluidic technology. Firstly，the mass fractions of isopropanol and n-butanol in the cosurfactants were optimized，followed by the optimization of NaCl mass fractions. Ultimately，microscopic visual displacement experiments were conducted with the optimal micro-emulsion formulation. The results show that the optimal micro-emulsion formulation is as follows：an fixed oil-water ratio of 1∶1，5 wt% SDS，8 wt% n-butanol and 3 wt% NaCl as the optimum. The corresponding ultimate oil recovery is 98.8%，and the residual oil saturations are 0.15% and 1.05% in the high- and low- permeability zones，respectively. NaCl can change the polarity of water to reduce interfacial tension. The combination of n-butanol with surfactants and NaCl can greatly reduce interfacial tension and modify the wettability of the microfluidic chip，leading to promoted oil detachment and enhanced mobility of residual oil. Using microfluidic technology to study the in situ emulsification and dynamic displacement process of micro-emulsions provides effective theoretical guidance and technical support for efficient development of reservoir residual oil.
In addressing the problems of intermittency and instability in the conventional utilization of solar energy，this paper introduces the research progress of the photothermal technology applied in photothermal power generation and direct solar thermal utilization for stable solar heat supply by employing heat storage systems，and summarizes the classification methods and application scenarios of current heat storage technologies. This study reviews the technical principles and research progress of the mainstream molten salt heat storage systems （carbonate，chloride，fluoride and nitrate），pointing out the advantages and technical problems of different molten salt thermal storage systems. Aiming at the core of the molten salt thermal storage technology，it summarizes the research status and process flow of photothermal technology in different scenarios. This paper also generalizes the development trends of molten salt thermal storage systems in the photothermal field. First，suitable heat collection modes are selected according to application scenarios，and the capacity configuration and coordination control of solar heat collection and molten salt thermal storage are optimized. Second，molten salt with lower melting points，wider liquid temperature range，and low corrosion is developed to improve the applicability of molten salt thermal storage. Third，the operation safety and stability of the molten salt energy storage system can be ensured while costs are lowered. This provides a reference for the future application and development of the molten salt thermal storage technology.
