The energy harvesting D2D-enabled cellular network (EH-DCN) has emerged as a promising approach to address the issues of energy supply and spectrum utilization. Most of existing works mainly focus on the throughput, while the information freshness, which is critical to the time-sensitive applications, has been rarely explored. Considering above facts, we aim to develop an optimal mode selection and resource allocation (MSRA) policy that maximizes the long-term overall throughput of a time-varying dynamic EH-DCN, subject to an age of information (AoI) constraint. As the MSRA policy involves both continuous variables (i.e., bandwidth, power, and time allocations) and discrete variables (i.e., mode selection and channel allocation), the optimization problem is proved to be nonconvex and NP-hard. To solve the nonconvex NP-hard problem, we exploit a deep reinforcement learning (DRL) approach, called MSRA twin delayed deep deterministic policy gradient (MSRA-TD3). The MSRA-TD3 employs a double critic network structure to better fit the reward function, and could effectively mitigate the overestimation of Q-value in deep deterministic policy gradient (DDPG), which is a classical DRL algorithm. It is worth noting that in the design of the MSRA-TD3, we use the throughput of user equipments (UEs) at the previous time slot as a state to bypass the channel state information estimation resulting from the time-varying dynamic environment, and take the weights of throughput and AoI penalty into the reward function to evaluate two performance. Simulations demonstrate that the established MSRA-TD3 algorithm achieves better performance in terms of throughput and AoI than comparison DRL algorithms.

In order to evaluate the displacement effect of four kinds of injection media in tight oil sandstone, water, active water, CO₂, N₂ flooding experiments were carried out in laboratory. Online Nuclear Magnetic Resonance (NMR) spectrometers combine the advantages of NMR technology and core displacement experiments. In the displacement experiment, NMR data of different injection volumes were obtained and magnetic resonance imaging (MRI) was carried out. The results showed that micro and sub-micropores provided 62–97% of the produced crude oil. The enhanced oil recovery ratio of active water flooding was higher than that of conventional water flooding up to 10%. The recovery ratio of gas flooding in micro and sub-micropores was 60–70% higher than that of water flooding. The recovery ratio of CO₂ flooding was 10% higher than that of N₂ flooding. The remaining oil was mainly distributed in pores larger than 0.1 μm. Under the same permeability level, the remaining oil saturation of cores after gas flooding was 10–25% lower than water flooding. From MRI images, the displacement effects from good to bad were as follows: CO₂ flooding, N₂ flooding, active water flooding, and conventional water flooding.

Hydraulic fracturing is an effective way to exploit hydrocarbons in tight oil reservoir. The success of this technique lies on the creation of high conductivity channels for the oil and gas. Quantitative analysis of factors influencing the conductivity of propped fractures is significant for the design of the operation schedule. According to the definition of sphericity, cylindrical and planar proppants of different sphericity and sizes were presented. And disordered packs of nonspherical proppants in fractures of different widths were established by the discrete element method. The change of the proppant embedment and fracture width under different closure pressures were analyzed by the solid mechanics. During the fracture deformation, the pressure and velocity of the fluid flowing in fractures were simulated by Lattice‐Boltzmann method. Based on that, the effect of the proppant size, sphericity, and the fracture width on the permeability and conductivity of hydraulic fractures were investigated. The accuracy of the model was verified by the experimental data. The simulation results show that the fracture permeability and conductivity decrease with the decrease in the rock's Young's modulus, proppant size, and sphericity, and their stress sensitivity increases with the decrease in the rock's Young's modulus and the increase in the proppant size. Increasing fracture width can improve fracture conductivity more significantly than increasing fracture permeability. The permeability and conductivity of the fractures filled cylindrical proppants are higher than that of the fractures filled with planar proppants.

During the unconventional hydrocarbon development, the irregular shaping and uneven sand concentration of proppants banks in the staged multi-cluster fracturing of horizontal wells are key factors determining the fracture conductivity and post-fractured well productivity. To compensate for the limitation of small-scale sand filled core conductivity research that cannot accurately reflect the fracture conductivity at the field scale, this study used the mixture model to investigate the proppant distribution in fractures after sand carrying fluid enters the multi-cluster fractures from a horizontal well section, and divided the fractures into several regions based on different sand concentration ranges inside hydraulic fractures. The mechanical parameters and permeability of the sand embankment in each region were regressed to the entire fracture. The closure and conductivity of field-scale fractures with non-uniform sand filled were studied using elastic mechanics theory and free and porous media flow theory. Effects of fracture width and height on the conductivity of field-scale fractures were analyzed. The results indicate that reducing the fracture width, from 10 to 6 mm, and fracture height, from 12 to 6 m, can increase the proportion of fracture areas with sand concentration from 12 to 15%; Configurations of areas with different sand concentrations in fractures are irregular, and some areas without proppant filling can be closed under the closure pressure of 70 MPa, causing the surrounded sand filling areas to fail providing flowing paths; Sand banks with proppant concentration between 0 and 6% at the top part of the fracture can provide a more permeable flow channel than the bottom part during the initial closure of the fracture. While sand banks with proppant concentration between 12 and 15% at the bottom of the fracture can maintain a higher permeability than the top part when the closure pressure reaches 70 MPa; Reducing the width and height of the fracture can still maintain a larger fracture width when the closure pressure exceeds 60 MPa.

Hydraulic fracturing, slotting, and cavity creation are commonly employed techniques to enhance coalbed methane (CBM) development. To investigate the applicability of these three stimulation methods, this study proposes a mathematical method for constructing coal seams with orthogonal cleats, and integrates it with hydraulic fracturing, slotting, and cavity creation to generate three coal seam stimulation models. Considering desorption and diffusion of adsorbed gas, a coupled flow model of CBM in the coal matrix–cleat–hydraulic fracture/slot/cavity system was established. The results indicate that among the three stimulation methods, the stable production period and peak production resulting from slotting are less sensitive to cleat density, enhancing its applicability across diverse coal seams. Hydraulic fracturing yields a higher peak daily production than slotting, reaching 411 m³/d, but its stable production period is shorter, averaging 7.2 years, and its cumulative production is slightly lower than that of slotting when the cleat density is low. In coal seams with low cleat density, the stable production period and cumulative production of the cavity are inferior to those of hydraulic fracturing and slotting. However, when the cleat density is high, the production of cavity creation can reach the levels of hydraulic fracturing and slotting, with cumulative production of 78 × 10⁴ m³.