The medium-deep geothermal exchanger featuring a U-shaped pipe configuration presents an optimal solution for geothermal energy heat exchange due to its capability to deliver higher temperature water, achieve greater heat extraction rates, and maintain minimal flow resistance. A layered analytical model for such exchanger is established based on the theory of thermal resistance in series methods. Experimental results are employed to validate the accuracy of this layered analytical model. By focusing on the Guanzhong Basin in Shaanxi Province as the focal point of research, the model investigates the influence of subterranean stratification in thermal conductivity and volumetric specific heat on the outlet water temperature and heat extraction rate throughout an entire heating period for a 3 000 m deep geothermal exchanger with U-shaped pipe. The findings reveal that the underground thermal conductivity stratification has a significant impact on the heat transfer performance. A simplistic approach using average thermal conductivity, as opposed to a detailed accounting of layered conductivities, results in an overestimation of outlet water temperature and heat extraction rate by approximately 6 % to 15 %. However, specific heat stratification exerts minimal influence on the subterranean heat transfer dynamics. This underscores the importance of considering the effects of underground thermal property stratification in the design and analysis of the heat transfer performance of a medium-deep geothermal exchanger with U-shaped pipe. For precise modeling and results, it is recommended to segment the underground area into at least eight distinct layers.

To quantitatively assess the quality of deep hydrothermal geothermal resources in the target area, with a focus on middle-deep hydrothermal resources in sedimentary basins, a comprehensive analysis is conducted. This analysis delves into the effects of geothermal geological conditions, the nature of the geothermal resources themselves, and the quality of geothermal fluids on the overall resource quality. For this assessment, sixteen indicators that significantly impact the quality of geothermal resources are identified. These indicators are then incorporated into an Analytic Hierarchy Process（AHP） framework, which assigns weights to each indicator, facilitating a quantitative evaluation. The middle-deep hydrothermal geothermal resources are divided into three levels and seven categories. Level Ⅰ areas are resource advantage areas that can be efficiently developed; Level Ⅱ areas are resource rich areas that meet the requirements of industrial development; Level Ⅲ areas are resource non enriched areas. Ultimately, a quantifiable resource evaluation system is formed to provide data analysis conclusions on whether geothermal resources can be utilized. The relevance and practicality of this evaluation system are demonstrated through its application in a case study. The example of geothermal development and usage in the Caofeidian District of Tangshan City, Hebei Province, serves as a testament to the system's effectiveness in guiding decision-making processes for geothermal resource utilization.

Shallow geothermal energy, with applications ranging from road snow melting and deicing to building heating/cooling, primarily utilizes closed-loop vertical buried pipes for resource exploitation. These pipes function by exchanging heat with the subterranean zone under specific cooling or heating loads. Given the limited capacity of a single vertical ground heat exchanger to harness geothermal resources, arrays of these exchangers are more commonly employed to effectively tap into shallow geothermal resources. However, the underground temperature field can be significantly affected by the heat exchange process between the ground heat exchanger array and the surrounding soil. Improper design and operational conditions can lead to an imbalance in the underground temperature field, potentially resulting in energy deficiencies and the malfunctioning of Ground Source Heat Pump Systems（GSHPS）. Therefore, optimizing the design and operation scheme of ground heat exchanger array is the key to solve the imbalance of underground temperature field. The review summarizes the domestic and foreign research results, outlining various methods for energy storage and removal, incorporating auxiliary heating and cooling sources, and exploring relevant optimization techniques. The borehole array design optimization methods include primarily the distance between the pipe and the borehole layout. The energy storage/removal section mainly introduces the latest research results of borehole heat exchanger array by using external heat/cold sources such as solar energy and industrial waste heat. The auxiliary method mainly describes the latest researches on the application of resources like solar energy and heating towers. The operation control strategy mainly analyzes the operation control of the ground source heat pump system, including the peak cooling and heating load operation, intermittent operation, partition operation, system control strategy, etc. By thoroughly examining these optimization approaches and operational control strategies, the review provides a comprehensive analysis of the advantages and disadvantages of each scheme. This detailed evaluation serves as a valuable reference for improving the energy efficiency of GSHPS, ensuring sustainable and effective utilization of shallow geothermal resources.

As geothermal resource development continues to advance, addressing the challenge of sustainably and efficiently harnessing these resources becomes increasingly critical. This involves achieving a balance between the exploration and sustainable use（or "irrigation"） of geothermal resources. To this end, the application of Petrel, a geological modeling software originally designed for the petroleum industry, has been adapted for geothermal geological modeling, offering a promising solution. The adaptation of Petrel for geothermal purposes involves establishing a geospatial platform within the software to manage and analyze a wide range of geothermal geological data. This platform enables comprehensive research into geothermal geological elements by integrating diverse data sets to the fullest extent, thereby enhancing the quality and scope of geothermal geological studies. This approach involves scaling up from traditional small-scale oil and gas reservoir modeling to large-scale thermal reservoir modeling. Such a transition not only maintains the accuracy of the models but also aligns with the scale requirements unique to geothermal geology. Utilizing Petrel, models of the thermal reservoir temperature field, pressure field, and effective thermal reservoir can be constructed. This is achieved by combining various types of data and employing both deterministic and stochastic modeling techniques, thereby establishing a robust method for thermal reservoir geological modeling using Petrel. A key advantage of employing a 3D geological model for calculating effective thermal reservoir resources is its reduced sensitivity to reservoir heterogeneity. This approach more accurately reflects real subterranean conditions, providing a more reliable basis for resource evaluation. The resulting accurate 3D geological models and resource assessments lay a solid foundation for the numerical simulation of thermal reservoirs and the development of comprehensive thermal reservoir management plans. This, in turn, supports the scientific and sustainable exploitation and utilization of geothermal resources in the area, ensuring their efficient and responsible development.

Geothermal energy, as a stable and sustainable clean energy source, is set to play a crucial role in China's energy structure transformation and the realization of the “double carbon” goal in the future. The Ordos Basin, noted for its abundant geothermal resources, still holds much untapped potential due to incomplete understanding of its reserves and distribution characteristics, and the relatively low level of exploration and development. Focusing on the Changqing Oilfield and its surrounding areas, the study delves into the geothermal geological characteristics using well data. It employs the unit volume method to estimate the geothermal resource reserves and conducts zoning based on the development and utilization potential of these resources. The study reveals that the formation structure in the area is relatively straightforward, with a general geothermal gradient of 2.2~3.0 ℃/hm. The primary thermal reservoir consists of conductive Mesozoic sandstone, while other thermal reservoirs, except for Luohe Formation, exhibit poor water yield. The geothermal resources in the region are distributed with higher concentrations in the western areas and lower in the east, with a total amount of 79.91 × 10¹⁷ kJ. Among this a recoverable capacity of 6.39 × 10¹⁷ kJ, and a geothermal fluid reserve of 2.47 × 10¹² m³ have been identified Blocks such as Hongliugou-Dashuikeng-Jicun-Shancheng block, Zhanggoumen-Liuquzhen-Sanchazhen block and the block near Qingyang exhibit significant potential for geothermal resource development. Therefore, the study recommends prioritizing the redevelopment of abandoned oil and gas wells, alongside the construction of medium and deep casing heat exchange systems. This approach would facilitate the effective development and utilization of geothermal resources in these areas.

Reinjection plays a crucial role in maintaining the pressure of geothermal reservoirs, extending the lifespan of geothermal fields and preserving the environment. In the Hancheng area, located at the southeastern margin of the Ordos Basin in Shaanxi province, there is an abundance of karst geothermal resources. Despite this, the level of development and utilization of these resources in the region remains relatively limited. To further evaluate the development potential of Karst geothermal resources in the region, we implemented a karst geothermal heating project and conducting a tracer test, employing NH₄SCN as the tracer. The goal was to establish an hydraulic connection between the production well and the reinjection well. Utilizing the thermal breakthrough model, predictions were made regarding the changes in the temperature of the production well as a consequence of long-term reinjection. The findings suggest that there is a primary direct pathway for the flow of water, and possibly a secondary path that may contribute to groundwater storage. The temperature of production well's water is projected to decline by 8.31 ℃ over 100 years due to the reinjection process. However, this decline is not expected to cause a severe temperature drop in the geothermal reservoir within this dual-well system.

The Minghuazhen Formation in the Cangxian Uplift of Tianjin presents a unique challenge for geothermal resource development due to its sandstone reservoirs. These reservoirs are characterized by high shale content, suboptimal lithology, loosely cemented structures, and a tendency for sand flow, all of which complicate the process of reinjecting water back into the reservoir. This difficulty in reinjection poses a significant obstacle to the sustainable development of geothermal resources in the area. The existing well completion technology, which involves filter pipe gravel filling, is beneficial in maintaining the stability of the formation and facilitating water flow. However, improvements are needed in several aspects, including drilling diameter, drilling fluid composition, drilling assembly, and well washing processes, to enhance the effectiveness of reinjection. An optimized large-diameter gravel filling well completion technology has been developed to address these issues. This technology not only preserves the original sand retention and support functions but also increases the well completion diameter, thereby enlarging the flow area of the geothermal wells. Further, by optimizing the drilling fluid formula and drilling assembly, the contamination of the reservoir is minimized. Additionally, a combined well washing technique implemented after drilling operations helps remove plugging components from the formation, aiding in unclogging the permeation channels. Three groups of reinjection tests were carried out on two reinjection wells in Minghuazhen Formation, which were constructed by the new well completion technology. The maximum reinjection rates in the tests were 32.0 m³/h and 58.0 m³/h. Compared with the reinjection wells in the same layer, the reinjection volume increased by 3.48 times and more than 2.00 times respectively, which proved that the optimized gravel filling well completion technology of large-diameter filter pipe improved the reinjection effect effectively.

To address the challenges of test instrument obstruction and the suboptimal deployment of concentric stratified water injection in the Subei complex fracture block oilfields, an innovative approach involving the use of a hollow rod for pipe cleaning was introduced. This method focused on two key areas: the implementation of a flowback preventing water dispenser and the application of chemical sand control technology to maintain the cleanliness of the water injection pipe. In addition, a polymer gel profile control system was designed to mitigate the disparities between layers, aiming to minimize the influence of stratum grade differences on measurement and adjustment processes. This suite of supporting technologies has been applied to testing wells a total of thirteen times. The on-site tests have demonstrated that this approach is effective in preventing the obstruction of testing instruments and in simplifying the deployment process for layered water injection. Notably, the success rate of testing wells for these annual supporting measures reached 100 %, marking a significant achievement. Furthermore, the overall success rate of concentric layered water injection wells increased from 74.4 % to 84.4 %. The implementation of this method offers a dual advantage of reducing costs and enhancing efficiency, particularly in the context of optimizing fine water injection.

Underground Gas Storage（UGS） is a complex, multifaceted process with multiple stages and a long operational cycle, making it a long-term systemic endeavor. The lifecycle of gas storage encompasses various phases including site selection evaluation, scheme design, engineering construction, production and operation, optimization of operations, and eventual abandonment. The integration of these phases is crucial for the safe construction and efficient operation of gas storage facilities. Given the complexity and scope of UGS, there is a pressing need for a comprehensive system that encompasses “management decision-making, monitoring, early warning, simulation analysis, and production control” to facilitate the integrated application of the entire gas storage process. This paper specifically addresses the construction plan of Sinopec gas storage, aligning with the national mandate for “industrialization and informatization” integration. It aims to bridge the gap between management, research, and production in gas storage, addressing both managerial and technical challenges throughout the entire process of site location, design, operation, and analysis. The ultimate objective is to enhance quality and efficiency in gas storage operations. An integrated platform for UGS has been designed and developed, focusing on “production monitoring, tracking analysis, remote control, and auxiliary decision-making” as its core components. Research indicates that this platform has significantly advanced the digitalization of various aspects of gas storage, such as site optimization, geological research, injection and production control, and peak shaving optimization, across all nodes. It enables precise control over production process nodes, intelligent analysis of production and operational trends, and scientific decision-making for production and control. The research shows that the platform has realized the digital improvement of the gas storage site optimization, geological research, injection and production control, peak shaving optimization and the whole node, accurately controlled the production process nodes, intelligently analyzed the production and operation trend, scientifically made the production and control decisions, and realized the integrated management and research of the gas storage site optimization, scheme design, production and operation, and dynamic analysis.

Tahe Oilfield, known for its substantial crude oil reserves, features fracture-vuggy carbonate reservoirs with diverse and heterogeneous characteristics shaped by structural and karstic influences. Each reservoir type within this field exhibits distinct development traits, making the precise identification of these reservoir types crucial for devising effective production strategies and optimizing oil reservoir development. However, the identification of reservoirs through drilling and geophysical data is challenging and costly, hence, this paper focuses on the dynamic identification of the vuggy, fractured-vuggy, and fractured reservoirs in the buried hill carbonate reservoirs in the Yakela block of Tahe Oilfield. The research initially involved analyzing the dynamic data of the production wells in this area and dividing the development stages of each well. Subsequently, the discriminant indicators, such as the initial oil production in the elastic stage, elastic time, cumulative oil production, and production decline rate were extracted. These indicators are generally available in each well and have less human interference. They form the basis of a dynamic quantitative characterization method for determiningreservoir types Through the utilization of mathematical statistics and artificial neural network technology, an automatic identification system for carbonate reservoir types based on dynamic data was established. Remarkably, the results obtained from this method align with over 80 % of the reservoir types determined through drilling logging and geophysical data. This automated identification method proves to be highly operable and complements geological data effectively, enabling more precise reservoir determination, especially in areas where geological information is scarce. Its applicability extends to carbonate reservoir research in regions with limited data, offering reliable reservoir-type results that are essential for informed development planning.

Accurately calculating the salinity and resistivity of mixed solution in water-flooded layers is the key basis for evaluating the water-flooded condition and remaining oil saturation in middle-late development stage. This paper focuses on simulating water-flooding processes with varying salinities and measuring resistivity at the rock core scale. A novel model for calculating the resistivity of mixed solutions was developed, taking into account the efficiency of injected-water sweep and ion exchange. This model was formulated based on theoretical analysis and provides an accurate representation of the properties of reservoir mixed solutions during water-flooding. It significantly enhances the accuracy of mixed-water resistivity calculations. The established model was successfully used in H Block of Qinghai Oilfield and the calculated water saturation was consistent well with the core analysis result with the total coincidence rate reached 92.33 %. The interpreted water-flooded layers were matched well with the actual production performance, the effectiveness of the established model was validated and lays a foundation for quantitative evaluation in the water-flooded layers.

The South China Sea's natural gas hydrate reservoirs, primarily composed of clayey silt with non-diagenetic properties, undergo creep during depressurization development. The implications of this creep on key reservoir characteristics such as permeability, porosity, pressure, temperature, hydrate saturation distribution, and gas well productivity remain unclear. To address this, a combination of water seepage experiment data from clayey-silt cores and numerical simulation methods was employed to study the development of these hydrate reservoirs through depressurization-induced vertical wells. The simulation results show that the creep effects reduce the effective reservoir porosity and permeability while developing South China Sea natural gas hydrate reservoirs using a depressurization-induced vertical well. Specifically, the pressure drop is predominantly observed near the well, accompanied by a significant decrease in temperature around the well. Additionally, the reservoir creep results in a more pronounced pressure drop funnel within the reservoir. The hydrate decomposition mainly occurs at the regions of the near-well, the top of hydrate layer A, and the bottom of hydrate layer B, and the radius of hydrate decomposition is decreased by 66.7 % due to creep effects. The reservoir creep effects reduced the gas well productivity, and the cumulative production of the gas well in five years decreased by 87 %. The creep of the South China Sea natural gas hydrate reservoir dominates while the production pressure difference is greater than 4 MPa. As the production pressure difference is larger, the increasing degree of cumulative production gradually becomes smaller. A production pressure difference lower than 4 MPa is recommended for future long-term development. This study provides a reliable theoretical basis for developing South China Sea natural gas hydrate efficiently.

Peak shaving and supply guarantee are the functions of Underground Gas Storage（UGS）. The accurate prediction of the UGS construction index is related to the number of new wells and investments. When a complex fault block reservoir is transformed into UGS, it encounters three-phase flow（oil, gas, and water） during multi-cycle and high-velocity operations. The petrophysical properties of oil and gas are greatly affected by temperature. Without considering the temperature disturbance after cold gas injection and the additional pressure loss of high-velocity turbulence, the index prediction accuracy of the existing numerical simulation methods for UGS is low. To improve the accuracy of index prediction for a UGS rebuilt from a complex fault block oil reservoir, combined with fluid viscosity-temperature and high-velocity turbulence experiments, a coupled mathematical model of seepage and temperature is established. The model is solved discretely using the Finite Volume Method（FVM）, with a Two-Point Flux Approximation（TPFA） scheme for spatial discretization and a backward （implicit） Euler scheme for temporal discretization. The material balance and pressure of the reservoir and single well in the depletion development stage are matched with high precision. The sensitivity analysis of the UGS operation index is carried out in an example. The results show that the disturbance of the cold gas injection temperature field and high-velocity non-Darcy effect is the main controlling factors of accumulative oil production and gas volume error respectively. The well control temperature range increases logarithmically with the gas injection rate and the water-phase seepage capacity increases when the oil-phase and gas-phase seepage capacity decreases significantly, resulting in the increase of the produced liquid volume and the decrease of formation pressure. The additional pressure drop caused by high-velocity turbulent flow results in some injected natural gas not being produced, leading to an increase in natural gas reserves and pressure over successive cycles.

The fault-affected karst system in the north of Shuntuoguole low uplift, Tarim basin, Shunbei oilfield has obvious vertical development and heterogeneity. Due to the large vertical depth of the reservoir, the influence of gravity can not be ignored in the process of fluid flow. Considering that the reservoir is composed of small-scale fracture, large-scale cavity and large-scale channeling path, and the initial pressure at different depths varies with the depth, a large-scale fracture-vuggy well test model considering gravity is established combined with the principle of seepage mechanics and the equipotential body theory. The Laplace transform method was used to address this issue and the typical model plate and parameter sensitivity analysis plate were drawn. The results show that the fluid flow needs to overcome more resistance when gravity is taken into account, and the positions of dimensionless pressure and its derivative curves are higher in the middle and later stages. When accounting for the seepage effect in small-scale fractured reservoirs, distinct flow characteristics emerge: Linear flow in channeling paths, Transitional flow in large cavities, Quasi-steady flow in large cavities, and Radial flow in fractured reservoirs. The slope of the dimensionless pressure and its derivative curve of the former is between 0 and 0.5. The dimensionless pressure derivative curves of the latter two decrease slowly and then rise slowly. The applicability and validity of the model are further corroborated through case studies. This research not only enriches the fracture-vuggy well test model literature but also provides a solid theoretical foundation for interpreting well test data in vertical fracture-vuggy reservoirs with significant depth.

In the study of fracture conductivity evolution under stress using direct numerically generated fracture models, a key issue is the neglect of the real fracture's heterogeneous microstructure. To address this, the Brazilian splitting method is used to create fractures in various types of rocks. A 3D optical topography scanner then captures the actual fracture morphology and aperture information. This data forms the basis for establishing a contact mechanics model and a single-phase seepage model, which are used to study the evolution of the fracture flow field and permeability under continuous stress loading. The study also evaluates the applicability of traditional empirical formulas to real fracture cases. The findings are significant: ① The 25 mm×50 mm real fracture in Brazilian splitting shows obvious heterogeneity in the microstructure of the original aperture and surface roughness, which is obviously different from the fracture that reaches the average scale directly generated by numerical method. ② In the process of stress loading, the fracture aperture, contact area and spatial correlation length show different evolution characteristics in the x direction and y direction due to the fracture heterogeneity, and the control mechanism of permeability change is different; ③ When the traditional empirical formula is used to fit the stress-sensitive permeability evolution of fracture, the deviation of the fitting degree increases with the increase of the heterogeneity of fracture samples. This study suggested that the traditional empirical formula has a good application basis in the study of the fracture reaching the averaging scale, but it is limited in the application of the fracture with strong heterogeneity or failure to meet the averaging scale.

The first member of the Dainan Formation in the Qintong Sag of the Subei Basin, characterized by its shallow burial and excellent physical properties, is identified as a key exploration target for high-quality hydrocarbon reserves. This study applies basic theories and technical methods such as sequence stratigraphy, sedimentology, and geochemistry, and integrates seismic, drilling core, and logging data to conduct a comprehensive analysis of sedimentary microfacies and oil and gas accumulation conditions under the sequence stratigraphic framework of the first member of Dainan Formation in Qintong Sag. The study shows that the fan delta front facies belt is a favorable area for the development of lithologic oil reservoirs, and the sand shale interbed near the largest lake flooding surface is the optimal reservoir cap combination vertically, The formation of oil and gas reservoirs in the first member of Dainan Formation is jointly controlled by the structural background, sedimentary facies belts, and regional strike slip structural belts. The study categorizes the oil reservoirs into two major categories and five subcategories. After drilling, it has been confirmed that large-scale integrated structural lithologic oil reservoirs have been discovered, and the exploration results are significant.

For designing effective injection and production well spacing in low permeability reservoirs, it's essential to consider the pressure-sensitive effects arising from various pressure changes during the operation of injection and production wells, along with the impact of changes in the start-up pressure gradient. This study builds upon the basic seepage laws of low-permeability reservoirs to establish a seepage equation that incorporates the effects of the starting pressure gradient and pressure sensitivity. Utilizing the stable successive substitution method, the study examines the pressure distribution and the mechanism of reserve production under typical injection-production patterns. Based on the different requirements of the daily output of oil wells in an actual oil fields, a method for solving the effective injection-production well spacing of low-permeability pressure sensitive reservoir is determined. The study shows that, using the pressure sensitivity of the injection and production well area as a benchmark, there is a notable difference in the calculated results for well spacing when compared with scenarios where pressure sensitivity is either not considered or only considered for the production well area. Specifically, these differences are +9.8 % and -20.6 % under the same conditions. Considering the production limit requirements, the effective injection-production well spacing is about 0.7 ~ 0.9 times of the limit injection-production well spacing under normal conditions, which can better guide the reasonable deployment of the development well pattern of low permeability pressure sensitive reservoirs.