Artificial Fracture Research Articles

Hydrothermal evolution analysis and performance optimization in multi-well fractured reservoirs for enhanced geothermal systems

The successful development of Enhanced Geothermal Systems relies on constructing high-quality fracture networks. However, the mechanism of hydrothermal evolution in geothermal reservoirs with artificial fracture networks remains poorly understood. This study aims to elucidate the mechanism of hydrothermal evolution in fractured reservoirs to optimize geothermal energy extraction. Novel metrics, namely reservoir heating efficiency and reservoir flow efficiency, were introduced to assess performance. The study comparatively investigated six fracture structures and evaluated their impact on system production. Key findings reveal that fluid flow in multiple horizontal wells fractures reservoirs efficiently, with heat effectively extracted from the edges of the Stimulated Reservoir Volume. Enhanced reservoir heating efficiency and optimized flow efficiency were achieved due to improved heat exchange and fluid diversion. Optimal hydrothermal evolution was realized with a reservoir heating efficiency of 0.2022 and a reservoir flow efficiency of 0.2398, using a configuration of a 0° rotation angle, 30 kg/s injection mass flow, 60 °C injection temperature, 3.12 mm hydraulic fracture aperture, and 200 m production well spacing. These findings provide valuable insights into reservoir design and production strategies for Enhanced Geothermal System.

Fasudil Alleviates Postoperative Neurocognitive Disorders in Mice by Downregulating the Surface Expression of α5GABAAR in Hippocampus.

Postoperative neurocognitive disorder (PND) refers to the cognitive impairment experienced by patients after surgery. As a target of sevoflurane, a kind of inhalation anesthetic, the balance of the GABAergic system can be disrupted during the perioperative period. In this study, we explored the promoting effect of abnormal elevation of the α5 subtype of γ-aminobutyric acid type A (GABAA) receptors caused by sevoflurane and surgical trauma on PND, as well as the therapeutic effect of fasudil on PND. Eight-week-old mice were pretreated with fasudil, and after 10 days, sevoflurane-induced femoral fracture surgery was performed to establish an animal model of PND. The Morris water maze and fear conditioning tests were used to evaluate PND induced by this model. Biochemical and electrophysiological analyses were conducted to assess the protective effect of fasudil on the GABAergic system. Following artificial fracture, the hippocampus-dependent memory was damaged in these mice. Fasudil pretreatment, however, ameliorated cognitive function impairment in mice induced by sevoflurane and surgery. Mechanistically, fasudil was found to restore the increased hippocampus expression and function of α5GABAARs in mice with PND. In addition, pretreatment with Fasudil inhibited the enhancement in the calcium ion concentration and phosphorylation of Camk2, as well as the activation of the Radixin pathway which led to increased phosphorylation of the ERM family in the hippocampal CA1 region of the PND model. Preadministration of fasudil improved postoperative cognitive function in PND mice by inhibiting the activation of Camk2 and Radixin pathways and finally downregulating the surface expression of α5GABAAR in hippocampus neurons.

Study on the Migration Mechanism of Temporary Plugging Agent in Artificial Fractures of Deep Geothermal Reservoirs Based on the Euler-Euler Multiphase Flow Model

The successful use of temporary plugging diverting fracturing technology requires an understanding of the migration and plugging processes of temporary plugging agents into artificial fractures under high temperature settings. In this study, a multiphase flow model for the migration of temporary plugging agents in artificial fractures was developed using the Euler-Euler framework, and numerical simulations were conducted at elevated temperatures. Various factors, including plugging agent injection velocity, concentration, carrying fluid viscosity, wall temperature, and fracture width, were systematically analyzed to assess their impact on the agent’s migration behavior. Detailed analyses, using cloud diagrams of particle volume fraction, velocity, and turbulence intensity, clarified the underlying mechanisms influencing the migration process. The results indicate that as the injection velocity increases, the height of blockages near the wellbore decreases, while the blockage length initially increases before declining. Increasing the concentration of the plugging agent leads to a rise in blockage height and a shift in the front edge toward the injection point. Enhancing the viscosity of the carrying fluid enables the plugging agent to migrate deeper into the fracture, improving deep plugging effectiveness. While changes in wall temperature have limited impact on blockage morphology, temperatures exceeding the critical threshold of 573K significantly intensify particle migration. Moreover, increasing fracture width enhances both the height and length of blockages, with the optimal plugging effect observed when the plugging agent diameter is approximately one-third of the fracture width.

Field experiments and main understanding of shale oil hydraulic fracturing

To understand the key processes of hydraulic fracturing in shale oil reservoirs, such as artificial fracture initiation and extension, proppant transportation and settlement, and the influencing factors of post-fracture production, many hydraulic fracturing field tests have been conducted in the United States. Examples include the ConocoPhillips tests and the National Hydraulic Fracturing Experiment. The results have promoted the innovation and development of fracturing technology. A good correlation exists between lithological changes and the roughness of artificial fractures. Although numerous artificial cracks are created, the number that can provide oil and gas seepage is relatively small, determined by the effectiveness of these cracks. The settlement of proppants in actual geological formations involves factors such as geology, lithology, fractures, and stress. The pressure data indicate that when the reservoir pressure drops below the bubble point pressure, the decline in production sharply increases. The key variables affecting shale oil well production include the horizontal well position, well spacing, horizontal section length, and sand addition intensity. These technologies are suitable for the adaptive process of China’s terrestrial shale oil fracturing, promoting the development and rapid increase of shale oil production.

Comparative Study on Artificial Fracture Modeling Schemes in Tight Reservoirs—For Enhancing the Production Efficiency of Tight Oil and Gas

In order to improve the reliability of the deployment of production schemes after artificial fracturing in tight reservoirs, it is urgent to carry out research on the description of fractures after artificial fracturing. In this study, taking the Chang 61 oil formation group in the Wangyao South area of Ordos Basin as an example, three different fracture modeling schemes are used to establish the geological model of fractured reservoirs, and the fitting ratios of the respective reservoir models are calculated by using the method of reservoir numerical simulation of the initial fitting, and the optimal fractured reservoir modeling scheme is screened in the end. The research area adopts three types of fracture prediction results based on FMI fracture interpretation data, seismic fracture prediction data, and rock mechanics artificial fracturing simulation data. On this basis, geological models of fractured reservoirs are established, respectively. The initial fitting of reservoir values of each geological model are compared, and the highest initial fitting rate of reservoir values is 88.44%, which is based on rock mechanics artificial fracturing simulation data. However, the initial fitting rate of the reservoir model was the lowest at 75.76%, which was established based on the fracture random modeling results of FMl fracture interpretation data. Under the constraints of seismic geostress prediction results and microseismic monitoring data, the simulation results of rock mechanics artificial fracturing fracture are used as the basis, on which the geological model of artificially fractured reservoirs is thus established, and this scheme can more realistically characterize the characteristics of fractured reservoirs after artificial fracturing in the study area.

Numerical modelling of energy storage using hydraulic fracturing in shale formations

In order to further expand the development of renewable energy, achieve low-carbon environmental protection, and promote the transformation of the oil and gas industry, this study introduces a new energy storage method: store energy by creating artificial fractures in shale formations. A fully coupled hydraulic fracturing numerical model is established to investigate the impact of various factors (Such as operational parameters, wellbore configurations, geological conditions, etc.) on energy storage capacity and energy storage efficiency. This study demonstrates that the energy storage efficiency is extremely sensitive to injection/flow-back rate and perforation number/diameter. Reducing the injection/flow-back rate or increasing the number/diameter of perforations can substantially improve energy storage efficiency. In general, deeper storage formation leads to higher energy storage capacity and higher energy output power. For abandoned shale wells, injection, and flow-back water have negligible impact on the transport of settled proppants. The proppant bank accumulated at the bottom of existing hydraulic fracture of depleted shale wells reduces effective fracture height, resulting in a reduction of maximum energy storage. Injecting high-viscosity fracturing fluid and flow-back can recover a portion of settled proppants and mitigate the adverse effect of proppants on energy storage.

Key Technologies for Volume Fracturing of Yingxiongling Shale Oil in the Qaidam Basi

Abstract The Yingxiongling shale oil in the Qaidam Basin is the preferred choice for Qinghai Oilfield to enter the field of unconventional oil and gas resources, and volume fracturing is the core technology for shale oil exploration and development. Through the analysis of the geological and engineering characteristics of the Yingxiongling shale oil, it is found that there are difficulties in volume fracturing of the Yingxiongling shale oil, such as frequent changes in vertical mechanical properties and limited vertical control range; large stress differences, making it difficult to form complex artificial fractures; difficulty in opening multiple clusters of perforation holes; high water shortage in the plateau, high mineralization of the formation backflow fluid, and difficulty in reusing the backflow fluid. By iteratively modeling three-dimensional geomechanics, a high-resolution three-dimensional geomechanical model is established to guide the optimization of volume fracturing schemes. Through the integration of geological and engineering selection and clustering, three-stage active control technology for cracks, and the dual temporary plugging process of boreholes and cracks, the targeted and complex degree of artificial crack transformation can be improved. Through the study of high salinity fracturing fluid system, it has been found that high salinity backflow fluid can replace slick water and alleviate the demand for fresh water in volume fracturing. The article analyzes the difficulties of shale oil volume fracturing and studies the formation of an effective set of key techniques for volume fracturing, achieving the goal of improving the degree and effectiveness of transformation, and providing support for the exploration and development of the Yingxiongling shale oil in the Qaidam Basin.

The impact of spatiotemporal variation of composite conductivity in carbonate reservoirs on well production after fracturing

Composite technology of hydraulic and acid fracturing for carbonate reservoirs has been conducted in the Taiyuan formation of Changqing Oilfield and has achieved good production effects. However, in long-term production, the fracture flow conductivity will inevitably decrease, which will affect the overall production capacity. Therefore, it is necessary to conduct simulation work to clarify the fracture conductivity and production decline law under the composite technology of hydraulic and acid fracturing. The general discrete element method involves unstructured refinement of the mesh around the fracture, which can improve simulation accuracy but also increase computational workload and difficulty. Based on the above situation, we used the EDFM (Embedded Discrete Fracture Model) method to simulate the production of carbonate reservoirs containing artificial fractures. The results show that there is a spatiotemporal decrease in composite conductivity formed by the composite technology of hydraulic and acid fracturing, whether it is the main or branch fractures. The decrease in fracture conductivity has a significant impact on production. The more proppant is filled in the branch fracture, the greater the production of the gas well. Therefore, in actual production, filling some small particle size proppants in the branch fracture can improve the yield increase effect.

Geological Conditions of Shale Gas Accumulation in Coal Measures

The shale of different potential layers is studied by using rock pyrolysis analysis, total organic carbon determination (TOC), kerogen microscopic component identification, mineral X-ray diffraction, scanning electron microscopy, and low-temperature nitrogen adsorption experiments. The results are as follows: (1) Shishui Formation of the Lower Carboniferous and Longtan Formation of the Upper Permian are the two most important shale gas reservoirs in the Chenlei Depression. The sedimentary environment of the target shale is a marine land interaction facies coastal bay lagoon swamp sedimentary system. Two sedimentary facies of tidal flat facies, subtidal zone, and lagoon swamp facies are developed. (2) The organic matter types of shale are Type III and II2, with TOC content greater than 1%. The maturity of shale samples is relatively higher (Ro,max is above 2%), which means they have entered the stage of large-scale gas generation. The overall brittle mineral content of the target shale sample is relatively higher (above 40%), which is conducive to artificial fracturing and fracture formation in the later stage, while an appropriate amount of clay minerals (generally stable at 40%) is conducive to gas adsorption. (3) The overall pore structure of the water measurement group and Longtan group is good, with a higher specific surface area and total pore volume (average specific surface area is 12.21 and 8.36 m2/g, respectively), which is conducive to the occurrence of shale gas and has good adsorption and storage potential. The gas content of the water measurement group and the Longtan Formation varies from 0.42 to 5 cm3/g, with an average of 2.1 cm3/g. It indicates that the water measurement group and the Longtan Formation shale gas in the study area have good resource potential.

Anisotropy of surface morphology of carbonate rocks after reaction with acid

In acid fracturing, acid is injected into artificial fracture to dissolve the rock, and the rock surface is shaped into the non-uniform morphology. This non-uniform morphology is the main cause of fracture conductivity after acid etching. The effects of acid type, flow rate, contact time and rock type on the non-uniform morphology of acid-etched rock surface have been studied. However, when the direction of acid flow is determined, the difference of dissolution characteristics in different directions of rock surface is not investigated. In this paper, acid rock reaction experiment and analysis of rock surface morphology after acid etching are carried out by using rock samples with flat surface. The difference of morphological characteristic parameters of rock surface in different directions under the condition of acid flow is discussed. It was found that the mean drop height, drop height range and roughness coefficient increase with the increase of acid rock reaction rate on flat rock surface. The morphological characteristic parameters of acid-etched rock face of limestone are greater than those of dolomite, which is conducive to forming acid-etched channels. According to the statistics of all experimental data, the larger average drop height of rock surface is distributed in the direction of parallel acid flow, the larger drop height range is distributed in the direction of vertical acid flow and other directions, and the larger roughness coefficient is distributed in other directions.

Temporal evolution of fracture transport properties of fractured shales during long-term stress compaction

Understanding the temporal evolution of fracture transport properties in shales is of increasing importance for the long-term safe operation of many underground engineering projects. Here, a series of long-term (60 days each) water seepage and gas breakthrough experiments utilizing three shale samples, each with a single artificial fracture, was conducted to evaluate the time-dependent evolution of permeability and gas breakthrough pressure (GBP) under constant confining stress. Our results show continuous decreases in permeability and increases in GBP with time, and the rate of change in both is initially rapid but then slows. As the loading time increases, the permeabilities and GBPs become relatively constant. The inferred mechanisms are aperture reductions caused by mechanical creep and clay swelling of fractures. Pretest and posttest scans of fracture surfaces reveal some changes in asperity height, which demonstrates the occurrence of mechanical damage to the fracture during the experiments. Long-term stress compaction causes flow channels to narrow or even partially close over time. The fluid flow in confined fracture is controlled by some narrow apertures in the flow channels, which act as bottleneck points. The apertures at these points decrease to the micro-nano level under stress, significantly reducing fracture transport properties. While the fracture transport properties of fractured shale obviously decrease during long-term stress compaction, residual fracture voids still dominate the fluid flow over a longer period, and are especially prone to gas escape.

The Formation and Pressure-Bearing Characteristics of Plugging Layers in Hydraulic Fracture: A Visualization Experimental Study

Summary Temporary plugging and diversion fracturing (TPDF) is an important means for improving the artificial fracture complexity in shale gas reservoirs. At present, most scholars’ studies on TPDF mainly focus on the formation conditions of the plugging layer in a horizontal fracture and the fracture propagation behavior after the plugging layer is formed. However, there is a lack of thorough study on the formation and pressure-bearing characteristics of the plugging layer in vertical fracture. For this paper, we conducted a plugging experiment using temporary plugging particles in a hydraulic fracture by use of a visualization hydraulic fracture experimental device to analyze the formation and pressure-bearing characteristics of plugging layers. The research results show that (1) when the ratio of temporary plugging particle diameter to fracture width (d/w) becomes larger, the fluid viscosity and injection rate have less influence on the formation of the plugging layer, and the concentration of temporary plugging particles required to form the plugging layer decreases. When d/w is equal to 0.45, the plugging layer has difficulty forming if the fluid viscosity is greater than 3 mPa·s or the mass concentration of temporary plugging particles is less than 20 kg/m3. If d/w is equal to 0.60, the plugging layer has difficulty forming when the concentration is less than 10 kg/m3. When d/w is equal to 0.75, a plugging layer forms when the concentration is 2.5 kg/m3, and the formation is not affected by the fluid viscosity and injection rate. (2) A smaller d/w, higher carrier fluid viscosity and injection rate, or lower temporary plugging particle concentration all lead to more pronounced fluctuation of the fracture flow channels at the location where the plugging layer is formed. (3) If the plugging layer can form, it is denser and has stronger plugging ability when the temporary plugging particle diameter is smaller and fluid viscosity and injection rate are larger. (4) Due to different lengths and d/w, the plugging layer can be divided into three types according to its morphological change characteristics after pressure-bearing: failure-unstable, locally-damaged, and stable-unchanged plugging layer. To improve the probability of forming the plugging layer with higher stability, the fluid with a viscosity of 3 mPa·s, in which is a temporary plugging particle with a d/w of 0.75, is recommended to plug the hydraulic fractures under an injection rate of 0.65 m3/min.

Convective Heat Transfer Analysis of Supercritical CO2 in Artificial Rock Fractures

Geothermal energy has emerged as a promising renewable and sustainable resource. This research article explores the utilization of supercritical CO2 and convective heat transfer in porous rock to enhance geothermal extraction. Artificial cement rock with a smooth and manmade slotted surface fracture was used as a working sample for heat transfer source in the test. Heat transfer characteristics under various flow rates, fluid inlet temperature and pressure, rock initial temperature are analyzed. The results indicate that the geometry characteristics of fracture surface impact the overall heat transfer intensity to a certain extent, whereas lithology has little influence on the heat transfer intensity. In addition, it is found that increasing injection pressure affects the operating temperature and density of the injected fluid, which helps to improve the production effect, to obtain more heat. However, limited by the heat transfer area, low injection flow is required. The maximum error of the heat transfer coefficient model is 7.05% compared with the empirical value and less than 10% compared with the experimental results. By examining the interaction between fluid and porous fractures, we aim to provide insights into the potential of these techniques for maximizing energy efficiency and tapping into deep geothermal resources.

A Study on Three-Dimensional Multi-Cluster Fracturing Simulation under the Influence of Natural Fractures

Multi-cluster fracturing has emerged as an effective technique for enhancing the productivity of deep shale reservoirs. The presence of natural bedding planes in these reservoirs plays a significant role in shaping the evolution and development of multi-cluster hydraulic fractures. Therefore, conducting detailed research on the propagation mechanisms of multi-cluster hydraulic fractures in deep shale formations is crucial for optimizing reservoir transformation efficiency and achieving effective development outcomes. This study employs the finite discrete element method (FDEM) to construct a comprehensive three-dimensional simulation model of multi-cluster fracturing, considering the number of natural fractures present and the geo-mechanical characteristics of a target block. The propagation of hydraulic fractures is investigated in response to the number of natural fractures and the design of the multi-cluster fracturing operations. The simulation results show that, consistent with previous research on fracturing in shale oil and gas reservoirs, an increase in the number of fracturing clusters and natural fractures leads to a larger total area covered by artificial fractures and the development of more intricate fracture patterns. Furthermore, the present study highlights that an escalation in the number of fracturing clusters results in a notable reduction in the balanced expansion of the double wings of the main fracture within the reservoir. Instead, the effects of natural fractures, geo-stress, and other factors contribute to enhanced phenomena such as single-wing expansion, bifurcation, and the bending of different main fractures, facilitating the creation of complex artificial fracture networks. It is important to note that the presence of natural fractures can also significantly alter the failure mode of artificial fractures, potentially resulting in the formation of small opening shear fractures that necessitate careful evaluation of the overall renovation impact. Moreover, this study demonstrates that even in comparison to single-cluster fracturing, the presence of 40 natural main fractures in the region can lead to the development of multiple branching main fractures. This finding underscores the importance of considering natural fractures in deep reservoir fracturing operations. In conclusion, the findings of this study offer valuable insights for optimizing deep reservoir fracturing processes in scenarios where natural fractures play a vital role in shaping fracture development.

ANALYSIS OF OIL RESERVES PRODUCTION AT THE BP8 DEVELOPMENT OBJECT OF THE TARASOVSKOYE OIL AND GAS CONDENSATE FIELD

Based on the example of the analysis of the development of the oil facility BP8 of the Tarasovskoye oil and gas condensate field, geological and technological factors that can cause a low current oil recovery factor with a high water cut of the product are considered. It is assumed that: 1) the low waterflood coverage coefficient is associated with artificial fracturing at the initial stage of development which led to a change in the type of reservoir from primary pore to porous-fractured; 2) a decrease in the displacement coverage coefficient is associated with the permeability heterogeneity of the object; 3) swelling of clay particles under the influence of injected fresh water led to a decrease in the displacement coefficient. An analysis of the development of the facility shows that without the use of new effective technological solutions for involving in the development of capillary-pinched oil reserves of the porous-fractured reservoir of the BP8 object, the final technological oil recovery factor will not exceed 0.240 instead of the approved 0.425. To increase development efficiency, it is recommended to carry out pilot work on drilling horizontal wells with multi-stage hydraulic fracturing, equipped with inflow control devices based on intelligent inflow indicators.

Numerical simulation study on propagation mechanism of fractures in tight oil vertical wells with multi-stage temporary plugging at the fracture mouth

The multi-stage temporary plugging and diverting fracturing technique stands as a pivotal method for enhancing production in tight oil reservoirs. At present, fracture propagation models in temporary plugging and diverting fracturing primarily focus on single-stage temporary plugging, disregarding intricate mechanisms influenced by multi-stage temporary plugging and inter-fracture interference on the redirection and propagation of artificial fractures. To address this gap, this study employs the extended finite element method and establishes a mechanical model for the propagation of multi-stage temporary plugging fractures in tight oil reservoirs based on the maximum circumferential stress criterion. Relevant numerical simulations are conducted, considering key factors such as horizontal stress differences, fracturing fluid viscosity, injection rate, and initial fracture angle, all of which influence the morphology of diversion fracture propagation. The study rigorously analyzes and compares characteristics such as the radius of diversion fractures, diversion angle, and fracture width profile corresponding to different numbers of temporary plugging stages. Numerical simulations reveal that the primary controlling factor influencing the extension of fractures is the horizontal stress difference. A smaller horizontal stress difference makes fracture diversion easier, resulting in larger redirection radii. The impact of fracturing fluid viscosity on the diversion radius and diversion angle of fractures can be deemed negligible. Larger injection rates during construction facilitate easier diversion, leading to larger diversion radii. Furthermore, when the initial fracture angle exceeds 90°, the diversion radius of fractures is significantly larger compared to cases where the initial fracture angle is less than 90°, indicating a more facile diversion of fractures.

Assessing hydraulic fracturing feasibility in marine hydrate reservoirs: Impact of closure pressure and hydrate decomposition on fracture conductivity

Hydraulic fracturing is a potentially promising technology for stimulating gas production and improving energy efficiency in low-permeability hydrate reservoirs. However, marine hydrate reservoirs, with weak cementation, unconsolidated nature, low mechanical strength, and the potential for decreased strength and fines migration resulting from hydrate decomposition, pose significant challenges for effective fracture propping and maintaining high conductivity. To assess hydraulic fracturing feasibility in marine hydrate reservoirs, we conducted experiments to investigate the impact of closure pressure, hydrate saturation, and hydrate decomposition mode on fracture conductivity, with a particular focus on understanding the propping mechanism and identifying potential sources of conductivity damage in artificial fractures. The results demonstrated that the conductivity of propped fractures within hydrate-bearing clayey silt sediments linearly decreased with increasing closure pressure, primarily due to proppant compaction and embedding. The conductivity disparity under different hydrate saturation levels decreasesd and became similar at 16 MPa closure pressure. The decomposition mode of hydrates had a significant impact on fracture conductivity damage, with higher degree of damage observed with increasing depressurization range (up to 90.3% at a 3.0 MPa range), whereas slow decomposition induced by heating only resulted in minor decreases in fracture conductivity (damage degree: 6.6%), primarily attributed to the migration of fine particles during gas-water production. Proppant embedding and fines migration were the main causes of fracture conductivity damage in hydrate reservoirs. Proppant embedding damage occurred at higher closure pressures or slow hydrate decomposition, while fines migration damage occurred with rapid hydrate decomposition. In proppant-filled propped fractures, fines migration posed a greater risk to fracture conductivity than proppant embedding, as the migration of fine particles can block the pore spaces within the proppant-filled fractures, leading to a significant reduction in conductivity. Therefore, it was recommended to induce hydrate decomposition by slowly reducing pressure during production to minimize fines migration damage to fracture conductivity. These research findings hold significant importance in the application of hydraulic fracturing during field tests conducted on hydrate reservoirs, as they assist in optimizing the propping mode of fractures and ensuring the effectiveness and prolonged success of fracturing stimulation.

Probabilistic analysis of seepage and temperature fields in geothermal extraction process based on discrete fracture network (DFN) model

Enhanced geothermal system is currently the most efficient technology of exploiting geothermal energy from high-temperature rock reservior in deep earth. However, due to the uncertainty of geological structural discontinuities, such as natural or artificial fractures, great challenges are encountered in conducting the precise evaluation of heat extraction within enhanced geothermal system. In this paper, a probability analysis is carried out to incorporate the uncertainty of the fracture network into the analysis of the spatial-time evolution on the seepage and temperature fields, based on a discrete fracture network based modeling scheme developed by the authors. The developed finite element model of the fractured reservior exhibits two-phase structure consisting of rock matrix and fractures, which are practically discretized into triangular elements and zero-thickness elements, respectively. The approach demonstrates a favorable comparison with the results obtained from the thereotical and other numerical solution. Monte Carlo simulation technique is then employed to probabilistically analyze the evolution of coupled thermal–hydraulic behavior, which involves 1000 different realizations considering the uncertainty of fracture structure. The results illustrate that the coefficient of variation of the seepage field decreases from 0 to 0.29 at 1 a to 0.06 to 0.15 at 50 a, averaging at 0.07, and the peak coefficient of variation of the temperature field decreases from 0.61 to 0.52, averaging at 0.27. The uncertainty of the temperature field is varying against time and prominent around the proximity to the advancing cold front, upper and lower boundaries, primarily associated with variations in fractures and constraint of boundary conditions. The existence of highly permeable fractures leads to a pronounced heterogeneity in the seepage and temperature fields within enhanced geothermal system. Furthermore, the importance of taking the uncertainty of the fracture structure into account for geothermal reservoir evaluation is highlighted, to enhance the reliability of numerical modeling for geothermal process prediction.

Fracture propagation law of temporary plugging and diversion fracturing in shale reservoirs under completion experiments of horizontal well with multi-cluster sand jetting perforation

This study conducted temporary plugging and diversion fracturing (TPDF) experiments using a true triaxial fracturing simulation system within a laboratory setting that replicated a lab-based horizontal well completion with multi-cluster sand jetting perforation. The effects of temporary plugging agent (TPA) particle size, TPA concentration, single-cluster perforation number and cluster number on plugging pressure, multi-fracture diversion pattern and distribution of TPAs were investigated. A combination of TPAs with small particle sizes within the fracture and large particle sizes within the segment is conducive to increasing the plugging pressure and promoting the diversion of multi-fractures. The addition of fibers can quickly achieve ultra-high pressure, but it may lead to longitudinal fractures extending along the wellbore. The temporary plugging peak pressure increases with an increase in the concentration of the TPA, reaching a peak at a certain concentration, and further increases do not significantly improve the temporary plugging peak pressure. The breaking pressure and temporary plugging peak pressure show a decreasing trend with an increase in single-cluster perforation number. A lower number of single-cluster perforations is beneficial for increasing the breaking pressure and temporary plugging peak pressure, and it has a more significant control on the propagation of multi-cluster fractures. A lower number of clusters is not conducive to increasing the total number and complexity of artificial fractures, while a higher number of clusters makes it difficult to achieve effective plugging. The TPAs within the fracture is mainly concentrated in the complex fracture areas, especially at the intersections of fractures. Meanwhile, the TPAs within the segment are primarily distributed near the perforation cluster apertures which initiated complex fractures.

Experimental study on acid etching mechanism of acid fracturing in carbonate reservoirs

Acid fracturing is one of the most effective methods to enhance oil and gas production in carbonate reservoirs. The effect of acid fracturing is mainly affected by the conductivity, which is controlled by the acid-etched morphology of the fracture face and near-wellbore zone. Currently, the acid etching mechanism of the fracture face and near-wellbore zone is not considered in traditional experiments. The flow and reaction of acid in the fracture are simulated by using the cores with processed artificial fracture and the high-temperature acid-resistant experimental setup based on traditional experiments. The results under different conditions are obtained. The fracture face and inlet end face of cores are analyzed by combining the dissolution rate, reaction rate, average etching depth, and standard deviation. The effects of the lithology, pump rate, thickening agent concentration, and acid concentration on the acid etching mechanism of acid fracturing in carbonate reservoirs are investigated.