Fractured Reservoir Research Articles

Three-dimensional fracture space characterization and conductivity evolution analysis of induced un-propped fractures in shale gas reservoirs

Huge numbers of induced unpropped (IU) fractures are generated near propped fractures during hydraulic fracturing in shale gas reservoirs. But it is still unclear how their fracture space and conductivity evolve under in-situ conditions. This paper prepares three types of samples, namely, manually split vertical/parallel to beddings (MSV, MSP) and parallel natural fractures (NFP), to represent the varied IU fractures as well as their surface morphology. Laser scan and reconstruction demonstrate that the initial fracture spaces of MSVs and MSPs are limited as the asperities of newly created surfaces are well-matched, and the NFPs have bigger space due to inhomogeneous geological corrosion. Surface slippage and consequent asperity mismatch increase the fracture width by several times, and the increase is proportional to surface roughness. Under stressful conditions, the slipped MSVs retain the smallest residual space and conductivity due to the newly sharp asperities. Controlled by the bedding structures and clay mineral hydrations, the conductivity of MSPs decreases most after treated with a fracturing fluid. The NFPs remain the highest conductivity, benefitting from their dispersive, gentle, and strong asperities. The results reveal the diverse evolution trends of IU fractures and can provide reliable parameters for fracturing design, post-fracturing evaluation, and productivity forecasting.

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.

LNMR analysis of the retention of different guar gum structure in sandstone: Based on a new characterization method

The adsorption and retention damage of guar gum to reservoirs are important factors affecting the effectiveness of hydraulic fracturing. Accurately understanding and evaluating the adsorption and retention of guar gum can better support the research of low-damage fracturing fluid. However, previous indoor evaluation methods have some limitations in studying the adsorption and retention characteristics of guar gum. The analysis object of low-field nuclear magnetic resonance (LNMR) is water rather than guar gum, which cannot achieve visualization of guar gum retention. In addition, Ordinary guar gum (GG), hydroxypropyl guar gum (HPG), and carboxymethyl guar gum (CMG) are commonly used in the hydraulic fracturing of sandstone gas reservoirs, but there are very few studies that focus on the differences in the adsorption and retention damage of the three guar gums from a microscopic perspective. In this study, a new characterization method for evaluating the retention of polymer in fracturing fluid based on the principles and properties of LNMR was proposed. This method can quantitatively evaluate the amount of guar gum adsorption retention and achieve a visual evaluation of the adsorption and retention of guar gum in cores. The aggregation characteristics of guar gum in porous media can be reflected. The dynamic retention process of GG, HPG, and CMG in sandstone cores was directly characterized through this method. The aggregation and entanglement characteristics of the three types of guar gum in sandstone were analyzed from the structure of guar gum. The experimental results show that the difference in molecular weight and modified groups of guar gum has an impact on its adsorption and retention. The molecular chain after the gel-breaking of GG was longer due to the large molecular weight. Long chains and intramolecular hydrogen bonds caused a larger curling degree of GG molecules. The entanglement degree of guar gum increased due to the introduction of non-ionic long-chain hydroxypropyl. The introduction of anionic carboxymethyl made CMG molecules more stretched due to electrostatic repulsion. The median particle size of the gel breaking liquid of GG was 10.65 μm, HPG was 8.8 μm, and CMG was 5.88 μm. A larger molecular particle size after guar gum gel breaking would aggravate the retention in sandstone porous media. After 150 min of displacement, the adsorption and retention amount of GG in the core was 4.59 mg/g, HPG was 4.17 mg/g, and CMG was 3.86 mg/g. The compactness of aggregates formed by guar gum in the core was HPG > GG > CMG. The gas flooding can relieve the adsorption and retention of guar gum. The higher the degree of entanglement of guar gum molecules, the more difficult to remove them from the core. The flowback degree of gas flooding of GG was 10.2%, HPG was 6.8%, and CMG was 21.9%. This research provides an experimental strategy for the microscopic evaluation of polymer adsorption and retention in rock porous media. The research results provide a deep understanding of the microscopic characteristics of guar gum adsorption and retention from the perspective of guar gum structure, which has some significance for guiding the optimization of fracturing fluid and the study of low-damage fracturing fluid.

Comprehensive study of hydraulic fracturing in shale oil reservoirs comprising shale–sandstone transitions

Hydraulic fracturing technology is a crucial technique for effectively developing shale oil reservoirs. In field fracturing treatment operations, these reservoirs are often consisting of a combination of various rock types that making them complex. Therefore, this study specially focuses on the sandstone–shale layers in the G zone of the Daqingzi Well G Area in the southern part of the Songliao Basin. It aims to provide essential parameter support for subsequent theoretical and numerical research through laboratory mechanical experiments. Using the finite discrete element method, we have established four different numerical models for the hydraulic fracturing of shale oil with varying geological conditions, (including transition zones). The study reveals that when the vertical stress difference is 6 MPa, the crack height increases, and the offset distance decreases. At 8 and 10 MPa, crack propagation exhibits a “forking” phenomenon. A decrease in rock cohesion leads to increased offset distances in the transition zone, along with an increase in crack height. For type a and b transition zones, it is recommended to use a fracturing fluid with a viscosity of approximately 10 mPa s and a flow rate of 12 m3/min for fracturing. For type c transition zones, it is advisable to select fracturing fluid with a viscosity in the range of 10–30 mPa s and use a flow rate of 12 m3/min for fracturing. For the type d transition zones in the fracturing reservoir, it is recommended to use fracturing fluid with a viscosity of around 10 mPa s and a flow rate of 15 m3/min for optimal field fracturing operations.

Technology Focus: Unconventional and Tight Reservoirs (July 2024)

Unconventional reservoirs bear a unique perplexity in that, at every scale, they are different from their conventional counterparts and even one another. Small nuances in any one parameter can result in a vastly different well result, which may affect how an area, or even an entire play, is interpreted. This month’s selection of papers is all about those differences, in recognition that it is technology that drives innovation through understanding what these differences mean and how best to extract value from these vast resources. Starting at the well scale and looking at the benefits of knowing the efficacy of each stimulation stage, paper URTeC 3864145 is from the Ordos Basin in China. Investigating hydraulic fracture performance on a stage-by-stage basis proves time and time again that understanding the details can improve overall development outcomes. The case study reviews two hydraulic fracture diagnostic techniques used in combination to determine water breakthrough and shutoff plans. Zooming out to the play scale, paper SPE 216292 is focused on the most variable of unconventional reservoirs: the carbonate reservoir. This case study of the Austin Chalk formation in Texas analyses the production uplift from application of horizontal, multistage fracture stimulation technology in tight or fractured carbonate reservoirs. The application of unconventional technology in carbonate reservoirs can extended field life, and the deployment of this technology should be considered for any redevelopment or reassessment of potential resources trapped in tight carbonate reservoirs. Finally, paper OTC 34832 draws on the concept of innovation that is required to unlock unconventional resources. Novel methods of stimulation are the cornerstone of unconventional technology in that well stimulation is a basic requirement of all low-permeability reservoirs. The paper describes a trial pilot from idea through execution from Kuwait Oil Company for enhanced oil recovery in tight formations using downhole hydrogen generation from in-situ exothermic multistage chemical reactions between two unique hydroreacting agents. The paper also provides lessons learned and optimization insights from the trial, concluding that a successful, low-cost alternative stimulation technique was demonstrated and repeatable. Recommended additional reading at OnePetro: www.onepetro.org. SPE 216139 Tight Gas Reservoir Characterization and Comparison of PLT Methods: Microseismic Monitoring, Fiber-Optical Production Logging, and Tracer-Coated Sand Monitoring Applied in the Same Well by Xiao Yao, Petrochina, et al. SPE 216149 New Insight in Developing Tight Fractured Carbonate Reservoirs, Mishrif Formation, West Kuwait by M. El-Jeaan, Kuwait Oil Company, et al. SPE 215712 Successful Utilization of In-Situ Dune Sands in Saudi Arabian Unconventional Frac Operations by Nahar Qahtani, Saudi Aramco, et al.

Torricelli’s Law in Fractal Space–Time Continuum

A new formulation of Torricelli’s law in a fractal space–time continuum is developed to compute the water discharge in fractal reservoirs. Fractal Torricelli’s law is obtained by applying fractal continuum calculus concepts using local fractional differential operators. The model obtained can be used to describe the behavior of real flows, considering the losses in non-conventional reservoirs, taking into account two additional fractal parameters α and β in the spatial and temporal fractal continuum derivatives, respectively. This model is applied to the flows in reservoirs with structures of three-dimensional deterministic fractals, such as inverse Menger sponge, Sierpinski cube, and Cantor dust. The results of the level water discharge H(t) are presented as a curve series, showing the impact and influence of fluid flow in naturally fractured reservoirs that posses self-similar properties.

Appraisal of the Propping Potential of Luwa Sand in Nigeria for Hydraulic Fracturing Applications

Natural sands made of spherical and round grains are widely used as proppants during hydraulic fracturing to increase recovery rate of hydrocarbon production. Synthetic proppants with high crush strength are employed for deep reservoir fracturing; however, this type of proppants suffer the disadvantages of high density, high cost and pose environmental hazards. This research was conducted with the aim to assess sands collected from Luwa River in Toro, Bauchi state of Nigeria for possible use as natural sand proppants. An epoxy resin-coated sand was produced using a simple method to modify the sands’ properties. A series of experiments were conducted in accordance with API recommended practice to determine the propping potential of the sand and the resin coated sand. The result from sieve analysis of 20/40 mesh size of Luwa sand revealed a mean size of 625.2 microns (0.625 mm). An X-ray fluorescence (XRF) result showed the presence of aluminosilicates (Al2O3 and SiO2) composition in Luwa sands. The sands recorded a hardness of 8 on the Mohs scale. Analysis of the shape parameters for sphericity and roundness was 0.8 and 0.8 (Krumbein-Sloss) respectively; it has bulk density of 1.64 g/cm3, acid solubility of 0.7% and 4.32% for the resin-coated sand. The sand has turbidity value of 28.98 NTU, loss on ignition in the range of 1.33% to 1.64% and crush resistance varies between 2000-3000 psi for Luwa sand and 4000-5000 psi for the coated sand. A comparison of the experimental results with API standard and conventional Ottawa and Brady models showed the sand competes favourably with these standards in all parameters for consideration as a proppant except for the crush resistance where more than 10% fragments was generated at low pressure of 3000 psi. However, the sand can be applied in shallow depth reservoirs.

Appraisal of the Propping Potential of Luwa Sand in Nigeria for Hydraulic Fracturing Applications

Natural sands made of spherical and round grains are widely used as proppants during hydraulic fracturing to increase recovery rate of hydrocarbon production. Synthetic proppants with high crush strength are employed for deep reservoir fracturing; however, this type of proppants suffer the disadvantages of high density, high cost and pose environmental hazards. This research was conducted with the aim to assess sands collected from Luwa River in Toro, Bauchi state of Nigeria for possible use as natural sand proppants. An epoxy resin-coated sand was produced using a simple method to modify the sands’ properties. A series of experiments were conducted in accordance with API recommended practice to determine the propping potential of the sand and the resin coated sand. The result from sieve analysis of 20/40 mesh size of Luwa sand revealed a mean size of 625.2 microns (0.625 mm). An X-ray fluorescence (XRF) result showed the presence of aluminosilicates (Al2O3 and SiO2) composition in Luwa sands. The sands recorded a hardness of 8 on the Mohs scale. Analysis of the shape parameters for sphericity and roundness was 0.8 and 0.8 (Krumbein-Sloss) respectively; it has bulk density of 1.64 g/cm3, acid solubility of 0.7% and 4.32% for the resin-coated sand. The sand has turbidity value of 28.98 NTU, loss on ignition in the range of 1.33% to 1.64% and crush resistance varies between 2000-3000 psi for Luwa sand and 4000-5000 psi for the coated sand. A comparison of the experimental results with API standard and conventional Ottawa and Brady models showed the sand competes favourably with these standards in all parameters for consideration as a proppant except for the crush resistance where more than 10% fragments was generated at low pressure of 3000 psi. However, the sand can be applied in shallow depth reservoirs.

Oil-and-gas potential of the northeast Predpatom trough

This article discusses the geological structure and prospects of the oil and gas potential in the northeastern part of the Predpatom trough. The materials of the study included geological findings from deep drilling and data from direct geochemical studies conducted in recent years. It describes the specific features of the structural plans of the upper versus the lower part of the geological cross-section. It is assumed that deep drilling in the area of the Ulugur structure has not reached the target productive horizons in the autochthonous part of the section. After acquiring more recent seismic data, there is a proposal to drill a deeper exploratory well in the area. As another priority target for oil and gas exploration, a potential zone of Vendian clastic deposits wedging on the southwestern slope of the Suntar uplift has been identified. A forecast has been made for the distribution of lithological traps stacked with well-sorted granular Vendian reservoirs in the northern parts of the Ergedzheysky and Ulugursky license areas. In the allochthonous part of the section, the potential for oil and gas content in carbonate deposits from the Vendian and Lower Cambrian periods is highlighted in reservoirs formed by secondary processes. It is assumed that thrust deformations could lead to the circulation of aggressive solutions, resulting in the formation of secondary fractured cavernous reservoirs. Subsequently, hydrocarbon accumulations may migrate and accumulate within these reservoirs. Good gas prospects were also noted in the upper part of the section, where gas deposits were confirmed in newly discovered fields. The results of direct geochemical testing of the Ulugur and Ergedzheysky license areas are presented, enabling the preliminary delineation of promising zones and areas in the studied territory. At the same time, narrow elongated geochemical anomalies are associated with the prospects of the allochthonous part of the section, while isometric anomalies are linked to the autochthonous part of the section. The need to consolidate all available geological and geophysical information on the Pre-Atomic deflection within the framework of case studies is noted.

Underground hydrogen storage in depleted gas reservoirs with hydraulic fractures: Numerical modeling and simulation

Underground hydrogen storage (UHS) is one of the key technological solutions for balancing energy systems and promoting sustainable energy development. In this study, we propose a novel UHS method, which involves injecting hydrogen generated from electrolyzing formation water into depleted gas reservoirs through hydraulic fractures during off-peak electricity periods, and then efficiently producing hydrogen for power generation during peak electricity periods. We establish a numerical simulation model for UHS in a depleted fractured gas reservoir, covering the entire process from injecting hydrogen gas into the reservoir through wells to shutting them down and subsequently producing hydrogen when required. We then investigate the impact of hydrogen injection rate, injection duration, and shut-in duration on the UHS process and storage efficiency. Our findings reveal that hydrogen production efficiency can exceed 85 % by optimizing hydrogen injection and production strategies. Our study provides an exemplary numerical simulation scheme to evaluate the feasibility of UHS in depleted gas reservoirs with hydraulic fractures.

Detailed effects of reservoir permeability distribution differences on enhanced geothermal systems performance

In enhanced geothermal systems, fractured reservoir permeability significantly affects geothermal exploitation efficiency. However, the detailed effects are not fully understood while most previous literature ignored the spatial differences of reservoir permeability because of the complexity and heterogeneity of fracture distribution. This study aims to reveal the quantitative relationship between the geothermal system’s heat extraction performance and the distributed permeability, through investigating heat extraction ratio and flow impedance by building a 3D thermal-hydraulic coupled model with discrete fracture network. The current study also compared the effects of twenty-nine kinds of fracture network distributions at various depths. It is found that higher fracture permeability around production well (800×10−12 m2) more significantly improves heat extraction rate by 30% rather than higher permeability in other areas in the first year. It is also found that fracture permeability changes on both sides of predominant flow regions cause a lower heat extraction rate. Lower fracture permeability at bottom and top layers (25×10−12 m2) increases the heat extraction rate by 1.17 MW in the 30th year. The proppant distribution affects the pressure distribution in fractured reservoirs. Permeability distribution variation has small effects on the heat extraction ratio. These results provided theoretical basis for fractured reservoir construction, optimal proppant pumping scheme and reservoir thermal output prediction.

A dual-porosity flow-net model for simulating water-flooding in low-permeability fractured reservoirs

The physics-based data-driven flow-network models with high computational efficiency have received great attention as the promising surrogate models for reservoir numerical simulation. However, the existing flow-network models developed for water-flooding reservoirs fail to consider different seepage characteristics of matrix and fractures and cannot be straightly applied to simulate the water-flooding process in low-permeability fractured reservoirs. In this study, we combine the flow-network model with the dual-porosity model to propose a new physics-based data-driven surrogate model, namely the Dual-Porosity Flow-Network Model (Flow-Net-DP), which can consider the non-Darcy flow in tight matrix and the stress-sensitive effects and preferential flow characteristic in fractures. Specifically, we refer to the dual-porosity model and use two channels to represent the connections between wells: one indicates the fracture system, the other represents the matrix system, and the fluid exchange between these two systems is considered by using a transfer function. Besides, each channel is discretized into one-dimensional grids, and a fully implicit scheme with Newton iteration is used to calculate pressure and saturation. Moreover, we establish an automated history matching method by using the Ensemble Smoother with Multiple Data Assimilation (ESMDA) algorithm to calibrate model parameters of Flow-Net-DP, and develop a production optimization method by using the Differential Evolution (DE) algorithm. Finally, the numerical simulation, history matching, and production optimization are conducted on different numerical examples to validate the capability of Flow-Net-DP. The results indicate that the Flow-Net-DP can provide a better description of water flooding process in low-permeability fractured reservoirs compared with the existing flow-network model, especially the rapid water breakthrough caused by the preferential flow characteristic in fractures. Furthermore, both history matching and production optimization based on the Flow-Net-DP yield satisfactory outcomes. For instance, when the optimization results are similar to the full-order simulation model, the optimization speed of Flow-Net-DP is increased by more than five times.

Gas channeling control with CO2-responsive gel system in fractured low-permeability reservoirs: Enhancing oil recovery during CO2 flooding

During the CO2 flooding process in fractured low-permeability oil reservoirs, the injected CO2 is prone to channeling along fractures due to severe reservoir heterogeneity, resulting in poor development effect. The CO2-responsive gel system shows dual advantages in achieving CO2 capture and plugging gas channeling to enhance oil recovery. This paper constructed a system with good CO2 sensitivity based on long-chain alkyl amide propyl dimethyl tertiary amine first. Subsequently, the properties of the system before and after the response were evaluated through rheological test, and its microstructure was characterized by Cryo-TEM. The system exhibited good CO2 responsiveness, transitioning from low-viscosity solution system to high-viscosity CO2-responsive gel system upon contact with CO2, with its viscosity increasing by nearly five orders of magnitude. The CO2-responsive gel demonstrated excellent shear resistance, viscoelasticity and shear self-repairing ability. The change of microstructure further verified the mechanism of molecules self-assembly in the system under the action of CO2. Then, a series of core physical simulation experiments were carried out to comprehensively evaluate the effects of different factors on the injection capacity, plugging characteristics, dynamic filtration damage performance and EOR effect of CO2-responsive gel. The gel maintained injectability while achieving an exceptional deep plugging effect, and the plugging rate reached 98.77%. It showed good characteristics of low filtration and permeability damage in low permeability reservoirs, effectively ensuring the fracture plugging effect. After the fracture was plugged by gel, the sweep range of CO2 to the matrix significantly expanded, and the gas flooding recovery increased by 18.19–21.7%. Finally, the matrix-fracture dual-media chip model was used to conduct microfluidic experiment, the oil displacement characteristics in different displacement stages were visually clarified, and the synergistic plugging and oil displacement mechanism between the CO2-responsive gel and CO2 was summarized. The research results can provide important insights for the green and efficient application of CO2-responsive gel in fractured low-permeability reservoirs.

Shear wave velocity prediction for fractured limestone reservoirs based on artificial neural network

AbstractShear wave velocity is an essential parameter in reservoir characterization and evaluation, fluid identification and prestack inversion. However, conventional data‐driven or model‐driven shear wave velocity prediction methods exhibit several limitations, such as lack of training data sets, poor model generalization and weak model robustness. In this study, a model‐ and data‐driven approach is presented to facilitate the solution of these problems. We develop a theoretical rock physics model for fractured limestone reservoirs and then use the model to generate synthetic data that incorporates geological and geophysical knowledge. The synthetic data with random noise is utilized as the training data set for the artificial neural network, and a well‐trained shear wave velocity prediction model, random noise shear wave velocity prediction neural network, is established by parameter tuning, which fits the synthetic data with noise well. The neural network is applied directly to the real field area. Compared with conventional shear wave prediction methods, such as empirical formulas and the improved Xu–White model, the prediction results show that the random noise shear wave velocity prediction neural network has better prediction performance and generalization. Furthermore, the prediction results demonstrate the efficacy of the proposed approach, and the approach has the potential to perform shear wave velocity prediction in real areas where training data sets are unavailable.

Effect of proppant injection condition on fracture network structure and conductivity

AbstractThe hydraulic fracturing of shale reservoirs is an important topic, and adjusting the fracturing process can enhance fracturing efficiency. To analyze the effect of injection conditions on the fracture network structure and conductivity, numerical simulations and theoretical calculations are carried out based on the construction data, and the variation patterns of the fracture network parameters are determined. During the theory study, a fracture network conductivity model was obtained by combining the fracture network expansion model and the fracture diversion model. Then a numerical model was set up according to the analysis results of monitoring data. The numerical simulation results showed the fracture network structure and proppant distribution under different conditions. Throughout the simulation process, the structural parameters and conductivity of the fracture network can be determined by controlling the injection amount and adjusting the injection method, speed, and sand ratio. Results indicated that the proppant pulse frequency during the injection process was a major factor affecting the structure and conductivity of the fracture network. At the same time, a comparison of the distribution structure of the proppant revealed that although the intermittent injection of the proppant improved the flow channel, the efficiency of fracture utilization can still be improved.

Effects of microstructure on hydraulic fracturing and gas–water production in coal reservoirs: A case study of the Dahebian coalbed methane block in Western Guizhou, China

AbstractThe development of coalbed methane (CBM) in China is susceptible to the influence of microstructure. Therefore, it is crucial to understand the extension laws of hydraulic fractures and engineering responses in coal reservoirs affected by microstructure development. Utilizing the Dahebian block in western Guizhou as the study area, this investigation examines the coal reservoir characteristics, fracturing, and drainage engineering analysis of the well DC1 group in the region. The aim is to discuss the spatial distribution characteristics of hydraulic fractures, geological controlling factors influenced by microstructure, and their corresponding engineering responses. The results indicate that, for coal reservoirs unaffected by microstructure, the extension laws of the fracture network in both longitudinal and planar directions are influenced by burial depth and the regional stress field. In the microstructural belt, tectonic stress dominates, causing changes in the ground stress field. Consequently, the hydraulic fracture network deviates from the direction of the maximum principal stress during the extension process. When a secondary fracture is nearby, the hydraulic fracture network extends towards the shortest path radial secondary fracture direction, leading to a rapid increase in fracture width per unit length until it intersects with the secondary fracture. Additionally, the presence of secondary joints near the microfault structure decreases fracturing pressure and results in a dense distribution of the fracture network. This promotes the formation of a complex fracture network, favorable for fracturing. The extension of the fracture network in complex structural development areas is influenced by the microfault structure between wells, which is reflected in the fracturing construction pressure and fluid output. This accounts for the significant variations in the early drainage performance of CBM wells.

Modelling of water injection-induced shear stimulation and heat extraction in hot fractured reservoirs

Hydroshearing has been proposed as an effective technique for enhancing the permeability of fractured geothermal reservoirs. This approach involves complicated thermo-hydro-mechanical (THM) coupling, but the shear behaviour and its effect on flow and heat transfer are often simplified. In this study, Barton–Bandis (BB) joint behaviour is extended to include nonlinear rock joint deformation, shear dilation and post peak softening and healing behaviours. Two models of field-scale fractured geothermal reservoirs are considered. In addition, the widely used Mohr-Coulomb (MC) model is also incorporated into the THM coupled model for comparison. The results show that cold water injection-induced high-temperature rock contraction and fluid pressure increase, reducing the effective stress and promoting fracture shear deformation and irreversible slip. Moreover, shear dilation, shear softening, and nonlinear fracture opening notably alter reservoir permeability. The two models exhibit entirely different behaviours due to different pathway evolutions and consequent pressure build-up. The BB model displays a larger shear disturbance zone than the MC model, significantly enhancing the permeability and heat extraction within the fractured reservoirs. Accurate descriptions of the mechanical behaviour of rock fractures in hydroshearing models are crucial, suggesting the potential of these models to enhance fractured reservoirs and regulate fracturing for improved geothermal heat extraction.

Fracture characteristics and energy dissipation law of shale under water-based impact loads

Shale fracture and energy dissipation are the basis of reservoir fracturing effect evaluation. The damage and fracture mechanism of shale under dynamic impact load is the key scientific concern of reservoir fracturing. To study the law of fracture, fracture propagation and energy dissipation of shale under dynamic impact, dynamic tests of water-based impact load under different impact velocities were carried out using impact rock breaking test platform based on air cannon. Topological and fractal theory, Weibull distribution model, space vector geometry method and Griffith fracture mechanics theory were used to systematically study the effects of impact velocity on fracture development and expansion, fragment mass and size distribution, damage degree of abutment residual and energy dissipation transformation. Scanning electron microscopy (SEM) was used to observe the micromorphology of the impact fracture surface. The results demonstrated that an increase in impact velocity led to the formation of a network fracture featuring main fractures, cavity fissure, bedding fractures, and crushing zones, thereby enhancing the fracture’s capability to penetrate bedding. The apparent fracture network connectivity, topology structure and fractal dimension were positively correlated with impact velocity. The residual height of the shale decreased, resulting in an escalation of the damage degree from mild (0.43) to severe (0.75), while the average penetration angle decreases from 81.00° to 63.52°. The area of new surface experiences rapid initial growth followed by a more gradual increase, with dissipative energy showing a more pronounced increase compared to crushing energy. The micro-fracture mode underwent an evolution from brittleness to toughness and a transition from low energy consumption to high energy consumption. The propagation, reflection, and superposition of stress waves within the rock mass gave rise to a complex stress zone, ultimately causing the rock mass to break. These findings lay the groundwork for developing a stress-damage-energy-failure combined model for shale subjected to dynamic impact loads, thereby enhancing the development of intricate networks in shale reservoir and improving the effective extraction of shale gas.

Application of support vector machines and genetic algorithms to fluid identification in Offshore Granitic subduction hill reservoirs

YL8 area granite submarine is located in the Songnan low uplift of Qiongdongnan Basin, submarine reservoir fracture development, non-homogeneous strong. Geophysical logging and gas logging do not show a clear pattern of response to the fluid properties of submarine reservoirs, and it is difficult to use logging information to linearly classify granite submarine reservoir fluids in two dimensions. Support Vector Machines (SVM) can map multi-dimensional data into high-dimensional space and construct hyperplanes in high-dimensional space to categorize the samples, which meets the need to incorporate logging curves and mud gas parameters that show complex response relationships with the fluid types of subducted reservoirs into the model.Therefore, in this paper, a support vector machine (GA-SVM) granite subduction reservoir fluid prediction model based on genetic algorithm optimisation is constructed. Firstly, the petrophysical characteristics of different reservoirs in the granite subduction hill were analysed in detail, acquisition and standardisation of logging and mud gas logging multi-dimensional parameters sensitive to reservoir fluids, inputting sensitive parameters into GA-SVM mapping multi-dimensional parameters to higher dimensional space using Gaussian radial kernel functions, using genetic algorithms to perform crossover and mutation operations on the kernel parameter g and the penalty parameter C to obtain the optimal parameter combinations, optimising the number of GA-SVM iterations and model accuracy. The GA-SVM predictions were compared with two other machine learning predictions. As demonstrated through actual case studies in the YL8 area, fluid type recognition compliance rate of 88.2% by GA-SVM, GA-SVM effectively improve the compliance rate of fluid identification in granite subduction reservoirs, provides a new idea for logging interpretation of complex reservoirs in granite subduction reservoirs.

Effect Evaluation of Staged Fracturing and Productivity Prediction of Horizontal Wells in Tight Reservoirs

In this paper, the effect evaluation and production prediction of staged fracturing for horizontal wells in tight reservoirs are studied. Firstly, the basic characteristics and value of horizontal wells in tight reservoirs are introduced, their geological characteristics, flow mechanism and permeability model are analyzed and the application of grey theory in effect analysis is discussed. Considering the problems of staged fracturing effect evaluation and the production prediction of horizontal wells in tight reservoirs, a BP neural network model based on deep learning is proposed. Due to the interference of multiple physical parameters and the complex functional relationship in the development of tight reservoir fracturing, the traditional prediction method has low accuracy and it is difficult to establish an accurate mapping relationship. In this paper, a BP neural network is used to simulate multivariable nonlinear mapping by modifying the model, and its advantages in solving the coupling relationship of complex functions are brought into play. A neural network model with fracturing parameters as input and oil and gas production as output is designed. Through the training and testing of data sets, the accuracy and applicability of the proposed model for effect evaluation and yield prediction are verified. The research results show that the model can fit the complex mapping relationship between fracturing information and production and provide an effective evaluation and prediction tool for the development of the staged fracturing of horizontal wells in tight reservoirs.