This study presents a thermo-hydro-mechanical framework to model hydrothermal systems within a simplified faulted synthetic reservoir, replicating current production scenarios in The Netherlands and Germany. The reservoir, composed of porous and permeable sandstone, and the confining layer, made of porous but less permeable shale, undergoes a process where cold water is injected and hot water is extracted. A fault, situated 750 meters from the injection well, is investigated to examine the conditions when fault slip could occur. Various fault and formation stiffnesses are modeled to assess their impact on fault stability. Our analysis reveals that stress changes induced by hydrothermal operations can lead to fault reactivation, with the stiffness contrast between the reservoir and confining layers playing a significant role in when and where fault reactivation can occur. Stiffer confining layers lead to reactivation occurring more closely associated with the passage of the cooling front. In contrast, a stiffer reservoir results in greater and more gradual stress changes, making reactivation more closely related to the total volume of cooled rock.

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Cold water injection into geothermal reservoirs is a common, sometimes necessary, technique for multiple reasons including the replenishment and stimulation of the reservoirs, and the disposal of waste water. The injection of cold water results in a thermo-hydro-mechanical (THM) impulse, which can cause near-wellbore cracking. A method is presented to simulate coupled thermo-hydro-mechanical processes, including the re-activation of existing fractures and fracturing of the rock matrix. The model is based on the finite element method, and utilises a newly developed cohesive interface element to represent discontinuities. The interface element belongs to the family of zero-thickness elements and is triple-noded. It is developed to allow the simulation of longitudinal and transversal fluid/heat flow. The cubic law is used to simulate the fracture transmissivity as a function of its aperture, while a elasto-damage law is used to characterise the mechanical response of the discontinuity. The method is successfully verified against analytical solutions for hydraulic fracturing (KGD model) and for the thermo-hydraulic response of a single fracture (Lauwerier’s problem). As numerical oscillations are observed due to the high Péclet number, an artificial diffusion is added to stabilise the numerical solution with sufficient accuracy. Qualitative validation is achieved against experimental data of cold water injection in granite samples. Fracture branching is observed in the case with large cooling shock, while a single fracture is induced in the case with smaller cooling shock, as was observed in the experiment. The validation demonstrates the capability of the proposed model to simulate fracturing processes under THM couplings.@en

Acid treatments aimed at reducing formation breakdown pressure are becoming increasingly popular in stimulating deep and ultra-deep geothermal and natural gas reservoirs, where high pumping pressures are typically required for fracturing. This technique effectively reduces surface pumping pressures, ensuring safe operations. Through multiscale experiments and mechanistic analysis, this study reveals the fundamental mechanisms underlying breakdown pressure reduction via acid preconditioning. Key findings include: (1) High breakdown pressures arise from high in-situ stress, low porosity and permeability, and engineering contamination. (2) Acid-induced mineral dissolution triggers dual effects-pore structure evolution enhances reservoir permeability (facilitating subsequent fracturing fluid imbibition and pressure transmission), while mechanical property degradation substantially weakens rock resistance to fracturing. (3) Comparative analysis of HCl, organic acids, and chelating agents demonstrates that high-temperature reservoirs benefit from low-corrosivity chelating agents (e.g., GLDA) or organic acid systems combined with low-concentration HCl, achieving optimal dissolution efficiency while ensuring wellbore integrity. (4) A multiscale laboratory evaluation framework was established to integrate experimental data for optimizing acid formulations and post-acid fracturing strategies. This paper provides mechanistic insights, acid system selection criteria, and experimental methodologies for breakdown pressure reduction in deep carbonate reservoirs, offering significant engineering value for achieving safe and efficient reservoir stimulation.

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This study presents a fully coupled hydro-mechanical framework for modeling hydraulic shearing in a mesoscale reservoir located at the Grimsel Test Site, Switzerland. The experiment was conducted on a ductile–brittle fault embedded in low-permeable granite. We observe that normal fracture opening increases flow channel recoverably, while fracture sliding locks asperities leading to a non-recoverable increase in flow. To couple these processes, we use a poro-elasto-plastic constitutive framework and employ a permeability function that depends on several parameters, such as dilation angle, in-situ stresses, residual aperture and maximum aperture. Our results capture the recorded pressure responses well, and indicate that the permeability changes by one order of magnitude during the experiment.

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This paper presents a combined laboratory and numerical investigation on the injection-induced permeability changes in pre-existing fractures. The analyses conducted were primarily based on the results of an innovative laboratory experiment designed to replicate the key mechanisms that occur during hydraulic stimulation of naturally fractured rocks and/or faulted zones. The experiment involved pressure-controlled fluid injection into a laboratory-scale pre-existing fracture within a granite block, which was subjected to true triaxial stress conditions. Rough and smooth fractures are investigated, and the results are discussed. Based on the experimental results, two contributing mechanisms were considered to describe the pressure-driven permeability changes in pre-existing fractures: (1) elastic opening/closure leading to a reversible permeability change, and (2) fracture sliding in shear mode, causing dilation and hence an irreversible permeability increase. With these assumptions, an aperture-dependent permeability function was adopted to couple the hydraulic flow with the mechanical deformations along the fracture. Subsequently, a 3D coupled hydro-mechanical model was developed to replicate fluid-injection tests conducted at various conditions, including different stress conditions and fracture surface roughness. The employed modeling framework effectively captured the experimental observations. Our results indicate that the maximum permeability increases twofold.@en

In geothermal projects, reinjection of produced water has been widely applied for disposing wastewater, supplying heat exchange media and maintaining reservoir pressure. Accordingly, it is a key process for environmental and well performance assessment, which partly controls the success of projects. However, the injectivity, a measure of how easily fluids can be reinjected into reservoirs, is influenced by various processes throughout installation and operation. Both injectivity decline and enhancement have been reported during reinjection operations, while most current studies tend to only focus on one aspect. This review aims to provide a comprehensive discussion on how the injectivity can be influenced during reinjection, both positively and negatively. This includes a detailed overview of the different clogging mechanisms, in which decreasing reservoir temperature plays a major role, leading to injectivity decline. Strategies to avoid and recover from injectivity reduction are also introduced. Followed is an overview of mechanisms underlying injectivity enhancement during reinjection, wherein re-opening/shearing of pre-existing fractures and thermal cracking have been identified as the main contributors. In practice, nevertheless, mixed-mechanism processes play a key role during reinjection. Finally, this review provides an outlook on future research directions that can enhance the understanding of injectivity-related issues.

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and boundary connected with aquifer respectively, are discussed. On the basis of these two boundary conditions, several factors that influence the fluid loss process are studied. For the thief zone with no-flow boundary, our key conclusions illustrate that once the pressure front reaches an opening in the sealing, fluid loss occurs. However, fluid loss is substantially limited (leakage rate lower than 0.02 m3/h) within one year of operation. The time at which leakage is limited, is controlled by the permeability shock between the thief zone and reservoir, transmissivity of fracture in sealing layer and injection pressure. In addition, only the injection pressure has a significant influence on the total amount of lost fluid, while the permeability shock and fracture conductivity do not influence it. However, more permeable thief zone and more conductive fracture could be helpful to quickly prevent the fluid loss, since the pressurisation up process can be achieved more quickly, and thus prevent the leakage in the early stage, ensuring a stable injection rate in the long term . In contrast, for the thief zone with fixed-pressure boundary, fluid loss does not stop. Instead, it keeps a constant leakage rate, indicating a continuous fluid loss. However, the increase in fluid pressure remains more limited. In this case, a more permeable thief zone, more conductive opening and higher injection pressure increase the leakage rate, yet reduce the elevated pressure. In conclusion, leakage can be prevented as a result of pressurization up of thief zones sealed by faults, and the only thing to consider in the planning stage is how fast it can be. While for thief zones linked with aquifers, injection plan should be made carefully to avoid induce or promote any fractures in sealing layer, or continuous leakage would occur. @en