Carbon dioxide (CO2) is an alternative working fluid to water for hydraulic fracturing in shale reservoirs. It offers advantages as a substitute for the use of large quantities of potable water and ...for the concurrent sequestration of CO2, however sorption and swelling effects, and their impact on permeability may be detrimental and are undefined. Hence, it is of great importance to understand the mechanism of supercritical carbon dioxide fracturing in shale and its effect on shale permeability enhancement. We conduct hydraulic fracturing experiments on shale samples using both water (H2O) and supercritical carbon dioxide (Sc-CO2) as fracturing fluids to explore the surface characteristics and permeability evolution of fluid-driven fractures. We use profilometry to measure the roughness and complexity of the resulting fracture surfaces and measure the permeability of the fractures. Results indicate that: (1) Sc-CO2 fracturing creates fractures with larger tortuosity relative to H2O fracturing (macroscale); (2) the topography of Sc-CO2 fracture surfaces is more rough and complex compared to that of H2O fractured surfaces; (3) larger mineral grains are removed and relocated from induced fracture surfaces by Sc-CO2 fracturing – these acting as micro proppants that result in a larger fracture aperture; (4) correspondingly, the permeability of shale fractures increases by ∼5 orders of magnitude with Sc-CO2 fracturing and this enhancement is ∼3 orders of magnitude higher than that by traditional hydraulic fracturing. This observation potentially validates the feasibility of Sc-CO2 as a fracturing fluid for the stimulation of shale reservoirs.
•Sc-CO2 fracturing creates fractures with larger tortuosity.•Sc-CO2 fracturing creates fracture surfaces with a larger roughness and complexity.•Sc-CO2 fracturing increases shale permeability by five orders of magnitude.•Mineral grains are peeled from fracture surface by Sc-CO2 fracturing.
Fluid injection-induced fracture slip during hydraulic stimulation of shales may be seismic or aseismic with the slip mode potentially influencing the evolution of permeability and subsequent shale ...gas production. We report a series of friction-permeability tests with constant and stepped velocities on planar saw-cut fractures of Longmaxi shale, Green River shale and Marcellus shale. In particular we explore the additive effect of stepped velocity on fracture permeability evolution relative to the background permeability driven at constant velocity. Fracture permeability decreases at larger slip displacement at constant velocity presumably due to asperity degradation and clay swelling. Sudden up-steps in slip velocity temporarily enhance fracture permeability as a result of shear dilation on hard minerals, but permeability net decreases with increasing slip displacement as wear products fill the pore space. Fracture surface roughness is the link between the fracture permeability and friction coefficient, which are both influenced by mineralogical composition. The fractures and sheared-off particles in the tectosilicate-rich and carbonate-rich shales dilate to increase fracture permeability, whereas asperity comminution readily occurs in the phyllosilicate-rich shale to reduce fracture permeability. The results potentially improve our ability to facilitate shale gas extraction and to mitigate the associated seismic risks.
The fluid injection-induced seismicity has drawn widespread concern due to the dramatic rise in seismicity rate worldwide, especially recent events associated with hydraulic fracturing operations ...during shale gas development. The frictional restrengthening is a prerequisite for the seismic cycles and the rate-and-state friction law is commonly used to describe the frictional behaviour of fractures and faults. However, the permeability evolution of faults/fractures during the seismic cycles remain finitely understood. In this study, we perform a series of slide-hold-slide experiments with concurrently permeability measurement to explore the frictional restrengthening, and permeability response to seismic cycles with Longmaxi shale fractures. The results indicate that even though the Longmaxi shale fractures exhibit a lower frictional healing rate than granite fractures, they still have the potential for seismic activities with a relatively lower seismic moment or low-rate creep. Similar to the in-situ observations, the Longmaxi shale fracture permeability gradually decays during the whole seismic cycle. The permeability response due to the reactivation and repose is complicated, which is largely controlled by the fracture slip history and matching conditions. Fracture permeability enhancement due to reactivation results from the shear dilation, mineral particle mobilisation, and the destruction and breaching of the fracture sealing. In contrast, permeability decay mainly results from asperity degradation. These observations highlight that the small-scale fracture surface properties may largely affect the permeability recovery and decay during seismic cycles, which provides a deeper understanding of fracture frictional behaviours and mitigating seismic risks in shale reservoirs.
Highlights
Longmaxi shale fractures exhibit low frictional healing rates than granite and quartz gouges.
The permeability response due to the reactivation and repose is primarily controlled by the fracture slip history and matching conditions.
Small-scale fracture surface properties could largely affect the permeability creation and decay during seismic cycles.
The Lower Silurian Longmaxi formation is one of the most promising shale gas reservoirs in China. A comprehensive understanding of the shale geomechanical and petrophysical properties is crucial for ...the successful exploration and extraction of shale gas. We select four representative locations to acquire Longmaxi formation shale samples for the laboratory experiments, to investigate the geomechanical and petrophysical properties through a series of X-ray diffraction (XRD), scanning electron microscope (SEM), uniaxial compression, triaxial compression, tensile strength, and fracture toughness measurements. Laboratory results indicate that: (1) The quartz is the dominant mineral, and phyllosilicate mineral contents vary largelly from 7.30% to 47.80% in Longmaxi shale, which enables a higher brittleness index and fracbility. SEM results show that the high gas storage potential and well micro-fractures development of Longmaxi shale rocks. (2) The phyllosilicate content is vital in determining the uniaxial compressive strength, triaxial strength and elastic properties due to its weaker mechanical properties than tectosilicate minerals; (3) Fracture toughness of Longmaxi shale are relatively higher than shale formations in the USA, which indicate a higher potential to form fracture networks during hydraulic fracturing operations. (4) The anisotropy affects Longmaxi shale mechanical properities extensively due to the high-density bedding planes, which may further influence the fracture network formation during hydraulic fracturing operations. Our results revealed significant non-linear mechanical response as a consequence of shale fabric and mineralogy, which provides necessary information for the in-situ hydraulic fracturing and wellbore stability application during shale gas development in Longmaxi shale formation.
•Nanopores and high thermal maturities of Longmaxi shale indicate a high gas storage potential.•The micro-fractures are beneficial for hydraulic fracturing stimulations to enhance reservoir permeability.•The geomechanics properties of Longmaxi shale vary largely due to the differences in mineralogical compositions.•The anisotropy cannot be neglected in analyzing Longmaxi shale geomechanical and petrophysical properties.
As one of the most promising shale gas reservoirs in China, the Lower Silurian Longmaxi formation in the Sichuan Basin has produced a large amount of shale gas during the last few years. However, two ...significant concerns have been raised during the contemporary shale gas development in this area: dramatic increases in well depths and potential induced seismicity. The extreme depths have resulted in higher in-situ stress and reservoir breakdown pressures. The other concern is whether recent earthquakes are related to hydraulic fracturing operations since they are close in space and time. An advanced fluid injection protocol-cyclic fluid injection has been proposed and used to lower the breakdown pressure of reservoirs and mitigate the potential seismic risks caused by hydraulic stimulations. In this study, we combine a series of laboratory experiments and a numerical simulation model to investigate the breakdown mechanism, seismic risks, permeability enhancement performance of cyclic fluid injection. The results indicate that the cyclic injection method decreases the shale breakdown pressure by ∼25% compared with the conventional monotonic rate injection, which is the result of fatigue failure near the fluid injection borehole induced by pore pressure fluctuations lagging behind the periodical injection pressure changes. Even though more acoustic emission events are observed during and post-the cyclic injection, the maximum acoustic emission amplitude decreases by 26%, which is equivalent to transforming AE events with large amplitudes to more AE events with small amplitudes. Moreover, fracture morphology and permeability measurement results indicate that cyclic injection creates hydraulic fractures with higher fracture tortuosity but smaller aperture and lower permeability, which contributes to the fatigue mechanism of rock breakdown. Our experimental results and theoretical analysis initially validate the potential of using cyclic injection methods to perform hydraulic fracturing stimulation in shale reservoirs to lower breakdown pressure and mitigate seismic risks.
Massive fluid injection into the subsurface can induce microearthquakes by reactivating preexisting faults or fractures as seismic or aseismic slip. Such seismic or aseismic shear deformations may ...result in different modes of permeability evolution. Previous experimental studies have explored frictional stability‐permeability relationships of carbonate‐rich and phyllosilicate‐rich samples under shear, suggesting that friction‐permeability relationship may be primarily controlled by fracture minerals. We examine this relationship and identify the role of mineralogy (i.e., tectosilicate, carbonate, and phyllosilicate content) using direct‐shear experiments on smooth saw‐cut fractures of natural rocks and sintered fractures with distinct mineralogical compositions. These results indicate that the friction‐permeability relationship is controlled by mineralogy. Frictional strength and permeability change upon reactivation decrease with phyllosilicate content but increase with tectosilicate content. In contrast, the reverse trend is observed for frictional stability (a‐b). However, the permeability change decreases with carbonate content while both frictional strength and stability increase. The permeability change always decreases with an increase in frictional stability. This relationship implies a new mechanical‐hydro‐chemical coupling loop via a linkage of frictional properties, mineralogy, and permeability.
Key Points
This study presents the evolution of frictional stability‐permeability in sheared smooth natural and sintered fractures with distinct mineral compositions
Frictional stability increases with carbonate and clay content and decreases with tectosilicate content
Permeability evolution is inversely correlated with frictional stability
In enhanced geothermal systems (EGS), the natural permeability of deep rocks is normally not high enough and needs to be increased. Permeability increase can be achieved through various stimulation ...methods, such as hydraulic, chemical, and thermal stimulation. Among these, hydraulic stimulation is the most commonly used technique to increase both reservoir permeability and the specific area for heat exchange. A comprehensive understanding of the underlying processes towards an optimization of hydraulic stimulation performance while minimizing the potential of unwanted induced seismicity is a critical prerequisite for a successful development of any EGS site. In this paper, we review the hydraulic stimulation strategies that have been developed and implemented for EGS. We begin with a description of the underlying mechanisms through which the permeability and heat exchange area increases are achieved. We then discuss the mechanisms of fluid injection-induced seismicity during and after a hydraulic stimulation operation. After that, alternative hydraulic stimulation strategies, namely conventional hydraulic stimulation, multi-stage fracturing, and cyclic soft stimulation, are reviewed based on current research in theoretical studies as well as, laboratory, and in-situ field experiments. Finally, some representative EGS projects are reviewed, focusing on fluid injection strategies, seismic responses, and reservoir permeability enhancement performance. The review shows the importance and need of (a) a comprehensive geological characterization of the natural fracture system including the nearby fault zones as well as the in-situ stress conditions, prior to the development of the site, (b) a proper design of the well arrangement, such as the positioning of the injection and production wells, and (c) the selection of an appropriate fluid injection strategy for the system at hand.
Article highlights
A comprehensive geological characterization of the natural fracture system and nearby fault zones is critical before the development of an EGS project.
Proper design of the arrangement of the injection and production wells as well as the fluid injection strategy are essential elements for successfully developing an EGS project.
Further research in coupled thermo-hydro-mechanical-chemical processes during and after a fluid injection operation in EGS is needed, in particular for better understanding of the processes related to induced seismicity.
Seismic activities have been reported by the large-scale fluid injection in shale reservoirs both during hydraulic fracturing operations and wastewater disposal processes. Fluid overpressure has been ...regarded as the primary cause for the injection-induced seismicity since the fluid lubricates the fault and decreases the effective normal stress applied to the pre-existing faults. However, how fractures/faults slip after the activation remains unclear. The rate-and-state friction law has been widely used to describe the fracture stability during slip. Hence, we performed a series of velocity-stepping slip experiments under various combinations of fluid pressure and normal stress states with shale samples, which aims to investigate the role of fluid pressure on the rate-dependent parameter (a–b) and critical slip distance (Dc) evolution. We observed the frictional stability transits from velocity strengthening to velocity weakening with the increase of fluid pressure in shale samples. Moreover, the critical slip distance increases dramatically due to the fluid pressure increases, which is the result of the fluid oscillation phenomenon. Through the calculation of critical fracture rheologic stiffness of shale samples under fluid pressure, the results indicated that a higher possibility for fluid injection-induced seismicity with the increase of fluid pressure. Our experimental observations suggest that the fluid pressure can change the frictional stability characteristics of shale fractures and favor the potential seismic slip, which could be a possible mechanism for the fluid injection-induced seismicity, especially in unconventional shale reservoirs.
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