Tree-type hydraulic fracturing (TTHF) is a new technology that can enhance the permeability of coal seams in a balanced manner and increase the coalbed methane production rate. However, the ...heterogeneity of coal seams is a major challenge in achieving balanced permeability enhancement by TTHF. Traditional methods based on digital image processing are difficult to apply in practice. To address these challenges, we proposed a 2D numerical model of coal seams based on the combined finite-discrete element method (FDEM). The elastic modulus of the coal seams obeys a Weibull distribution, and the coal heterogeneity was quantified by an index m. The effects on the fracture initiation pressure, the fracturing influence range, and displacements of TTHF were analyzed from four aspects, including the homogeneity index of coal, the arrangement angle of branch boreholes, the horizontal stress difference, and the injection rate of the fracturing fluid. The results show that TTHF has a significant effect on the balanced permeability enhancement in coal reservoirs, particularly with strong heterogeneity, and the best permeability enhancement for TTHF is achieved when the branch boreholes are arranged at 45°. The branch boreholes are prefabricated in advance to create a pressure relief area around the injection point, and the hydraulic fracture propagation is affected by the horizontal stress difference only when the fracturing influence range exceeds this area. When the horizontal stress difference increases from 0 to 4 MPa, its fracture initiation pressure increases from 8.93 to 10.86 MPa, with an increase of 21.61%. In addition, the initial stage of fluid injection was found to be crucial for achieving balanced permeability enhancement in TTHF, and a higher injection rate can expand the fracturing influence range. The numerical model has profound implications for the field application of TTHF technology.
The shale fracture permeability is critical in determining gas production and deep CO2 sequestration performance. Moreover, how shale fracture permeability evolves after interactions with ...supercritical carbon dioxide (Sc-CO2) should be understood to constrain the shale reservoir permeability and evaluate the long-term sealing ability of shale formations. In this research, we conducted soaking experiments with shale fractures and Sc-CO2 at various times and then measured the shale fracture permeability and hydraulic aperture evolution under different stress states. Additionally, we quantify the chemical compositions, pore characteristics, fracture surface roughness alternation through X-ray diffraction, nuclear magnetic resonance, scanning electron microscope, and optical profilometry techniques. Our results indicate that soaking with Sc-CO2 will dramatically increase the shale fracture permeability and aperture due to the calcite and dolomite dissolution. This free-face dissolution process will remove the mineral particles in the fracture surface, resulting in larger pores, peaks, and valleys in the fracture surfaces. This process may last for seven days, and after that, chemical reactions may terminate, and the rock-Sc-CO2 system turns stable. Our results explain how Sc-CO2 alters the shale fracture permeability through the chemical dissolution of specific minerals from a microscale analysis.
Non-aqueous or gaseous stimulants are alternative working fluids to water for hydraulic fracturing in shale reservoirs, which offer advantages including conserving water, avoiding clay swelling and ...decreasing formation damage. Hence, it is crucial to understand fluid-driven fracture propagation and morphology in shale formations. In this research, we conduct fracturing experiments on shale samples with water, liquid carbon dioxide, and supercritical carbon dioxide to explore the effect of fluid characteristics and in situ stress on fracture propagation and morphology. Moreover, a numerical model that couples rock property heterogeneity, micro-scale damage and fluid flow was built to compare with experimental observations. Our results indicate that the competing roles between fluid viscosity and in situ stress determine fluid-driven fracture propagation and morphology during the fracturing process. From the macroscopic aspect, fluid-driven fractures propagate to the direction of maximum horizontal stress direction. From the microscopic aspect, low viscosity fluid easily penetrates into pore throats and creates branches and secondary fractures, which may deflect the main fracture and eventually form the fracture networks. Our results provide a new understanding of fluid-driven fracture propagation, which is beneficial to fracturing fluid selection and fracturing strategy optimization for shale gas hydraulic fracturing operations.
We report experimental observations of permeation of CO2-rich aqueous fluids of varied acidic potential (pH) on three different shales to investigate mechanical, chemical, and mineralogical effects ...on fracture permeability evolution. Surface profilometry and SEM-EDS (scanning electron microscopy with energy-dispersive X-ray spectroscopy) methods are employed to quantify the evolution in both roughness on and chemical constituents within the fracture surface. Results indicate that, after 12 hours of fluid flow, fracture effective hydraulic apertures evolve distinctly under different combinations of shale mineralogy, effective stress, and fluid acidity. The evolution of roughness and transformation of chemical elements on the fracture surface are in accordance with the evolution of permeability. The experimental observations imply that (1) CO2-rich aqueous fluids have significant impact on the evolution of fracture permeability and may influence (and increase) shale gas production; (2) shale mineralogy, especially calcite mineral, decides the chemical reaction and permeability increasing when CO2-rich aqueous fluids flow through fractures by free-face dissolution effect; (3) clay mineral swelling reduces fracture aperture and additively calcite pressure solution removes the bridging asperities, which are the main reasons for fracture permeability decrease; (4) competition roles among clay mineral swelling, mineral pressure solution, and free-face dissolution determine how fracture permeability changes. Furthermore, a multiple parameter model is built to analyze effective hydraulic aperture evolution in considering above three mechanisms, which provide a reference to forecast fracture permeability evolution in shale formations.
Celotno besedilo
Dostopno za:
DOBA, IZUM, KILJ, NUK, PILJ, PNG, SAZU, UILJ, UKNU, UL, UM, UPUK
Geological carbon dioxide (CO2) storage in deep, unmineable coal seams represents a promising strategy for carbon emissions reduction. This approach involves pore and fracture alteration due to ...injecting supercritical CO2 (SCCO2), which is crucial for long-term safe storage of CO2 and extracting coalbed methane. This study quantitatively characterized pores and fractures before and after SCCO2 saturation using nuclear magnetic resonance (NMR). The results show an average 89 % increase in total porosity after SCCO2 treatment. The proportion of macropores significantly increased, resulting in a wider range of pore sizes, with the average of macropore porosity increased by more than seven times. Furthermore, SCCO2 exposure reduced the fractal dimension, resulting in smoother pores conducive to gas transport. The alterations in pore type induced by SCCO2 were discussed, in which original fractures exhibited increased apertures after SCCO2 exposure, accompanied by new Y-shaped secondary fractures, while XRD analysis explained mineral dissolution and precipitation. A conceptual model considering the swelling coefficient in matrix-fracture development under SCCO2 dissolution is proposed based on the correlation between seepage pores and adsorption pores. Furthermore, the influence of pore morphology on the development of pores and fractures under SCCO2 exposure was analyzed, offering valuable insights into the CO2-ECBM project.
•Coal porosity increased, and seepage porosity rose over 7 times after SCCO2 exposure.•Lower porosity and higher complexity of raw coal lead to greater porosity increase.•SCCO2 increases the fracture opening and forms new fractures.•A conceptual model for matrix-fracture influenced by SCCO2 dissolution is proposed.
•Theoretical considerations suggest a control on fault stability and rupture dynamics by multiple non-dimensional parameters.•Varying load-point velocity in direct-shear laboratory experiments allows ...gradual changes in effective friction properties.•Laboratory data reveal multiple factors controlling rupture dynamics and stability of polycarbonate faults.
The stability of frictional sliding affects the spectrum of fault slip, from slow-slip events to earthquakes. In laboratory experiments, the transition from stable sliding to stick-slip is often explained by the ratio of the stiffness of the loading system to a critical value that depends on effective normal stress and other physical properties. However, theoretical considerations indicate other controls on fault stability that have not been validated experimentally. Here, we exploit the dependence of frictional properties on load-point velocity to explore the dynamics of frictional sliding with gradual variations of frictional properties. We use the period-multiplying and chaotic cycles that appear at the transition between stick-slip and stable sliding as a sensitive indicator of fault stability. In addition to the stiffness ratio, we find that the ratio of the parameters that describe the dependence on velocity and state constitutes another control on the stability of faulting and rupture dynamics. Variations of these two non-dimensional parameters among faults may help explain the wide range of rupture styles and recurrence patterns observed in nature.
Spontaneous imbibition can impact the fluid distribution and saturation within the shale reservoirs, which, in turn, has an impact on the production and storage of shale oil and gas. The spontaneous ...imbibition characteristics of shale reservoirs under the CO2-brine-rock system will change. In order to understand the spontaneous imbibition characteristics of shale (before and after treatment with different pressures in CO2-brine), we researched the rock samples of shale from Chang 7 3 submember of Ordos Basin accordingly to conduct CO2-brine immersion treatment under different pressure tests, spontaneous imbibition tests (AFO), NMR T 2 tests, contact angle tests, and XRD tests. The results show that the final imbibition mass of/the initial imbibition rate of/the imbibition volume of brine and dodecane for the shale increase with the treatment pressure (CO2-brine immersion stage) increasing on the shale. It is the result of the combination of porosity, wettability, and mineral composition. Although the water wettability of the shale decreases and the relative content of water-wet (oil-wet) minerals decreases (increases), the porosity of the shale increases, so that the final imbibition mass of both brine and dodecane increases. Therefore, porosity has a greater influence on SI. CO2-water treatment at different pressures improves the spontaneous imbibition capacity of shale into water and oil, which will be beneficial to the flowback of fracturing fluid and the recovery of crude oil in the process of shale oil production.
Managing fluid stimulation protocols is an effective means to mitigate the risk of injection-induced earthquakes during shale gas development. The success of these protocols is dependent on our ...understanding of fluid pressure heterogeneity and the associated inhomogeneous slip on critically stressed faults. Here we show the evolution of velocity-weakening zone on a simulated fault, derived from fluid injection and velocity stepped experiments, and the corresponding non-uniform fluid pressure distribution, recovered from coupled hydro-mechanical simulations. Our results indicate that the sharp extension of velocity-weakening zone occurs before the nucleation of fault rupture, which could be an indicator to avoid the reactivation of other fault patches beyond the stimulated zone. The dynamic rupture is estimated to extend much faster than the maximum speed of the velocity-weakening zone front. We infer that the velocity-weakening zone may further expand and fully control the fault behavior after multiple slip events.
•After CO2-brine-rock interaction, the SSA and PV of the shale decrease.•Both mineral dissolution and mineral precipitation were observed through SEM.•The precipitation of siderite is the main reason ...for the decrease in PV.•There may be a self-sealing mechanism in the shale caprock caused by mineral precipitation after CO2 injection.
The integrity of the caprock is a pivotal element influencing the security of CO2 geological sequestration. The CO2-brine-rock interaction can alter the pore structure of the caprock, thereby influencing its sealing capability. In this study, CO2-brine-rock interaction experiments were conducted on Yanchang shale from the Ordos Basin, China. The changes in the shale pore structure and mineral composition before and after the interaction were characterized using low-pressure N2 adsorption (LPN2A), low-pressure CO2 adsorption (LPCO2A), scanning electron microscopy (SEM), energy dispersive spectroscopy (EDS), and X-ray diffraction (XRD). The results showed that the pore volume (PV), specific surface area (SSA), and fractal dimension (D) of the shale decreased after the CO2-brine-rock interaction. The formation of siderite precipitates is the main reason for the reduction in shale pore volume, which can enhance the sealing capacity of the caprock. The findings of this study provide critical insights and theoretical support for the implementation of CO2 geological sequestration projects in the Ordos Basin, China, potentially enhancing their safety and effectiveness.
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