Hydraulic Fracturing Behavior Research Articles

Analysis of crack propagation and hydraulic fracturing behavior of coral reef limestone

Analysis of crack propagation and hydraulic fracturing behavior of coral reef limestone

Research on the factors influencing the width of hydraulic fractures through layers

AbstractThe method of segmented hydraulic fracturing in the coal seam roof has proven to be an efficient technique for coalbed methane exploitation. However, the behavior of hydraulic fractures in multilayer formations with significant differences in mechanical properties is still unclear. This paper studied the variation in hydraulic fracture width at the coal-rock interface by employing experimental method with a true triaxial hydraulic fracturing experimental system and numerical simulation method. Results revealed that the hydraulic fracture more likely to expanded along the coal-rock interface instead of break through it with the small horizontal stress difference and low flow rate injection condition. And improving the injection flow rate lager than a critical value, the hydraulic fracture tends to break through the coal-rock interface. Hydraulic fractures in both mudstone and coal beds exhibited a trend of increasing and then decreasing of fracture width at the interface. Since the strength of the coal seam was lower compared to that of the mudstone, maintaining high pressure was no longer necessary when the hydraulic fracture crossed the interface and entered the coal seam, leading to a reduction in fracture width within the mudstone. During the later stages of fracturing, the entry of proppant into the coal seam became challenging, resulting in a phenomenon characterized by excessive fluid but insufficient sand. The time required for the fracture width to traverse the proppant was found to be inversely proportional to the difference in horizontal ground stress and the flow rate of the fracturing fluid. And it was directly proportional to the modulus of elasticity, permeability of the coal seam, and interface strength. The interface strength has the greatest influence on the width of hydraulic fractures. In conclusion, this study provides valuable insights into the behavior of hydraulic fractures in multilayer formations with varying mechanical properties. The findings contribute to a better understanding of the factors affecting hydraulic fracture width within coal seams, which can ultimately enhance the efficiency of coalbed methane exploitation.

Simulation and optimization of unstable dynamic propagation of multiple fractures in the shale formation

Multi-cluster hydraulic fracturing of horizontal wells is a well-adopted technique with high efficiency to increase the production of tight and shale formations. However, the stress shadows among clusters pose challenges to the synchronous propagation of hydraulic fractures during multi-cluster fracturing. In order to explore the fracture propagation mechanism and characteristics under the influence of stress shadow in low-spacing staged multi-cluster fracturing, a three-dimensional hydraulic fracturing model was generated using a lattice-based method. This model considered the impact of geological and engineering parameters on the propagation behavior of multiple fractures in shale formation. A variable pumping approach is adopted, where the fracturing fluid is initially injected at a high rate and then transitioned to a lower rate. Afterward, a method was proposed to quantitatively assess the extent of fracturing in a specific area (i.e., the stimulated area), considering the impact of stress shadow within a single stage. The simulation results demonstrated significant differences in the fracture stimulation area due to the influence of each parameter in the case of uncontrollable geological factors and controllable engineering factors. An increase in both Young’s modulus and stress anisotropy of the reservoir results led to a corresponding increase in the total fracture stimulation area. As the principal stress orientation increased, the fracture stimulation area gradually decreased. In terms of operational parameters, the stimulated area of hydraulic fractures gradually decreased as the fracture spacing increased. With increasing injection rate, the stimulated area initially expanded and then decreased, peaking at an injection rate of 0.04 m3/s. These findings can provide valuable insights into the propagation behavior of multi-cluster hydraulic fractures under uncertain parameters, with significant implications for future engineering applications.

Extended finite element-based cohesive zone method for modeling simultaneous hydraulic fracture height growth in layered reservoirs

In this study, a fully coupled hydromechanical model within the extended finite element method (XFEM)-based cohesive zone method (CZM) is employed to investigate the simultaneous height growth behavior of multi-cluster hydraulic fractures in layered porous reservoirs with modulus contrast. The coupled hydromechanical model is first verified against an analytical solution and a laboratory experiment. Then, the fracture geometry (e.g. height, aperture, and area) and fluid pressure evolutions of multiple hydraulic fractures placed in a porous reservoir interbedded with alternating stiff and soft layers are investigated using the model. The stress and pore pressure distributions within the layered reservoir during fluid injection are also presented. The simulation results reveal that stress umbrellas are easily to form among multiple hydraulic fractures’ tips when propagating in soft layers, which impedes the simultaneous height growth. It is also observed that the impediment effect of soft layer is much more significant in the fractures suppressed by the preferential growth of adjoining fractures. After that, the combined effect of in situ stress ratio and fracturing spacing on the multi-fracture height growth is presented, and the results elucidate the influence of in situ stress ratio on the height growth behavior depending on the fracture spacing. Finally, it is found that the inclusion of soft layers changes the aperture distribution of outmost and interior hydraulic fractures. The results obtained from this study may provide some insights on the understanding of hydraulic fracture height containment observed in filed.

Numerical Simulation Study on the Effect of Preinjected CO2 on the Hydraulic Fracturing Behavior of Shale Oil Reservoirs.

Due to the low permeability and apparent mechanical anisotropy of shale reservoirs, shale oil production highly depends on the performance of hydraulic fracturing of the tight reservoir. Pre-injection of CO2 before hydraulic fracturing treatment has been proven beneficial to enhance shale oil production. A comprehensive understanding of the effect of changes in the properties of shale reservoirs after preinjected CO2 on the hydraulic fracturing behavior of shale reservoirs is essential to improve the stimulated reservoir volume (SRV) of shale oil reservoirs. In this study, comprehensive evaluating parameters were proposed to specify the variation of mechanical properties of shale rock at different soaking times of CO2 based on published testing parameters of shale. Accordingly, a three-dimensional (3D) numerical model was established and three groups of horizontal well fracturing cases with different cluster spacings were conducted based on the adaptive FE-DE method to simulate and compare the hydraulic fracturing behavior in the reservoirs with different mechanical properties. We established a quantitative relationship between the alterations in reservoir properties and the stimulated reservoir volume. The results indicate that both the brittleness and conductivity properties of shale rock are dramatically improved as the increment of soaking time of CO2. It is beneficial to improve the SRV, and the initiation pressure is reduced with the increment of soaking time of CO2. However, as the stress shadow effect is involved in the horizontal well fracturing, the complexity of the hydrofracturing crack is significantly enhanced to restrain the development of hydrofracturing crack. When the cluster spacing is larger, the stress shadow effect is weakened, and the weakening effect of CO2 soaking on reservoir is more obvious.

Investigation of Hydraulic Fracture Behavior near a CBM Wellbore: Evidence from in situ Observation in Coal Seam

Investigation of Hydraulic Fracture Behavior near a CBM Wellbore: Evidence from in situ Observation in Coal Seam

Hydraulic fracturing behavior of shale–sandstone interbedded structure under true triaxial stress conditions: A comprehensive experimental analysis

AbstractReservoirs characterized by shale–sandstone interbedded structures are extensively dispersed throughout China, and understanding the propagation mode of hydraulic fractures is a prerequisite for shale gas exploitation engineering. In this study, hydraulic fracturing tests were conducted using horizontal wells subjected to true triaxial compression conditions to elucidate the mechanism by which the initiated layer lithology and stress state influence the fracture morphology. Furthermore, the propagation mode of the fractures and the consequential effects on fracture network formation were investigated. The findings demonstrate four distinct interaction modes between the shale–sandstone interfaces and hydraulic fractures. The lithology of the initiated layer influences the fracture propagation trajectory, thereby affecting the propagation modes at the shale–sandstone interface and resulting in varying effects on layer penetration. The stress difference exerts a significant controlling influence on the fracturing behavior, enhancing the possibility of interconnecting multiple rock layers characterized by substantial stress differences.

The propagation of hydraulic fracture in layered coal seam: a numerical simulation considering the interface thickness based on the distinct element method

The intercalated layer of coal seam plays an important role in the propagation of hydraulic fracturing. To understand the role of the intercalated layer, a composite coal seam model considering the thickness of the intercalated layer was established. Based on the block distinct element method, the effects of rock structure (thickness of the coal seam and intercalated layer), rock properties (elastic modulus), and construction parameters (injection rate and fluid viscosity) on the penetration behavior of hydraulic fractures were analyzed. The results show that the intercalated layers influence the fracture deflection and have a hindering effect on fracture propagation. The thickness of the intercalated layer affects the stress on the bedding plane and the front edge of the fractures. On the contrary, the thickness of the coal seam mainly affects the penetration ability of hydraulic fractures and the extent of hydraulic fracture propagation. In addition, the elastic modulus of the intercalated layers and coal seams affects the hindering effect of the intercalated layer. The high injection rates reduce the hindering effect of the intercalated layer. When fracturing with a high-viscosity fluid, fractures are more likely to enter the intercalated layer. However, excessively high viscosity can make it difficult for fractures to penetrate the intercalated layer. This study can provide theoretical guidance for the fracturing of composite coal seams.

Prediction criterion and numerical validation for the interaction between hydraulic fractures and bedding planes.

Shale is a kind of sedimentary rock with an obvious bedding structure. The effect of the bedding plane on hydraulic fracture initiation, propagation, and complex fracture network formation is remarkable and a major problem in hydraulic fracturing and shale oil and gas development. In this study, a criterion is established to predict the evolution behavior of hydraulic fractures (HF) under different confining pressure differences and intersection angles. This criterion is intended to predict the types of interaction between HFs and bedding planes (BPs): penetrating, slipping, or dilating. The dependence of crossing on the intersection angle and the principal stress difference is quantitatively presented using the criterion. Meanwhile, 20 simulations with principal stress differences of 2, 4, 6, and 8 MPa and intersection angles of 30°, 45°, 60°, 75°, and 90° were simulated using the RFPA2D-Flow code. Simulation results exhibit good agreement with the criterion results for a wide range of angles. The investigation showed that HFs tend to penetrate BPs under high confining pressure differences and intersection angles and open BPs under low confining pressure differences and intersection angles. In addition to the above two forms, HFs slip due to shear. The criterion can provide relevant reference about the formation of complex fracture networks in shale layers.

Hydraulic fracturing-induced microseismicity controlled by rock brittleness and natural fractures in Tongren, Guizhou, China

Hydraulic fracturing-induced microseismicity has drawn public attention in recent years. However, understanding the behavior of hydraulic fracture is limited due to the complex relationship between microseismicity and various geologic conditions. To further understand this question, we conduct a study to detect and locate hydraulic fracturing-induced microseismicity at a shale gas production site in Tongren, Guizhou, China. We investigate the relationship between their distribution and two important geologic factors: the brittleness index (BI) of rocks and the distribution of natural fractures. With the aid of a 3D active seismic survey, we first calculate the BI of rocks in the hydraulic fracturing region using Young’s modulus and Poisson’s ratio, compared with the locating result of fracturing-induced microseismicity, which indicates that most of the events are distributed in the area with higher BI. We then delineate natural fractures using the ant-tracking method of the 3D seismic attribute. The microseismic location is consistent with the region of natural fractures. Based on our findings, we suggest that the spatial distribution of induced microseismicity is highly controlled by the brittleness of rocks and the distribution of natural fractures in this region. This research provides insights into the factors controlling hydraulic fracturing-induced microseismicity and enhances our understanding of the complex interplay between geologic conditions and the behavior of hydraulic fractures.

In Situ Stress Distribution of Deep Coals and Its Influence on Coalbed Methane Development in the Shizhuang Block, Qinshui Basin, China.

The in situ stress plays a crucial role in variations in coal permeability, hydraulic fracturing behavior, and accordingly coalbed methane (CBM) productivity. As the depth increases, the effects of in situ stress will become more prominent. In the Shizhuang block, present-day stress magnitude and permeability of coals at depths >800 m were measured with multiple-cycle hydraulic fracturing and injection falloff test, respectively. The results show that most seams are under pressure reservoirs with pressure gradient <0.9 MPa/100 m. Horizontal stress magnitudes and gradients tend to increase (800-1200 m) and then decrease (>1200 m) with increasing depth. Strike-slip fault stress regimes are predominant, while seams with depth >1400 m are subjected to a normal fault stress regime. Coal permeability tends to decrease gradually with depth and tends to be convergence to 0.01 mD. Considering extremely low permeability of these deep seams, hydraulic fracturing must be applied to create seepage channels for gas and water drainage. Although the high horizontal stress difference in deep seams is favorable for the generation of longer and simple hydraulic fractures, there is no obvious relations between fracture length and gas productivity as poor-support fractures and limited sand migration distance. The current hydraulic fracturing missed the variable stress regimes and permeability at various depth, but used the similar fracturing schemes, leading to significant reduction in gas productivity with depth. Using the high viscosity fracturing fluid, great sand volume, big injection rate, and low sand concentration are recommended for hydraulic fracturing. Single-branch horizontal well with staged fracturing show better applicability for deep CBM extraction.

A semi-analytical flowback data history-matching approach that rigorously accounts for fracture dynamics

Flowback data analysis methods used for unconventional reservoirs are still in their infancy. Until now, the dynamics of fracture closure during flowback have not been rigorously accounted for in analytical or semi-analytical models. In some cases, at the start of flowback, fracture pressure may be higher than the minimum horizontal stress, which means the fracture is still closing during the early flowback period. For such cases, the commonly-applied assumption of a static fracture width in flowback modeling will be in significant error. Moreover, previous analytical and semi-analytical modeling approaches have ignored fluid leakoff from the fracture when the fracture pressure is greater than reservoir pressure, which could also lead to significant errors when analyzing early flowback data in a stress-sensitive reservoir.In the current work, a semi-analytical history-matching approach for characterizing hydraulic fractures, which captures the dynamic behavior of hydraulic fractures during the early production period, is presented. The proposed methodology accounts for varying fracture width, cumulative leakoff from the fracture to the matrix, and spontaneous imbibition, during early flowback. The new method is verified using numerically simulated data and its practical application demonstrated by history matching a field case (shale gas well) exhibiting evidence of dynamic fracture properties during flowback. History matching of the same field case using models that do not account for fracture dynamics or fluid leakoff reveals that these models may overestimate fracture properties such as initial fracture permeability. In addition, history matching of the field case with the new model without spontaneous imbibition effects implemented yields fracture properties (initial fracture permeability and fracture half-length) that are greater than when both geomechanics and spontaneous imbibition are implemented.When compared to existing flowback models, the proposed semi-analytical model may yield more accurate estimates of fracture properties when fracture dynamics cannot be ignored during the early flowback period.

Numerical simulation of fracture propagation in deep coal seam reservoirs

AbstractAs an unconventional oil and gas resource, coalbed methane has become a key area of unconventional oil and gas exploration worldwide, and hydraulic fracturing is the critical technology for the efficient stimulation of coalbed methane. However, due to the strong heterogeneity of deep coal seam reservoirs and the development of natural cleat fractures, the fracture propagation path is quite complex and difficult to capture. In this study, we propose a hydraulic fracture propagation simulation method using the ABAQUS Software for natural cleat fracture networks and a fluid–solid fully coupled two‐dimensional finite element model with the global embedded cohesive zone model (CZM). CZM is established to simulate the propagation of hydraulic fractures in the heterogeneous combination of coal rock and mudstone. The accuracy of this model is verified by using Blanton's experiment criterion. Finally, the model is used to simulate the influence of cleat angle, cleat density, length ratio of coal rock and mudstone combination, and construction displacement on the propagation behavior of hydraulic fractures. This study aims to deepen the understanding of the mechanism of hydraulic fracture propagation in deep coal seams and provides guidance for deep coal seam fracturing and hydraulic fracturing design.

An IFS-based fractal discrete fracture network for hydraulic fracture behavior of rock mass

The discrete fracture network (DFN) model is applied for fluid flow and transport simulations in fractured rock masses. In this study, a novel two-dimensional fractal DFN generation method was proposed based on the iterative function system (IFS). To achieve the fine mesh for the DFN model, a refinement technique was presented to remove the short edges and small gaps. Subsequently, the zero-thickness flow cohesive element was inserted at the adjacent edge of elements for the hydraulic fracture modeling. The results indicated that the injection pressure of hydraulic fracture had three phases: Sudden increase, rapid drop-off, and stabilization. Compared with the traditional linear DFN model, the injection pressure evolution and fracture propagation of fractal DFN were significantly affected. In addition, the fracture aperture variation was an important factor influencing hydraulic fracturing in the rock mass. Considering the complexity of the hydraulic fracturing process, the effects of mesh sensitivity and fracture aperture size were also analyzed based on two-dimensional simulation results. This study presents a novel 2D DFN model for an accurate description of fracturing and provides a valuable simulation method for hydraulic fracturing.

Propagation Law of Hydraulic Fracture across the Coal–Rock Interface under the Co-Effect of Natural Fractures and Tectonic Stress

Indirect fracturing from roof rock to coal using a horizontal well is a new and promising technology for coalbed methane surface exploitation in soft and low-permeability coal seams. In order to study the propagation law of hydraulic fractures across the coal–rock interface, a pore pressure cohesive element is used to establish a numerical model for indirect fracturing. Combined with practical engineering in a 3# coal seam in the Xinjing mine in China, the propagation behavior of hydraulic fractures across the coal–rock interface was researched, and the range of the horizontal well position for indirect fracturing was determined. The results show that: (1) the pore pressure cohesive element can be used to accurately simulate the interaction between hydraulic fractures and natural fractures, and the propagation of hydraulic fractures across the coal–rock interface. (2) As the vertical distance between the horizontal well and coal–rock interface decreases, the breakdown pressure of perforation decreases, while the injection pressure increases when the hydraulic fracture crosses the coal–rock interface. (3) For the indirect fracturing engineering in a 3# coal seam in the Xinjing mine, the vertical distance between the horizontal well and coal–rock interface should not be larger than 2.0 m to make the hydraulic fracture propagate into the coal seams.

A criterion for a hydraulic fracture crossing a natural fracture in toughness dominant regime and viscosity dominant regime

Hydraulic fracturing is an efficient stimulation technology in the process of unconventional reservoir development, and the hydraulic fracture morphology directly affected oil and gas recovery. In this paper, we proposed a new criterion based on linear elastic fracture mechanics (LEFM) to predict the intersection behavior of hydraulic fracture (HF) and natural fracture (NF) with non-orthogonal angle. The new criterion considered the coupling effects of the fluid flow, stress shadow, and poroelastic response, and was validated with published analytical criteria and laboratory tests. Sensitivity analysis results indicated that an HF tends to cross NF under conditions of short HF half-length, high friction coefficient, high fracturing fluid viscosity and high fracture toughness. In addition, high principal stress difference inhibited the crossing behavior when the intersection angle was less than the transition angle, the HF would be arrested or divert along NF.

Influence of hydrogen on the hydraulic fracture behavior of a 42CrMo4 steel welds: Effect of the prior austenite grain size

The influence of hydrogen on the mechanical behavior of a quenched and tempered 42CrMo4 steel has been evaluated by means of high internal pressure fracture tests carried out on hydrogen precharged notched cylindrical specimens. The notched cylindrical specimens were precharged in a 1 M H2SO4 + 0.25 g/l As2O3 solution for 3 h with 1.2 mA/cm2. Hydraulic fracture tests were performed at different loading rates. Hydrogen embrittlement resistance increased with grain size refinement although the fine grained specimen had a higher hydrogen content than the coarse grained one. Fractographic analysis showed hydrogen enhanced decohesion fracturewas less pronounced with decreasing grain size. Hydrogen embrittlement susceptibility is discussed in terms of the prior austenite grain size (PAGS) and the operative fracture mechanisms.

Numerical and Experimental Simulation of Hydraulic Fracture Propagation Mechanism in Conglomerate Formation Based on Hybrid Finite-Discrete Element Method

Hydraulic fracturing was the main technology to achieve the economic development of conglomerate reservoirs, knowing that the hydraulic fracture propagation mode was of great significance for improving the development of conglomerate reservoirs. This paper proposed a new method to understand the hydraulic fracture behavior based on a hybrid finite-discrete element method. The simulation indicated that a complex fracture network was created near the wellbore in the studied conglomerate reservoir, and hydraulic fracture propagation around the gravel layer was the main failure mode when the hydraulic fracture reached the gravel layer. From the simulations, it was shown that under small differences in horizontal stress and tensile strength, the hydraulic fracture propagated more easily around the gravel layer, while it could cross the gravel under large differences in horizontal stress and tensile strength. Greater tensile strength differences can reduce the complexity of the fracture network. In addition, higher pumping rates and viscosities of fracturing fluid contribute to the complex fracture network and also can produce more gravel crosses when the hydraulic fracture is met. The main reason was that a higher pumping rate and higher viscosity of fracturing fluid can obtain a higher net pressure, which can ensure the hydraulic fracture crosses the gravel layer.

Experimental evaluation of the flow resistance of CO2 foam fracturing fluids and simulation prediction for fracture propagation

Shale gas fracturing requires huge amounts of water, but most well pads are located mainly in hilly areas where water is scarce. Water supply issues have limited the industrialization of shale gas development. CO2 foam fracturing fluids can meet the requirements for large-scale hydraulic fracturing of shale gas and relieve pressure on water resources. Friction calculations of CO2 foam fracturing fluids in conduit flow are key to the reliability of overall fracturing procedures, affecting fracture targeting and reservoir stimulation effects. Through the analysis of the experimental data of carbon dioxide foam fracturing fluid flow under the simulated reservoir conditions, the influence of pressure, temperature, shear rate, foam quality and other factors on the friction characteristics of CO2 foam fracturing fluid was obtained, and the mathematical calculation model of the friction coefficient of CO2 foam fracturing fluid was established, and the pipe string friction and bottom hole pressure during the fracturing process were obtained, Thus, the shape and extension behavior of hydraulic fractures in the process of carbon dioxide foam fracturing in shale reservoir are simulated and predicted, which provides a theoretical basis for effective evaluation of fracturing effect.

Fluid-solid-phase multi-field coupling modeling method for hydraulic fracture of saturated brittle porous materials

Hydraulic fracturing of saturated brittle rock is a common discontinuous multi-physics phenomenon. The evolution and flow behavior of hydraulic fractures are the key to multi-field coupling in saturated brittle porous media. A fluid-solid-phase multi-field coupling modeling method for hydraulic fracturing is proposed and implemented by staggered algorithm in a commercial finite element software. In this method, the hydraulic fracture evolution is controlled by a unified fracture phase-field method, and the fluid flow in the cracked domain is equivalent to a Darcy-type flow whose flow property is dependent on the crack width. The crack width is derived according to the level-set method, and discretized into an equivalent form to determine the flow property in the cracked domain. The simulation results show that the proposed multi-field coupling modeling method performs well in simulating the hydraulic fracturing of saturated brittle porous media under constant flow and constant injection pressure. A heterogeneous model is established by applying the multi-field coupling modeling method to mesostructured materials, which shows great potential in simulating irregular-shaped natural fractures.