Hydraulic Fracture Network Propagation Research Articles

Hydraulic fracture network propagation in a naturally fractured shale reservoir based on the “well factory” model

In different geological and engineering conditions, it is important to study the stress interference of multiple fractures and interaction of natural fractures in “well factory” fracturing to improve the complexity of fracture networks. For this purpose, a 2D, coupled stress-seepage-damage field cohesive model with random propagation of hydraulic fracture was developed, and a random function was used to simulate the natural fractures distribution in a real reservoir. Orthogonal test was designed to investigate the geological and engineering parameters impacting the evolution of zipper fracturing and modified zipper fracture networks. The results show that in naturally fractured reservoirs, hydraulic fracture can open natural fractures and promote the formation of complex fracture networks by combined, induced manner. Higher stress differences lead to simpler fracture networks and straighter hydraulic fracture propagation paths; When pre-existing natural fracture is longer, the propagation direction of hydraulic fracture is more likely to be paralleled with natural fracture; However, the stress shadow effect of multiple fractures may potentially lead to failure of some hydraulic fracture initiation. In addition, the fracture initiation sequence of multiple fractures has a significant effect on the evolution of the fracture networks. The results of the study have important significance for parameter optimization of well factory fracturing in naturally fractured reservoirs.

Mechanisms for the Generation of Complex Fracture Networks: Observations From Slant Core, Analog Models, and Outcrop

We use observations of hydraulic fractures in core, outcrop attributes of natural hydraulic fractures, and analogue models, to address how hydraulic fracture networks evolve. A slant core from the Wolfcamp Formation—an unconventional shale hydrocarbon reservoir in the Permian Basin of West Texas—collected within 18 m and 30 m of two hydraulically stimulated horizontal wells, provided an opportunity to examine hydraulic fractures directly. In approximately 183 m of core, 309 calcite-sealed natural opening-mode fractures and 375 hydraulic fractures were identified. Many hydraulic fractures in the core show complex morphology, including twist-hackle segmentation, diversion, and bifurcation; these structures most commonly develop at lithological bed boundaries and mechanical heterogeneities such as natural fractures and concretions. An outcrop of bed-parallel pavements in the Cretaceous Boquillas Formation in West Texas contains opening-mode fractures that likely formed by natural hydraulic fracturing. Fracture traces provide evidence of twist-hackle segmentation, and are typically associated with bed boundaries and preexisting bed-parallel stylolites. A laboratory study of hydraulic fracturing of 33 synthetic blocks of gypsum and hydrostone revealed fracture steps, diversions, twist hackles, and multiple overlapping fractures together with information on fracture growth directions. These complexities in the fracture network were dominantly nucleated at inclusions used to simulate pre-existing fractures, and as a result of mechanical heterogeneity introduced by the wellbore and perforations. Collectively, our results show that complex fracture networks are produced in hydraulic fracturing of self-sourced reservoir strata. Mechanical stratigraphic boundaries and other heterogeneities are likely to enhance fracture network complexity through the processes of segmentation, diversion, and bifurcation. These processes create multiple fracture strands, resulting in an increased number of hydraulic fractures over those initiated, thereby increasing total fracture surface area. Our study provides insight into hydraulic fracture network propagation, and has applications for evaluation, completion, production, and fracture modeling of unconventional reservoirs.

Numerical modeling of complex hydraulic fracture networks based on the discontinuous deformation analysis (DDA) method

Hydraulic fracturing is one of the most important technologies for shale gas production. Complex hydraulic fracture networks can be stimulated in shale reservoirs due to the existence of numerous natural fractures. The prediction of the complex fracture network remains a difficult and challenging problem. This paper presents a fully coupled hydromechanical model for complex hydraulic fracture network propagation based on the discontinuous deformation analysis (DDA) method. In the proposed model, the fracture propagation and rock mass deformation are simulated under the framework of DDA, and the fluid flow within fractures is simulated using lubrication theory. In particular, the natural fracture network is considered by using the discrete fracture network (DFN) model. The proposed model is widely verified against several analytical and experimental results. All the numerical results show good agreement. Then, this model is applied to field-scale modeling of hydraulic fracturing in naturally fractured shale reservoirs. The simulation results show that the proposed model can capture the evolution process of complex hydraulic fracture networks. This work offers a feasible numerical tool for investigating hydraulic fracturing processes, which may be useful for optimizing the fracturing design of shale gas reservoirs.

3D NUMERICAL INVESTIGATION OF HYDRAULIC FRACTURE NETWORK PROPAGATION IN A SHALE GAS RESERVOIR WITH NATURAL AND LAYERED DISCONTINUITIES UNDER FULLY HYDROMECHANICAL COUPLING

3D NUMERICAL INVESTIGATION OF HYDRAULIC FRACTURE NETWORK PROPAGATION IN A SHALE GAS RESERVOIR WITH NATURAL AND LAYERED DISCONTINUITIES UNDER FULLY HYDROMECHANICAL COUPLING

Phase-field modeling of hydraulic fracture network propagation in poroelastic rocks

Modeling of hydraulic fracturing processes is of great importance in computational geosciences. In this paper, a phase-field model is developed and applied for investigating the hydraulic fracturing propagation in saturated poroelastic rocks with pre-existing fractures. The phase-field model replaces discrete, discontinuous fractures by continuous diffused damage field, and thus is capable of simulating complex cracking phenomena such as crack branching and coalescence. Specifically, hydraulic fracturing propagation in a rock sample of a single pre-existing natural fracture or natural fracture networks is simulated using the proposed model. It is shown that distance between fractures plays a significant role in the determination of propagation direction of hydraulic fracture. While the rock permeability has a limited influence on the final crack topology induced by hydraulic fracturing, it considerably impacts the distribution of the fluid pressure in rocks. The propagation of hydraulic fractures driven by the injected fluid increases the connectivity of the natural fracture networks, which consequently enhances the effective permeability of the rocks.

Effect of Multiple Flow Pulses on Hydraulic Fracture Network Propagation in Naturally Fractured Volcanic Rock

Exploring engineering methods for increasing fracture network complexity is important for the development of unconventional oil and gas reservoirs. In this study, we conducted a series of fracturing experiments on naturally fractured volcanic samples. An injection method, multiple flow pulses, is proposed to increase fracture complexity. The results show that fluid leaked into the natural fracture network (NFN) when the injection rate was low (0.2 mL/min); hydraulic-fracture-dominant fracture geometry was created with an injection rate of 2 and 5 mL/min. Under the 2 mL/min-injection scheme with 3 pulses, the injection pressure during the intermittent stage was low (<5 MPa), resulting in a limited increase in fracture complexity. When the number of the flow pulses increased to 5, the pressure drop rate in the fourth and fifth intermittent stage significantly increased, indicating an increase in the aperture of natural fractures (NFs) and in the fluid leak-off effect. Under the 5 mL/min injection scheme containing 5 pulses, besides the enhanced fluid leak-off, a sharp injection pressure drop was observed, indicating the activation of NFs. The complexity and the aperture of the ultimate fracture network further increased. The injection method, multiple flow pulses, can be used to create complex fracture networks effectively.

Optimal selection and effect evaluation of re-fracturing intervals in shale gas horizontal wells

The monitoring results of production logging show that almost one third of perforation clusters produce no or less gas after volumetric fracturing is initially applied in shale gas reservoirs. Besides, the production decline after the commissioning is commonly faster. In this paper, a fracture network prediction model and a fracturing well productivity prediction model were established based on microseismic interpretation data and hydraulic fracture network propagation results. After petrophysics, microseism, production performance were taken into consideration comprehensively, shale re-fracturing development potential evaluation index (RDPEI) was proposed. Then, a re-fracturing design and evaluation method was developed and targeted interval selection and evaluation was realized and applied on site. And the following research results were obtained. First, due to the heterogeneity of natural fractures, hydraulic fracture networks are more different, so an obvious “dead gas zone” can be easily formed and its re-fracturing potential is high. Second, the initial hydraulic fracture network is more affected by natural fractures. The main part of a fracture network propagates along the direction of maximum horizontal major stress, the fractures in regional stimulated intervals propagate in the form of double wing, and the length of a liquid swept fracture network is 52–70% of seismic interpretation result. Third, the RDPEI model avoids the limitations of single factor analysis and realizes the quantitative prediction on three types of indexes of recoverability, compressibility and re-fracturing. Fourth, re-fracturing of the case well is remarkable in stimulation effect. Its shale gas productivity is increased by 38.9%, and its cumulative gas production in one year is increased by 62.5%. In conclusion, re-fracturing is an effective and feasible method for improving the single well ultimate recovery reserves of shale gas. This method provides a theoretical and technical support for the selection and effect evaluation of re-fracturing intervals in shale-gas horizontal wells.

Effect of Joint Geometrical Parameters on Hydraulic Fracture Network Propagation in Naturally Jointed Shale Reservoirs

The presence of a significant amount of discontinuous joints results in the inhomogeneous nature of the shale reservoirs. The geometrical parameters of these joints exert effects on the propagation of a hydraulic fracture network in the hydraulic fracturing process. Therefore, mechanisms of fluid injection-induced fracture initiation and propagation in jointed reservoirs should be well understood to unleash the full potential of hydraulic fracturing. In this paper, a coupled hydromechanical model based on the discrete element method is developed to explore the effect of the geometrical parameters of the joints on the breakdown pressure, the number and proportion of hydraulic fractures, and the hydraulic fracture network pattern generated in shale reservoirs. The microparameters of the matrix and joint used in the shale reservoir model are calibrated through the physical experiment. The hydraulic parameters used in the model are validated through comparing the breakdown pressure derived from numerical modeling against that calculated from the theoretical equation. Sensitivity analysis is performed on the geometrical parameters of the joints. Results demonstrate that the HFN pattern resulting from hydraulic fracturing can be roughly divided into four types, i.e., crossing mode, tip-to-tip mode, step path mode, and opening mode. As β (joint orientation with respect to horizontal principal stress in plane) increases from 0° to 15° or 30°, the hydraulic fracture network pattern changes from tip-to-tip mode to crossing mode, followed by a gradual decrease in the breakdown pressure and the number of cracks. In this case, the hydraulic fracture network pattern is controlled by both γ (joint step angle) and β. When β is 45° or 60°, the crossing mode gains dominance, and the breakdown pressure and the number of cracks reach the lowest level. In this case, the HFN pattern is essentially dependent on β and d (joint spacing). As β reaches 75° or 90°, the step path mode is ubiquitous in all shale reservoirs, and the breakdown pressure and the number of the cracks both increase. In this case, β has a direct effect on the HFN pattern. In shale reservoirs with the same β, either decrease in k (joint persistency) and e (joint aperture) or increase in d leads to the increase in the breakdown pressure and the number of cracks. It is also found that changes in d and e result in the variation in the proportion of different types of hydraulic fractures. The opening mode of the hydraulic fracture network pattern is observed when e increases to 1.2 × 10−2 m.

Numerical Investigation into the Effect of Natural Fracture Density on Hydraulic Fracture Network Propagation

Hydraulic fracturing is an important method to enhance permeability in oil and gas exploitation projects and weaken hard roofs of coal seams to reduce dynamic disasters, for example, rock burst. It is necessary to fully understand the mechanism of the initiation, propagation, and coalescence of hydraulic fracture network (HFN) caused by fluid flow in rock formations. In this study, a coupled hydro-mechanical model was built based on synthetic rock mass (SRM) method to investigate the effects of natural fracture (NF) density on HFN propagation. Firstly, the geometrical structures of NF obtained from borehole images at the field scale were applied to the model. Secondly, the micro-parameters of the proposed model were validated against the interaction between NF and hydraulic fracture (HF) in physical experiments. Finally, a series of numerical simulations were performed to study the mechanism of HFN propagation. In addition, confining pressure ratio (CPR) and injection rate were also taken into consideration. The results suggested that the increase of NF density drives the growth of stimulated reservoir volume (SRV), concentration area of injection pressure (CAIP), and the number of cracks caused by NF. The number of tensile cracks caused by rock matrix decrease gradually with the increase of NF density, and the number of shear cracks caused by rock matrix are almost immune to the change of NF density. The propagation orientation of HFN and the breakdown pressure in rock formations are mainly controlled by CPR. Different injection rates would result in a relatively big difference in the gradient of injection pressure, but this difference would be gradually narrowed with the increase of NF density. Natural fracture density is the key factor that influences the percentages of different crack types in HFN, regardless of the value of CPR and injection rate. The proposed model may help predict HFN propagation and optimize fracturing treatment designs in fractured rock formations.

Model development of proppant transport through hydraulic fracture network and parametric study

A model capable of simulating proppant transport through hydraulic fracture network is developed and summarized in this paper. The proppant transport model (PTM) is able to capture multiple proppant transport patterns, including suspension, saltation and creeping. These patterns are first identified, and then quantified to establish proppant transport equations. The governing equations are programed into a three-dimensional, finite-difference model to simulate the proppant transport process. The PTM is coupled to a previously developed hydraulic fracture network propagation model, which updates essential input parameters such as fracture geometry, velocity distribution and pressure profile for each step. In every step, the proppant transport model extracts values for these parameters and solves the mass transport equations for all three patterns. Finally, the PTM generates proppant concentration, fracture conductivity and distribution throughout the created fracture network and predicts, at the end of the designed treatment the propped stimulated reservoir volume (PSRV) – a critical indicator of long-term stimulation effectiveness for hydraulically fractured oil/gas reservoirs. Parametric Studies of several important treatment, operational, reservoir, and geomechanical parameters are done in this paper to illustrate the impact of each factor on the PSRV.

Hydraulic Fracture Network Propagation Rule of Shale Reservoir

Hydraulic Fracture Network Propagation Rule of Shale Reservoir

Numerical Investigation into the Influence of Bedding Plane on Hydraulic Fracture Network Propagation in Shale Formations

Shale formations are often characterized by low matrix permeability and contain numerous bedding planes (BPs) and natural fractures (NFs). Massive hydraulic fracturing is an important technology for the economic development of shale formations in which a large-scale hydraulic fracture network (HFN) is generated for hydrocarbon flow. In this study, HFN propagation is numerically investigated in a horizontally layered and naturally fractured shale formation by using a newly developed complex fracturing model based on the 3D discrete element method. In this model, a succession of continuous horizontal BP interfaces and vertical NFs is explicitly represented and a shale matrix block is considered impermeable, transversely isotropic, and linearly elastic. A series of simulations is performed to illustrate the influence of anisotropy, associated with the presence of BPs, on the HFN propagation geometry in shale formations. Modeling results reveal that the presence of BP interfaces increases the injection pressure during fracturing. HF deflection into a BP interface tends to occur under high strength and elastic anisotropy as well as in low vertical stress anisotropy conditions, which generate a T-shaped or horizontal fracture. Opened BP interfaces may limit the growth of the fracture upward and downward, resulting in a very low stimulated thickness. However, the opened BP interfaces favor fracture complexity because of the improved connection between HFs and NFs horizontally under moderate vertical stress anisotropy. This study may help predict the HF growth geometry and optimize the fracturing treatment designs in shale formations with complex depositional heterogeneity.

Numerical investigation of hydraulic fracture network propagation in naturally fractured shale formations

Hydraulic fracture network (HFN) propagation in naturally fractured shale formations is investigated numerically using a 3D complex fracturing model based on the discrete element method. To account for the plastic deformation behavior of shales, the Drucker–Prager plasticity model is incorporated into the fracturing model. Parametric studies are then conducted for different Young's moduli, horizontal differential stresses, natural fracture (NF) properties, injection rates, and number and spacing of perforation clusters. Numerical results show that horizontal differential stress primarily determines the generation of a complex HFN. The plastic deformation of shale can reduce the stimulated reservoir volume; this is more obvious with Young's modulus of less than 20 GPa. In addition, a higher injection rate could largely increase the fracture complexity index (FCI). Moreover, increasing perforation cluster numbers per fracturing stage is beneficial for increasing the FCI, but it also increases the potential merging of neighboring fractures, which may lead to non-uniform development of HFN in far-wellbore regions. To achieve uniform development of HFN within a fracturing stage, the distribution of NFs should be fully considered. The results presented here may provide improved understanding of HFN generation and are favorable for optimizing fracturing treatment designs for shale formations.

Experimental Investigation into Hydraulic Fracture Network Propagation in Gas Shales Using CT Scanning Technology

Multistage fracturing of the horizontal well is recognized as the main stimulation technology for shale gas development. The hydraulic fracture geometry and stimulated reservoir volume (SRV) is interpreted by using the microseismic mapping technology. In this paper, we used a computerized tomography (CT) scanning technique to reveal the fracture geometry created in natural bedding-developed shale (cubic block of 30 cm × 30 cm × 30 cm) by laboratory fracturing. Experimental results show that partially opened bedding planes are helpful in increasing fracture complexity in shale. However, they tend to dominate fracture patterns for vertical stress difference Δσ v ≤ 6 MPa, which decreases the vertical fracture number, resulting in the minimum SRV. A uniformly distributed complex fracture network requires the induced hydraulic fractures that can connect the pre-existing fractures as well as pulverize the continuum rock mass. In typical shale with a narrow (<0.05 mm) and closed natural fracture system, it is likely to create complex fracture for horizontal stress difference Δσ h ≤ 6 MPa and simple transverse fracture for Δσ h ≥ 9 MPa. However, high naturally fractured shale with a wide open natural fracture system (>0.1 mm) does not agree with the rule that low Δσ h is favorable for uniformly creating a complex fracture network in zone. In such case, a moderate Δσ h from 3 to 6 MPa is favorable for both the growth of new hydraulic fractures and the activation of a natural fracture system. Shale bedding, natural fracture, and geostress are objective formation conditions that we cannot change; we can only maximize the fracture complexity by controlling the engineering design for fluid viscosity, flow rate, and well completion type. Variable flow rate fracturing with low-viscosity slickwater fluid of 2.5 mPa s was proved to be an effective treatment to improve the connectivity of induced hydraulic fracture with pre-existing fractures. Moreover, the simultaneous fracturing can effectively reduce the stress difference and increase the fracture number, making it possible to generate a large-scale complex fracture network, even for high Δσ h from 6 MPa to 12 MPa.

Development of innovative and efficient hydraulic fracturing numerical simulation model and parametric studies in unconventional naturally fractured reservoirs

The most effective method for stimulating unconventional reservoirs is using properly designed and successfully implemented hydraulic fracture treatments. The interaction between pre-existing natural fractures and the engineered propagating hydraulic fracture is a critical factor affecting the complex fracture network. However, many existing numerical simulators use simplified model to either ignore or not fully consider the significant impact of pre-existing fractures on hydraulic fracture propagation. Pursuing development of numerical models that can accurately characterize propagation of hydraulic fractures in naturally fractured formations is important to better understand their behavior and optimize their performance.In this paper, an innovative and efficient modeling approach was developed and implemented which enabled integrated simulation of hydraulic fracture network propagation, interactions between hydraulic fractures and pre-existing natural fractures, fracture fluid leakoff and fluid flow in reservoir. This improves stability and convergence, and increases accuracy, and computational speed. Computing time of one stage treatment with a personal computer is now reduced to 2.2min from 12.5min than using single porosity model.Parametric studies were then conducted to quantify the effect of horizontal differential stress, natural fracture spacing (the density of pre-existing fractures), matrix permeability and fracture fluid viscosity on the geometry of the hydraulic fracture network. Using the knowledge learned from the parametric studies, the fracture–reservoir contact area is investigated and the method to increase this factor is suggested. This new knowledge helps us understand and improve the stimulation of naturally fractured unconventional reservoirs.

Numerical Modeling of Hydraulic Fractures Interaction in Complex Naturally Fractured Formations

A recently developed unconventional fracture model (UFM) is able to simulate complex fracture network propagation in a formation with pre-existing natural fractures. A method for computing the stress shadow from fracture branches in a complex hydraulic fracture network (HFN) based on an enhanced 2D displacement discontinuity method with correction for finite fracture height is implemented in UFM and is presented in detail including approach validation and examples. The influence of stress shadow effect from the HFN generated at previous treatment stage on the HFN propagation and shape at new stage is also discussed.