Hydraulic Fracture Growth Research Articles

Competition growth of biwing hydraulic fractures in naturally fractured reservoirs

Hydraulic fracturing, combined with horizontal wells, is one of the key technologies that enables production from shale gas reservoirs. However, data from several fields in the United States verified that the total production is only contributed by a small portion of designed fractures (Miller et al., 2011). In this paper, we aim to provide an explanation about this phenomenon and propose corresponding suggestions to improve stimulation efficiency. Here, a multi-fracture propagation model in reservoirs containing cemented natural fractures (NFs) is presented based on phase field method. The fracture growth resistance of each wing for varying properties of NFs is quantitatively investigated. We found that NFs toughness, roughness and intersection angle play a vital role on the fracture growth resistance. It was demonstrated that the discrepancy of fracture growth resistance of each wing can suppress fracture propagation in heterogeneous reservoirs. Fracture propagation in mixed-regime was found to favor creation of biwing fractures, which can be used to improve stimulation performance. The simulations of simultaneous fracturing in naturally fractured formations demonstrated that the existence of NFs alters the extending paths of hydraulic fractures (HFs), which may result in fracture coalescence. In this case, the presented model can be utilized to improve stimulation efficiency through optimizing design parameters.

PROPPANT MIGRATION WITHIN A ROUGH HYDRAULIC FRACTURE

Hydraulic fracturing creates a fracture network that enhances the hydrocarbon flow from the tight reservoir where the proppant migration determines the conductivity of the propped fracture, and thus, the well productivity. Core observations from the Hydraulic Fracturing Test Site (HFTS) show that hydraulic fractures are denser than initially designed and most of them are not well propped. Understanding the proppant migration in the thin and rough fracture is crucial to the optimization of the pumping scheme in the field. In this work, a transparent rough fracture model is duplicated from a hydraulically fractured outcrop by the epoxy resin with the dimension 300 mm × 300 mm × 300 mm. The settling rate of sands is quantified in this rough fracture model under different mimicked pumping conditions, from which a model is built to help estimate the growth of propped hydraulic fracture under different pumping rates, sand ratios, sand diameters, and fracturing time during field operations. The model corrects the classic Stokes' law for proppant settlement within a narrow and rough fracture. Results indicate that the equilibrium height and migration rate of the sandbank increase with the sand ratio and decrease with the pumping rate. After being compared with results obtained from Fluent simulations, a numerical model is further proposed to predict the growth of a propped fracture in the field scale.

A new model for predicting hydraulic fracture penetration or termination at an orthogonal interface between dissimilar formations

Vertical height growth of hydraulic fractures (HFs) can unexpectedly penetrate a stratigraphic interface and propagate into neighboring layers, thereby resulting in low gas-production efficiency and high risk of groundwater contamination or fault reactivation. Understanding of hydraulic fracture behavior at the interface is of pivotal importance for the successful development of layered reservoirs. In this paper, a two-dimensional analytical model was developed to examine HF penetration and termination behavior at an orthogonal interface between two dissimilar materials. This model involves changes in the stress singularity ahead of the HF tip, which may alter at the formation interface due to material heterogeneity. Three critical stress conditions were considered to assess possible fracture behavior (i.e., crossing, slippage, and opening) at the interface. Then, this model was verified by comparing its theoretical predictions to numerical simulations and three independent experiments. Good agreement with the simulation results and experimental data was observed, which shows the validity and reliability of this model. Finally, a parametric study was conducted to investigate the effects of key formation parameters (elastic modulus, Poisson's ratio, and fracture toughness) between adjacent layers. These results indicate that the variation in the introduced parameters can limit or promote vertical HF growth by redistributing the induced normal and shear stresses at the interface. Among the three studied parameters, Poisson's ratio has the least influence on the formation interface. When the fracture toughness and elastic modulus of the bounding layer are larger than those of the pay zone layer, the influence of fracture toughness will dominate the HF behavior at the interface; otherwise, the HF behavior will more likely be influenced by elastic modulus.

Laboratory Investigation of Hydraulic Fracture Growth in Zimbabwe Gabbro

AbstractDirect measurement of the apparent toughness evolution during hydraulic fracture growth remains challenging in rocks due to the difficulty of measuring the time evolution of the fracture geometry. We report hydraulic fracturing tests performed in 250 × 250 × 250 mm Zimbabwe gabbro under different confining stress. Using time‐lapse active acoustic surveys, we reconstruct the fracture front and fracture width using scattered and transmitted waves. After verifying that hydraulic fracture growth is dominated by the energy dissipated in fracture creation such that the fluid pressure can be considered spatially uniform in the fracture (negligible viscous flow energy dissipation), we estimate the apparent fracture toughness, using the theory of linear hydraulic fracture mechanics, by combining fracture geometry and pressure data. The apparent fracture energy is higher than that measured from semicircular bending tests. The created fractures evolve in a planar and radial geometry at the macroscopic scale, but we observe overlapping segments and bridges at the millimetric scale. This complex segmentation at a scale on par with the rock grain size is likely responsible for the observed higher fracture energy at centimetric scale. Such fracture segmentation and bridging will necessarily occur when encountering heterogeneities and result in a further increase of fracture energy at a larger scale even if the overall macroscopic geometry remains planar. The experimental data set reported here should guide modeling efforts necessary to better predict hydraulic fracture growth in rock masses.

Modeling of solids particle diversion to promote uniform growth of multiple hydraulic fractures

Solid particulate additives are sometimes used to promote the uniform growth of multiple hydraulic fractures in horizontal oil and gas wells. The principle is that solid particulates block, accumulate, and form larger porous plugging zones preferentially at entrances of fracture taking in the most fluid volume. These porous zones create fluid flow resistance or additional pressure loss; thereby, inhibiting the growth of these dominant fractures and diverting fluid to suppressed fractures. While this technology is promising, governing design parameters and ramifications of placing solids diverters inside the fracture remain unclear. This paper models the propagation of multi-fractures with diverter pressure losses induced by the porous plugging zones. The resulting non-linear hydraulic fracturing problem is solved numerically with an Implicit Level Set Algorithm (ILSA) for each time step and the mechanisms of diversion are illustrated by comparing and contrasting cases with and without particle diverter. In both cases, during the fluid ramp-up period (pumping rate gradually increases from 0 to fracturing rate (QT)), the injection can be equally distributed among fractures before the stress interference affects the fluid allocation (Phase I). Then, stress interference starts to partition more fluid into outer fractures and suppress the growth of the middle fracture (Phase II). Once the perforation friction loss is sufficient to counteract the stress interaction, injection begins to shift to the middle fracture, but still gives a significantly non-uniform fracture growth (Phase III). At this point, solid diverter particles are introduced, leading to three additional phases of growth. Phase IV introduces solid diverters to the treatment at a reduced pumping rate. Particles bridge, accumulate and create porous plugging zones at the flow entrance. A higher pressure drop in outer fractures diverts injection fluids to the middle fracture. Phase V resumes the treatment rate to QT without diverter. The increased pump rate in turn increases the pressure drop in outer fractures and diverts more fluids to the middle fracture. This results in a rapid extension velocity for the middle fracture, enabling it to have the chance to catch up with the longer outer fractures (in Phase VI). This process is controlled by the interplay among stress interference, perforation friction loss, and diverting pressure drop. These simulations demonstrate that a model-based optimization could improve the effectiveness of the diverter technology and promote a uniform multi-fracture growth.

Three-dimensional buoyant hydraulic fractures: constant release from a point source

Hydraulic fractures propagating at depth are subjected to buoyant forces caused by the density contrast between fluid and solid. This paper is concerned with the analysis of the transition from an initially radial fracture towards an elongated buoyant growth – a critical topic for understanding the extent of vertical hydraulic fractures in the upper Earth crust. Using fully coupled numerical simulations and scaling arguments, we show that a single dimensionless number governs buoyant hydraulic fracture growth, namely the dimensionless viscosity of a radial hydraulic fracture at the time when buoyancy becomes of order 1. It quantifies whether the transition to buoyancy occurs when the growth of the radial hydraulic fracture is either still in the regime dominated by viscous flow dissipation or already in the regime where fracture energy dissipation dominates. A family of fracture shapes emerge at late time from finger-like (toughness regime) to inverted elongated cudgel-like (viscous regime). Three-dimensional toughness-dominated buoyant fractures exhibit a finger-like shape with a constant-volume toughness-dominated head and a viscous tail having a constant uniform horizontal breadth: there is no further horizontal growth past the onset of buoyancy. However, if the transition to buoyancy occurs while in the viscosity-dominated regime, both vertical and horizontal growths continue to match scaling arguments. As soon as the fracture toughness is not strictly zero, horizontal growth stops when the dimensionless horizontal toughness becomes of order 1. The horizontal breadth follows the predicted scaling.

Controlling Hydraulic Fracture Growth Through Precise Vertical Placement of Lateral Wells: Insights from HFTS Experiment and Numerical Validation

Controlling Hydraulic Fracture Growth Through Precise Vertical Placement of Lateral Wells: Insights from HFTS Experiment and Numerical Validation

Simultaneous propagation of hydraulic fractures from multiple perforation clusters in layered tight reservoirs: Non-planar three-dimensional modelling

In this paper, a hydromechanical coupled finite-discrete element method, which considers the non-planar three-dimensional growth, pressure continuity along the horizontal well, dynamic flow rate distributions among clusters, perforation friction, and fracturing fluid leakage, is employed to simulate the simultaneous growth of hydraulic fractures from an array of five perforation clusters in tight reservoirs interbedded with alternating stiff and soft layers. The simulation results highlight that the stress shadow induced by the non-planar propagation of the outmost hydraulic fractures stops the planar growth of the interior and middle hydraulic fractures and causes uneven fracturing fluid distribution among perforation clusters. The results demonstrate that the generated fracture pattern in the stage becomes more symmetric overall with the decreasing modulus of the soft layers. As the soft layer's modulus decreases, the total fracture height decreases significantly, but the local fracture aperture distribution increases, which leads to the reduction of total fracture area and leak-off volume of fracturing fluid as well as the increase of total fracture volume. The total fracture area decreases with the increasing leak-off coefficient and perforation number, but the total leak-off volume and total fracture volume increase. The violation of the fluid pressure continuity by without considering the dynamic flow rate distributions overestimates the growth of the interior and middle hydraulic fractures and produces a smaller total fracture area. It is also found that the adjustment of pumping rate is more effective than using nonuniform cluster spacing in promoting the simultaneous hydraulic-fracture growth in layered tight reservoirs.

Investigation into Hydraulic Fracture Propagation Behavior during Temporary Plugging and Diverting Fracturing in Coal Seam

Temporary plugging and diverting fracturing (TPDF) is widely used to improve the stimulation effectiveness in coal seam. To study the fracture propagation behavior during TPDF in coal formation, a series of laboratory hydraulic fracturing experiments were performed on natural coal samples. Based on the results of sample splitting and fracture reconstruction, the influences of horizontal stress difference and the size of temporary plugging agent (TPA) as well as the concentration of TPA on hydraulic fracture growth were analyzed. Experimental results show that TPDF is beneficial for improving the fracture complexity even under high stress difference of 8 MPa. When the TPA of small particle size (70/100 mesh) was applied, the primary fracture could not be fully blocked whereas increasing the particle size of TPA to 20/40 mesh tended to cause accumulation and bridging in the wellbore, resulting in an abnormally high fracturing pressure. TPA with particle size of 40/70 mesh tended to be a reasonable choice for the target formation, as it could form effective plugging in primary fractures and promote the generation of new fractures. Meanwhile, optimizing the concentration of TPA was also conducive to improving the plugging effectiveness. Effective temporary plugging can be achieved by using appropriate TPA of proper size and concentration, which varies with different treatment parameters and formations. Laboratory experiments are expected to provide guidance for the parameter optimization for TPDF in coal seam.

Numerical study of simultaneous growth of multiple hydraulic fractures from a horizontal wellbore combining dual boundary element method and finite volume method

Horizontal well and multi-stage hydraulic fracturing have been extensively used to extract unconventional oil/gas. The fracture pattern created from the multiple fractures determines the surface area of the reservoir in contact with the wellbore, thus influencing the overall quality of the multi-stage fracturing. Therefore, a good understanding of the HF propagation behavior is of importance for designing the perforation layout. In this paper, a new fully coupled hydraulic fracturing model is developed by combining the dual boundary element method (DBEM) that describes the rock matrix deformation and the finite volume method (FVM) that simulates the fluid flow in the fracture. The DBEM applies displacement boundary integral equation to one crack surface and traction boundary integral equation to the other. The model presented is first validated against the existing semi-analytical and numerical solutions for single and two fractures in the infinite domain. Then the impact of spacing, in-situ stress difference and injection parameters on the competitive growth behavior between multiple HFs is investigated. A parameter formulated in terms of the ratio of fluid volume allocated to different fractures is proposed to be the indicator of simultaneous or preferential propagation. The results show that less isotropic in-situ stress and a larger fluid viscosity or injection rate tend to facilitate simultaneous growth of multiple fractures, in which the influence of the in-situ stress difference is enhanced while that of the injection parameters is weakened when increasing the fracture spacing.

Secondary growth and closure behavior of planar hydraulic fractures during shut-in

The evolution of fractures during shut-in after hydraulic fracturing is an important topic in petroleum engineering. Considering the closure and secondary expansion of fractures during shut-in can further improve the accuracy of predicting hydraulic fracture parameters. Based on linear elastic fracture mechanics, elastic mechanics, and the implicit level set algorithm, a numerical model of planar hydraulic fracture propagation was established in this study. In the proposed model, the reservoir was considered as a homogeneous elastic medium, and the fluid loss was characterized using Carter's filtration model. The secondary propagation and fracture closure behavior during shut-in could be simulated by solving the strongly nonlinear system of fluid and stress coupling. Based on this model, the evolution behavior of hydraulic fractures during injection and shut-in was analyzed. According to the variation characteristics of the fracture length, the evolution process could be divided into three stages: fracture propagation during injection, secondary growth, and fracture stopping (but not closing). According to the variation characteristics of the fracture opening and net pressure, the evolution process could be divided into three stages: nonlinear increase, linear decrease, and gradual decrease. For low-permeability reservoirs, fracture closure and secondary propagation may take several times the injection time after shut-in, and the secondary propagation length may reach tens of meters. The results show that the larger the filtration coefficient, the faster the fracture closure will be, and the shorter the secondary propagation distance. The higher the viscosity of the fracturing fluid, the slower the fracture closure will be, while the secondary propagation distance is almost unaffected. The fracture toughness has little effect on the fracture closure and secondary propagation. The crack will close first in the region with large interlayer stress during shut-in. The findings of this study can help for better understanding of the evolution mechanism of fractures during shut-in and closure.

Multi-fracture nonuniform initiation and vertical propagation behavior in thin interbedded tight sandstone: An experimental study

Thin interbedded tight sandstone of Shanxi Formation in Ordos basin, China, contains mudstone interlayers and laminas universally, and exhibits ultra-low matrix permeability, low brittleness, and areal heterogeneity. The stimulation effectiveness of this formation depends largely on whether multiple hydraulic fractures (HFs) can initiate and penetrate into the multiple thin sandstone layers upward and downward. To clarify the multi-fracture growth behavior of such formation, multi-cluster fracturing experiment in the horizontal well was performed on specimens prepared from the sandstone-mudstone outcrops of Shanxi Formation based on a true triaxial fracturing simulation system. The influences of interlayer stress difference, mudstone thickness, fluid viscosity, pumping rate and the number of clusters were mainly analyzed through post-fracturing specimen splitting and pressure curve analysis. Results show that the difference of rock mechanical parameters between sandstone and mudstone is relatively large. When interlayer stress difference is less than 3 MPa, the mudstone layer cannot function as a barrier to restrain the vertical growth of HFs, and the essential mechanism causing HF height containment is mainly the opening of laminas or/and interfaces. By contrast, when the interlayer stress difference is equal to or greater than 3 MPa and the dimensionless thickness of mudstone is more than 0.4, the HF height tends to be restrained. Increasing the fluid viscosity or/and pumping rate can reduce filtration, and facilitates HFs penetrating through the laminas or interfaces and consequently propagating into adjacent layers. It has been observed that when fluid viscosity reaches 100 mPa s (cross-linked gel) and pumping rate is 100 mL/min, HFs can pass through the overlaying mudstones. However, uniform initiation of all clusters is difficult to achieve due to the low brittleness of sandstone and heterogeneity along the horizontal wellbore. The experimental results prove that temporary plugging within the wellbore using the plugging agent of appropriate particle size is necessary to create multiple HFs in such formation.

Experimental and numerical investigations on hydraulic fracture growth using rock-like resin material containing an injecting inner pre-crack

A new transparent resin material with a compression-tension strength ratio of up to 6.6 at −15∼-10 °C has been developed. It possesses more brittle fracture properties than before and can competently simulate many kinds of engineering rocks. The fabrication demands strict temperature control and treatments. Specimens are inventively made with a hollow injecting inner pre-crack. Based on self-designed water injection devices and low-temperature loading equipment, uniaxial and biaxial hydraulic fracturing experiments are carried out under fixed water pressures. The specimens' uniaxial hydraulic failure process can be separated into four stages. At each stage, the variation of water injection is analysed. For all experiments, both crack initiation stress and peak strength have declined significantly, by more than 80% and 70% compared with dry specimens. The evolution of wrapping wing cracks and fin-like cracks in biaxial experiments has rarely been reported before. Moreover, numerical verification is conducted by FLAC3D. A novel fluid-solid coupled model has been developed that takes into account both the pre-peak damage and post-peak sharp degeneration. The principles are dependent on the element's failure type, i.e., tensile failure, shear failure, or a combination of the two. The mechanical parameters and permeability coefficient of damaged elements are redefined. The simulation results match well with experiments, demonstrating the feasibility of this method. Finally, the proposed model is applied to explore the hydraulic failure of the specimen under triaxial compression with fixed stress. The impact of injecting pre-crack on hydraulic fracture growth is illustrated.

Fast-running model for high-volume hydraulic fracturing

We develop a rapid simulator of hydraulic fracture growth in complex geologic layered conditions and extensively drilled multistage fractured wells in a reservoir. The simulator allows running independent simulations for thousands hydraulic fractures within a minute on modern personal computers. The model is meshless and has a simplified rectangular fracture shape; however, coupling all conventional hydraulic fracture mechanics equations makes the model accurate enough. We demonstrate it via comparison with exact analytical solutions in limiting toughness-, viscosity-, and leakoff-dominated regimes, as well as via comparison with other commercial simulators on real field cases. Field validation of the model by temperature log measurements is also provided.To demonstrate the practical implications of the model for reservoir engineering, we show several examples of numerical simulations for a huge number of hydraulic fractures in a reservoir, which interact with each other due to the closeness of stimulated wells and perforation clusters. Rapid simulations allow obtaining the field-scale simulations of fracture growth in the range of a minute and efficiently building distributions of asymmetric fracture growth both in length and in height. We show that the stress shadow effect causes undesired outbreaks to adjacent gas- or water-saturated geological layers if the fracture placement in a reservoir is dense enough. Even small spatial misalignment of stages in the offset wells may result in changes of geometry of transverse fractures growing from neighbored wells. Vertical true vertical depths mismatch in offset wells; their deviations in the dip and azimuth angles are shown to cause the asymmetry of fracture growth as well, which hardly can be predicted in field development workflows without rigorous fracture simulations. Examples of longitudinal fracturing in horizontal wells demonstrate the strongest distortion of conventionally assumed lateral symmetry and height growth similarity of fractures created in one horizontal well. Our simulations also show that these results are affected by the viscosity of pumped fracturing fluids. The presented model of field-scale interactive fracture growth in a reservoir enables finding the best fracture placement characteristics and pumping schedule for the needs of field development with hundreds to thousands of fractures in a short time frame.

Predicting fracture vertical growth containment using the width-induced net stress

The vertical growth of hydraulic fractures in layered formations is important from treatment-placement and well performance perspective. Most numerical fracture simulators generate fracture geometries by accounting for the in-situ stress and rock mechanical properties, along with key parameters related to fracturing fluids such as rheology and leakoff behavior, amongst various other critical parameters that can influence the outcome. Although the results from various simulators are generally reasonable, the fracture height estimates can vary significantly even for identical input data sets as shown in the literature. Because of the limitations of these simulators, some of the field observations, such as containment of fracture height growth across certain interfaces of contrasting material properties or weak interfacial bonding, are not replicated effectively, unless such an interface is pre-defined.In this study, the influence of fracture width on resultant stresses is incorporated in the calculation process while solving for vertical growth of hydraulic fractures. For this purpose, a modified equilibrium height growth model previously developed by the authors is used. The effects of viscous fluid movement in the fracture are also included in the calculation scheme.The outputs from the model were compared with the field-derived fracture heights that were inferred from micro seismic (MS) surveys conducted on various fracturing treatments that included both vertical and horizontal wells completed in layered formations. The analysis revealed a close agreement between the model-predicted and observed values of fracture height.While the authors acknowledge that predicting the containment of vertical growth of fracture across a plane is a challenging task given the complex nature of the problem, the paper discusses a method that offers a simpler approach to predicting the sites that may act as a constraint to the fracture growth during the stimulation treatments. This can aid in well-placement planning, perforation strategy, and hydraulic fracturing treatment design. The model can be readily deployed or incorporated in existing simulators.

Improving Fracture Complexity and Conductivity in Shale Formation with Calcite-Filled Natural Fractures by a Novel CO2-Assisted Fracturing: An Experimental Study

Summary Given the advantages of using CO2 as a fracturing fluid to enhance unconventional oil/gas production and urge of carbon neutrality, CO2-assisted fracturing draws increasing attention in China recently. However, several critical issues related to this fracturing technology, such as the mechanism of hydraulic fracture (HF) growth, still need to be clarified. A novel CO2-assisted fracturing design, which can increase the HF complexity and conductivity, as well as improve the porosity/permeability of surrounding rock matrix, bedding planes (BPs), and natural fractures (NFs), was proposed. In the design, the carbonated water, formed by dissolving surpercritical CO2 in the slickwater, is used as the slug fluid to soften the calcite-sealed NFs that intersect with the precreated HFs. Subsequently, the slickwater is injected as the carrying fluid to dilate the NFs. To verify this design, a series of true triaxial fracturing simulations and static soaking experiments were conducted on the Longmaxi shale in Sichuan basin, China. Scanning electron microscopy results show that carbonated water, a weakly acidic fluid, can react vigorously with the carbonate-rich shale with time going on, thereby resulting in numerous dissolved pores with the diameter of dozens of microns. Eventually, the reaction between rock and carbonated water increases porosity/permeability and reduces mechanical strength. Notable dissolution of calcite, which could soften the calcite-sealed NFs, can occur in a short time (0.5 hours). Pretreating the specimen with carbonated water can lower the breakdown pressure of the rock by 2.7 MPa for half an hour and 11.7 MPa for 2 hours and promote HFs to propagate along the BPs and NFs in the shear-dominant mode. The shear dislocation and uneven erosion of fracture surface are of great significance in improving the permeability or conductivity of HFs. Notably, well shut-in for an optimized period may allow the sufficient interaction between carbonated water and shale, thereby improving the effectiveness of composite fracturing. This innovative design, which takes advantage of the special physical-chemical properties of supercritcal CO2, is feasible and conducive to enhancing production from unconventional reservoirs.

Experimental Study on Fracture Propagation Mechanism of Shale Oil Reservoir of Lucaogou Formation in Jimusar

The lithology of shale oil reservoir of Lucaogou Formation in Junggar Basin, China shows great variation in a vertical direction and develops bedding planes (BPs). In such formation, rock properties and fabrics have a significant impact on stimulation effects. To clarify the fracture propagation mechanism in a vertically heterogeneous reservoir, an experimental study on fracture propagation in layered rock samples with complex lithology has been conducted. The effect of layers on the height of hydraulic fractures (HFs) was analysed based on triaxial hydraulic fracturing simulation system combined with mineral and mechanical characteristics analysis. The research shows that when the HF is initiated in siltstone layer, it tends to penetrate BPs with the dimensionless fracture height of more than 0.74. When HF is initiated in mudstone layer, the vertical growth of HFs tends to be terminated at the BPs, and thefracture height is constrained. The greater the thickness of the interlayer is, the more likely the HFs tend to be cut off at the interface and propagate along the interface, resulting in the limited fracture height. Under high horizontal stress difference, HFs are relatively straight. Due to the high permeability of BPs and the low viscosity of fracturing fluid, the fluid leakoff into BPs is observed, which is not conducive to the vertical propagation of HFs. Increasing the viscosity of fracturing fluid facilitates HFs to penetrate the high-permeability BPs and improves the vertical stimulated volume of shale oil reservoir.

Multiple hydraulic fractures growth from a highly deviated well: A XFEM study

A fully coupled extended finite element (XFEM) model is presented to investigate the effect of different well types (highly deviated and horizontal wells) on simultaneous growth of multiple fractures. The importance of the use of deviated wells is briefly described and the governing equations for multi-cluster hydraulic fracturing in a saturated porous media are stated. The weak forms of both stress equilibrium and fluid mass continuity equations are turned into a system of linear equations through XFEM-type enrichments in space and Newmark scheme in time, which are solved by Newton-Raphson iteration method. In addition, the secant method is employed to impose the pressure continuity and mass conservation conditions at the fracture-well intersections. A numerical example with considering the simultaneous propagation of four hydraulic fractures is first adopted to validate the proposed numerical model. Several examples are then employed to investigate the influence of operational parameter, deviation angle, fracture spacing, placement and number on final fracture patterns. Numerical results show that coefficient of variation in multiple fracture heights for high-angle well is lower than that for horizontal well for all fracture placements. The opposite growth directions for two neighboring fractures, partially arising from the height difference at fracture-well intersection points, can reduce the stress shadow effect, thus promoting uniform growth of multiple fractures. Those results potentially unveil the causes for higher oil and gas production rates measured after multi-cluster hydraulic fracturing along highly deviated wells.

Hydraulic fracture height growth in layered rocks: Perspective from DEM simulation of different propagation regimes

A propagating fluid driven fracture in a rock mass is expected to interact with geological interfaces on a wide variety of length scales. The vertical growth of hydraulic fractures in layered rocks is of pivotal importance for the successful stimulation in reservoir development. In this study, 2D discrete element modeling is used to investigate the influence of the stiffness and toughness ratio, as well as stress contrast between layers on the hydraulic fracture height growth. In particular, the ultimate goal is to better understand mechanisms of the fracture height containment by contrasts of different rock properties and to quantitatively determine which parameters provide a stronger influence. In addition, the analysis is performed in the context of hydraulic fracture regimes, whereby the dominant dissipation mechanism in the system can either be associated with fracture toughness or viscous fluid flow. As a starting point, we investigated the propagation of a plane strain hydraulic fracture from a low stiffness layer to a high stiffness layer and vice versa, while keeping the stress constant. The influence of stress on hydraulic fracture propagation in layered rocks is investigated afterwards. The numerical results demonstrate that the hydraulic fracture can either directly pass through the geological interface, be arrested at the interface, or stop before reaching the interface. The interface itself is assumed to be perfectly bonded, therefore no slippage is considered. Ability of the hydraulic fracture to approach the interface is first determined by the elastic modulus ratio of the two adjacent layers. Once reached the interface, the further growth is then affected by the toughness ratio between the layers. After that, if the fracture crosses the interface, then it is affected by the stress contrast. The propagation regime has an important influence on the fracture propagation in layered rocks. If the propagation regime is closer to the viscosity dominated, the hydraulic fracture is likely to cross the interface. In contrast, it is more difficult for a fracture to cross the barrier if the propagation regime is near the toughness dominated. A map of fracture crossing behavior versus propagation regime and contrast in properties has been constructed, that can be used to quantify strength of mechanical barriers and to deduce hydraulic fracture height growth behavior for various scenarios.

Stratigraphically Controlled Stress Variations at the Hydraulic Fracture Test Site-1 in the Midland Basin, TX

We investigated the relationship between stratigraphy, stress, and microseismicity at the Hydraulic Fracture Test Site-1. The site comprises two sets of horizontal wells in the Wolfcamp shale and a deviated well drilled after hydraulic fracturing. Regional stresses indicate normal/strike-slip faulting with E-W compression. Stress measurements in vertical and horizontal wells show that the minimum principal stress varies with depth. Strata with high clay and organic content show high values of the least compressive stress, consistent with the theory of viscous stress relaxation. By integrating data from core, logs, and the hydraulic fracturing stages, we constructed a stress profile for the Wolfcamp sequence, which predicts how much pressure is required for hydraulic fracture growth. We applied the results to fracture orientation data from image logs to determine the population of pre-existing faults that are expected to slip during stimulation. We also determined microseismic focal plane mechanisms and found slip on steeply dipping planes striking NW, consistent with the orientations of potentially active faults predicted by the stress model. This case study represents a general approach for integrating stress measurements and rock properties to predict hydraulic fracture growth and the characteristics of injection-induced microseismicity.