Hydraulic Fracture Growth Research Articles

Fully coupled hydro–mechanical controls on non-diffusive seismicity triggering front driven by hydraulic fracturing

The spatio–temporal evolution of fluid-injection-induced seismicity is often bounded by a triggering front that expands away from the injection point in space and time. For some injection scenarios, the triggering front is thought to be directly linked to pore pressure diffusion, but in the case of hydraulic fracturing, the stress interaction of the growing tensile fracture with natural joints may be more significant. In order to explore the concept of a triggering front in this context, we use a fully coupled hydro–mechanical finite-discrete element (FDEM) approach to simulate microseismicity induced by hydraulic fracture growth. The medium contains a network of randomly oriented pre-existing fractures that are activated based on the Mohr–Coulomb failure criterion. As expected, the primary triggering front is defined by the envelope of microseismicity that tracks the hydraulic fracture, although more distal events are triggered by mechanical stress changes beyond the bounds of the triggering front. However, these distal events are approximately synchronous with initiation of the hydraulic fracture and are attributed to far-field elastic perturbations associated with the stress wave spread in the medium. A field example indicates that patterns of seismicity that emerge from our simulations have characteristics similar to observed microseismicity during hydraulic fracturing.

Reduced order model for simultaneous growth of multiple closely-spaced radial hydraulic fractures

A new reduced order model (ROM) provides rapid and reasonably accurate prediction of the complex behavior of multiple, simultaneously growing radial hydraulic fractures. The method entails vastly reducing the degrees of freedom typically associated with fully-coupled simulations of this multiple moving boundary problem by coupling together an approximation of the influence of the stress interaction among the fractures (“stress shadow”) with an approximation of fluid flow and elasticity, ensuring preservation of global volume balance, global energy balance, elasticity, and compatibility of the crack opening with the inlet fluid flux. Validating with large scale (“high-fidelity”) simulations shows the ROM solution captures not only the basic suppression of interior hydraulic fractures in a uniformly-spaced array due to the well-known stress shadowing phenomenon, but also complex behaviors arising when the spacing among the hydraulic fractures is non-uniform. The simulator's usefulness is demonstrated through a proof-of-concept optimization whereby non-uniform spacing and stage length are chosen to maximize the fracture surface area and/or the uniformity of growth associated with each stimulation treatment.

Numerical model for a penny-shaped hydraulic fracture driven by laminar/turbulent fluid in an impermeable rock

As hydraulic fracturing at high injection rates with low viscosity fluids grows in popularity, so also there is a growing need to include not only the more common laminar fluid flow, but also the turbulent and transition flow regimes in numerical simulators. One common scenario is embodied in the behavior of a radial (penny-shaped) hydraulic fracture where flow is turbulent near the inlet, laminar near the tip, and in transition somewhere between. The main goal of this paper is to investigate the impact of this transition on hydraulic fracture growth through development and use of a numerical simulator for penny-shaped hydraulic fractures using the so-called drag reduction method to estimate the friction factor inside the crack for all relevant flow regimes. Upon solving this problem numerically for the case of zero toughness, comparing the results with fully laminar and fully turbulent asymptotic solutions shows that the early time behavior of radial hydraulic fractures is predominantly turbulent while large time behavior if predominantly laminar. The time scale associated with this transition determines the relevance of either limiting regime to practical cases, i.e. when the transition takes place in a small fraction of the total treatment time it suffices to approximate growth using the laminar asymptotic solution and when the transition requires are large time compared to the treatment time it suffices to approximate growth using the turbulent asymptotic solution.

Modeling simultaneous initiation and propagation of multiple hydraulic fractures under subcritical conditions

Modeling the simultaneous propagation of multiple hydraulic fractures is important for stimulation of horizontal oil and gas wells. A new numerical model for the initiation and subsequent propagation of multiple hydraulic fractures allows the fractures to propagate under subcritical conditions. Including subcritical growth enables demonstration of the importance of time-dependent hydraulic fracture initiation and its impact on the subsequent growth of multiple hydraulic fractures, indicating that this phenomenon can strongly impact the behavior of simultaneously-growing hydraulic fractures, including reducing the suppression of some fractures during growth and reducing the pressure required to sustain fracture propagation.

In the Battle Against Frac Hits, Shale Producers Go to New Extremes

A new plan has been put to work in the Permian Basin’s remote but resource-rich swath of land shared by Texas and New Mexico. Its objective can be reduced to this simple idea: protect neighboring horizontal wells from each other by drilling and completing them at the same time. Most in the shale business know these projects as “cube developments.” Their scope of work has moved operators away from developing wells one at a time to a half dozen or more at a time. Each cube project is done from supersized well pads that host four to six rigs, two pressure pumping fleets, and hundreds of people every day. From the surface perspective, these onshore megaprojects are delivering much needed economies of scale on everything from sand and water to parts and labor. However, the bigger motivation lies deep in the ground. That is where shale producers have been battling poor production results for years because of frac hits between older and newer wells, often referred to as “parent” and “child” wells. The root of this complex problem lies in the fact that a child well’s hydraulic fractures often follow the path of least resistance into a reservoir’s most resource-depleted zones, rather than to areas containing the best reserves. In some parts of the Permian, the effect has caused child wells to deliver a 30% lower recovery rate than their parents (when factors such as well lengths are normalized). When such production shortfalls are felt fieldwide, the losses are measured in millions of dollars per day. The point of cube developments is to put an end to this cycle by creating only parent wells. Thinking Inside the Cube Occidental Petroleum began implementing its own version of the cube approach—called “optimized sequenced development”—last summer at its Greater Sand Dunes project in New Mexico. This year, the Permian stalwart says new wells brought on line there have turned in “basin-leading” peak 30-day rates that averaged around 3,100 BOE/D. The Houston-based firm’s approach relies on a strong understanding of geomechanics to sequence the drilling, completion, and eventual flowback of multiple wells to mitigate frac hits. This allows some wells to be produced, while others nearby are still being drilled or hydraulically fractured, said Oscar Quintero, the president and general manager of Oxy’s Permian assets in New Mexico. If done correctly, and critical rock properties are entered into the equation, then “you have vertical isolation, and you have horizontal isolation” of each well’s hydraulic fracture growth, said Quintero. “So, by design, we are avoiding the impact of frac hits.” This succinct outline of the high-density approach boils down a long list of subsurface nuances, ones that remain an intense area of study for the shale sector. Understanding them helps explain why Oxy and a growing number of its peers would go to the lengths of drilling so many wells simultaneously.

Impact of Fluid Acidity on the Time-Dependent Initiation of Hydraulic Fractures in Carbonate Rocks

Carbonate-rich rocks are commonly encountered in oil and gas reservoirs, and as such, mechanisms of hydraulic fracture initiation and growth in carbonates are important for effective reservoir stimulation. Thus motivated, this paper shows the impact of acidic fluid on the hydraulic fracture initiation in laboratory experiments. The results demonstrate that compared to water injection, acid injection results in more rapid initiation of the hydraulic fractures under so-called static fatigue or pressure-delay conditions wherein a certain pressure, insufficient to instantaneously generate a hydraulic fracture, is maintained until a hydraulic fracture grows. Acid injection also is shown to generate a dissolution cavity in the vicinity of the wellbore, and the breakdown of the specimen is observed to be explosive in the case of acid injection, probably due to the generation and the subsequent rapid expansion of carbon dioxide as a part of the dissolution reaction. Finally, the time to breakdown is shown to be related not only to the magnitude of the wellbore pressure, but also to the apparent permeability of the specimen. Altogether, the results indicate first that acid injection has the potential to improve the initiation of multiple hydraulic fractures within multistage hydraulic fracturing of horizontal wells by decreasing the time required for initiation at subcritical wellbore pressures. The results also show that the current theoretical framework can capture the overall negative exponential relationship between the time to breakdown and the wellbore pressure, but it is insufficient to account for the secondary dependence on rock permeability.

Acoustic Emission Response of Laboratory Hydraulic Fracturing in Layered Shale

Understanding the generation process of complex fracture network is essential for optimizing the hydraulic fracturing strategy in shale formations. In this study, laboratory fracturing was performed on shale specimens containing multiple bedding planes (BPs) combined with acoustic emission (AE) monitoring and computerized tomography scanning techniques. The injection pressure curve and the time dependency and hypocenter mechanisms of AE events in different stages were analyzed in detail. The relationship between AE spatial localization and hydraulically connected region were then further quantitatively discussed. Experimental results show that the characteristics of the pressure curve and AE response reflect well the hydraulic fracture (HF) growth behavior in layered shale. Shear events were detected around some weak BPs far away from the wellbore before the HF initiation. Stable injection pressure and a few AE events with low amplitude along the BP may indicate the stage of fluid leak-off. Numerous shear and tensile AE events and drastic pressure changes occur during the generation of a fracture network including breakdown in rock matrix and activation of multiple BPs. The shear instability of weak BPs caused by the stress perturbation during pressurization and HF growth tends to result in overestimation of the effective stimulated reservoir volume/hydraulically connected region.

A model for hydraulic fracture growth across multiple elastic layers

Typical stress conditions in gas reservoirs consisting of multiple thin coal seams interlayed with shales, tuffs and sandstones, often lead to generation of a planar vertical hydraulic fracture. A pseudo-3D model, in which the growth of the planar hydraulic fracture occurs through multiple horizontal layers with different elastic properties, is developed to account for the effects of modulus contrasts on fracture shapes. In this model, plane strain deformation is assumed for pseudo-3D cells that have uniform cross-sectional pressure distribution, and the horizontal fluid flow is simplified to be one dimensional. The vertical and horizontal fracture growth are controlled in the model by two failure criteria, respectively. Viscous fluid friction effects are included for vertical growth and a correction factor is applied to the horizontal failure criterion to adjust the propagation speeds. The numerical results for different values of the correction factor are presented for a vertically planar fracture propagating in a homogeneous rock subject to stress contrasts. Fitting the pseudo-3D results to fully-3D results provides a means to determine the correlation factor that is found to be a function of material constants and cell length. The correlation factor obtained is then extended to hydraulic fracture propagation in a layered rock mass. There are two options in choosing material constants for the correlation factor and their results are examined. Both choices demonstrate the same varying trends for fracture height and propagation speed. The existence of softer coal seams retards upward fracture growth, with a stepwise injection pressure associated with the discontinuous upward growth.

Impact of the anisotropy of fracture toughness on the propagation of planar 3D hydraulic fracture

Sedimentary rocks often exhibit a transverse isotropy due to fine scale layering. We investigate the effect of the anisotropy of fracture toughness on the propagation of a planar 3D hydraulic fracture perpendicular to the isotropy plane: a configuration commonly encountered in sedimentary basins. We extend a fully implicit level set scheme for the simulation of hydraulic fracture growth to the case of anisotropic fracture toughness. We derive an analytical solution for the propagation of an elliptical hydraulic fracture in the toughness dominated regime—a shape which results from a particular form of toughness anisotropy. The developed numerical solver closely matches this solution as well as classical benchmarks for hydraulic fracture growth with isotropic toughness. We then quantify numerically the transition between the viscosity dominated propagation regime at early time—where the fracture grows radially—to the toughness dominated regime at large time where the fracture reaches an elliptical shape in the case of an elliptical anisotropy. The time scale at which the fracture starts to deviate from the radial shape and gets more elongated in the direction of lower toughness is in accordance with the viscosity to toughness transition time-scale for a radial fracture defined with the largest value of fracture toughness. Similarly, the toughness dominated regime is fully reached along the whole fracture front when the time gets significantly larger than the same transition time-scale defined with the lowest value of toughness. Using different toughness anisotropy functions, we also illustrate how the details of the complete variation of fracture toughness with propagation direction governs the final hydraulic fracture shape at large time. Our results highlight toughness anisotropy as a possible hydraulic fracture height containment mechanism as well as the need for its careful characterization beyond measurements in the sole material axes (divider and arrester) directions.

Modeling of curving hydraulic fracture propagation from a wellbore in a poroelastic medium

Understanding near-wellbore hydraulic fracture behaviors is vital for hydraulic fracturing treatments and other injection-related operations in the petroleum industry. This paper presents a fully coupled fluid flow and geomechanics model for growth of hydraulic fractures in the near-wellbore region. The model is developed within the framework of the extended finite element method (XFEM). Fracture initiation and propagation, fracturing fluid flow, rock deformation, and pore fluid flow are coupled into the XFEM framework. The model is validated against experimental results in the literature. Capabilities of the proposed model for capturing fracture geometry, fluid flow, and local stress and pore pressure distributions are illustrated with numerical examples. A parametric study is carried out using the model to investigate a few operational parameters’ effects on near-wellbore fractures. Some recommendations are provided for reducing fracture tortuosity and breakdown pressure based on the results of the parametric study. The XFEM model proposed in this paper provides an efficient tool to predict arbitrary hydraulic fracture growth in the wellbore vicinity. It can be used to aid designs of various hydraulic fracturing related operations in the petroleum industry, such as fracturing stimulations, injectivity tests, waterfloods, and waste injections.

Influence of perforation erosion on multiple growing hydraulic fractures in multi-stage fracturing

In multi-stage hydraulic fracturing, the limited-entry method is widely used to promote uniform growth of multiple fractures. However, this method's effectiveness may be lost because the perforations will be eroded gradually during the fracturing period. In order to study the influence of perforation erosion on multiple growing hydraulic fractures, we combined the solid–fluid coupled model of hydraulic fracture growth with an empirical model of perforation erosion to implement numerical simulation. The simulations show clearly that the erosion of perforation will significantly deteriorate the non-uniform growth of multiple fractures. Based on the numerical model, we also studied the influences of proppant concentration and injection rates on perforation erosion in multi-stage hydraulic fracturing. The results indicate that the initial erosion rates become higher with the rising proppant concentration, but the growth of multiple hydraulic fractures is not sensitive to the varied proppant concentration. In addition, higher injection rates are beneficial significantly to the limited-entry design, leading to more uniform growth of fractures. Thus, in multi-stage hydraulic fracturing enough high injection rates are proposed to keep uniform growths.

On the link between stress field and small-scale hydraulic fracture growth in anisotropic rock derived from microseismicity

Abstract. To characterize the stress field at the Grimsel Test Site (GTS) underground rock laboratory, a series of hydrofracturing and overcoring tests were performed. Hydrofracturing was accompanied by seismic monitoring using a network of highly sensitive piezosensors and accelerometers that were able to record small seismic events associated with metre-sized fractures. Due to potential discrepancies between the hydrofracture orientation and stress field estimates from overcoring, it was essential to obtain high-precision hypocentre locations that reliably illuminate fracture growth. Absolute locations were improved using a transverse isotropic P-wave velocity model and by applying joint hypocentre determination that allowed for the computation of station corrections. We further exploited the high degree of waveform similarity of events by applying cluster analysis and relative relocation. Resulting clouds of absolute and relative located seismicity showed a consistent east–west strike and 70° dip for all hydrofractures. The fracture growth direction from microseismicity is consistent with the principal stress orientations from the overcoring stress tests, provided that an anisotropic elastic model for the rock mass is used in the data inversions. The σ1 stress is significantly larger than the other two principal stresses and has a reasonably well-defined orientation that is subparallel to the fracture plane; σ2 and σ3 are almost equal in magnitude and thus lie on a circle defined by the standard errors of the solutions. The poles of the microseismicity planes also lie on this circle towards the north. Analysis of P-wave polarizations suggested double-couple focal mechanisms with both thrust and normal faulting mechanisms present, whereas strike-slip and thrust mechanisms would be expected from the overcoring-derived stress solution. The reasons for these discrepancies can be explained by pressure leak-off, but possibly may also involve stress field rotation around the propagating hydrofracture. Our study demonstrates that microseismicity monitoring along with high-resolution event locations provides valuable information for interpreting stress characterization measurements.

Numerical investigation for simultaneous growth of hydraulic fractures in multiple horizontal wells

Recently developed multi-well fracturing technologies are widely used in unconventional low-permeable reservoirs for enhancing production. In this paper, we have implemented a three-dimensional numerical model, which couples the rock deformation, fluid flow and the dynamical flux partition in multiple wellbores, to simulate the simultaneous growths of hydraulic fractures in multi-well fracturing at unconventional reservoirs. To resolve the fully-coupled problem, a numerical scheme with four-layer loops is adopted in this model. The numerical simulations reveal that the asymmetric fracture propagations occur in multi-well fracturing, and the lateral growths of interior fractures are suppressed due to the intense inter-well stress interference. Results show that higher inlet pressure loss, achieved by limited entry design, is able to promote the lateral propagation of interior fractures. Then, case studies are performed to investigate the influences of fracture spacing, well spacing and fracturing scheme on fracture growths in multi-well fracturing. The results reveal that, when decreasing fracture spacing to a certain degree, the fracturing efficiency will not be promoted further by increasing fracture number. The case studies also indicate that, for successful fracturing treatment, a possible lower limit of well spacing should be considered in design, to avoid a sharp reduction of effectiveness in treatment. Compared to simultaneous fracturing scheme, study results show that zipper fracturing scheme has a better performance in promoting the fracture complexity and increasing the fracture surface area, which is favorable to enhance hydrocarbon production.

Experimental Analysis of Hydraulic Fracture Growth and Acoustic Emission Response in a Layered Formation

Microseismic/acoustic emission (AE) monitoring is an essential technology for understanding hydraulic fracture (HF) geometry and stimulated reservoir volume (SRV) during hydraulic fracturing in unconventional reservoirs. To investigate HF growth mechanisms and features of induced microseismic/AE events in a layered formation, laboratory fracturing experiments were performed on shale specimens (30 cm × 30 cm × 30 cm) with multiple bedding planes (BPs) under triaxial stresses. AE monitoring was used to reveal the spatial distribution and hypocenter mechanisms of AE events induced by rock failure. Computerized tomography scanning was used to observe the internal fracture geometry. Experimental results showed that the various HF geometries could be obviously distinguished based on injection pressure curves and AE responses. Fracture complexity was notably increased when vertically growing HFs connected with and opened more BPs. The formation of a complex fracture network was generally indicated by frequent fluctuations in injection pressure curves, intense AE activity, and three-dimensionally distributed AE events. Investigations of the hypocenter mechanisms revealed that shear failure/event dominated in shale specimens. Shear and tensile events were induced in hydraulically connected regions, and shear events also occurred around BPs that were not hydraulically connected. This led to an overestimation of HF height and SRV in layered formations based on the AE location results. The results also showed that variable injection rate and using plugging agent were conducive in promoting HF to penetrate through the weak and high-permeability BPs, thereby increasing the fracture height.

Comparison of Different Hydraulic Fracture Growth Models Based on a Carbonate Reservoir in Iran

There has been little interest in the application of hydraulic fracture treatment in Iranian oil fields, thanks to the primarily suitable production rates of the vast oil fields. In this paper, hydraulic fracturing treatment was simulated by different models for a carbonate reservoir in the southwest of Iran. Suitable pay zones were nominated based on the lithology, water-oil saturation, geomechanical properties, and finally in-situ stress conditions – with the optimum option chosen based on a pseudo three-dimensional (P3D) model. In this work, modeling with P3D, finite different method (FDM), and the methods proposed by Perkins, Kern, and Nordgren (PKN) and Khristianovic, Geertsma, and de Klerk (KGD) were performed in order to determine and compare fracture growth geometrical aspects and the required pressure. Comparison of the above-mentioned models confirmed that P3D and FDM provides more reasonable results, while neither of PKN and KGD models was suitable for such a complex condition. Eventually, sensitivity analysis of input data, such as in-situ stress, injection rates, and reservoir geomechanical properties, was performed to evaluate the variation influence of these factors on fracture growth aspects, such as required pressures and geometrical specifications. The results showed that successful hydraulic fracturing treatment not only depended on the controllable parameters like fluid and proppant specifications, but also uncontrollable parameters such as reservoir properties and in-situ stress had to be taken into account. This study can help to select the optimum model in future hydraulic fracture design and implement it in carbonate reservoirs with similar conditions.

A new mathematical model of asymmetric hydraulic fracture growth

ABSTRACTHydraulic fractures generated by fluid injection in rock formations are often mapped by seismic monitoring. In many cases, the microseismicity is asymmetric relative to the injection well, which has been interpreted by stress gradient along the direction of the hydraulic fracture. We present a mathematical model of asymmetric hydrofracture growth based on relations between the solid‐phase stress and the fracture hydraulics. For single fracture and single injection point, the model has three parameters, hydraulic conductivities of the fracture wings, and normalised stress gradient and predicts the positions of the fracture tips as functions of time. The model is applied to a set of microseismic event locations that occurred during and after an injection process. Two different methods are suggested that make it possible to delineate the fracture tips from the set of microseismic events. This makes it possible to determine the model parameters and to check the agreement between the model prediction and the measured data. The comparison of the measured and modelled growth of fracture wings supports both the assumption of the non‐zero stress gradient and the existence of the post‐injection unilateral growth.

Hydraulic Fracturing and Production Optimization in Eagle Ford Shale Using Coupled Geomechanics and Fluid Flow Model

With increasing production from shale gas and tight oil reservoirs, horizontal drilling and multistage hydraulic fracturing processes have become a routine procedure in unconventional field development efforts. Natural fractures play a critical role in hydraulic fracture growth, subsequently affecting stimulated reservoir volume and the production efficiency. Moreover, the existing fractures can also contribute to the pressure-dependent fluid leak-off during the operations. Hence, a reliable identification of the discrete fracture network covering the zone of interest prior to the hydraulic fracturing design needs to be incorporated into the hydraulic fracturing and reservoir simulations for realistic representation of the in situ reservoir conditions. In this research study, an integrated 3-D fracture and fluid flow model have been developed using a new approach to simulate the fluid flow and deliver reliable production forecasting in naturally fractured and hydraulically stimulated tight reservoirs. The model was created with three key modules. A complex 3-D discrete fracture network model introduces realistic natural fracture geometry with the associated fractured reservoir characteristics. A hydraulic fracturing model is created utilizing the discrete fracture network for simulation of the hydraulic fracture and flow in the complex discrete fracture network. Finally, a reservoir model with the production grid system is used allowing the user to efficiently perform the fluid flow simulation in tight formations with complex fracture networks. The complex discrete natural fracture model, the integrated discrete fracture model for the hydraulic fracturing, the fluid flow model, and the input dataset have been validated against microseismic fracture mapping and commingled production data obtained from a well pad with three horizontal production wells located in the Eagle Ford oil window in south Texas. Two other fracturing geometries were also evaluated to optimize the cumulative production and for the three wells individually. Significant reduction in the production rate in early production times is anticipated in tight reservoirs regardless of the fracturing techniques implemented. The simulations conducted using the alternating fracturing technique led to more oil production than when zipper fracturing was used for a 20-year production period. Yet, due to the decline experienced, the differences in cumulative production get smaller, and the alternating fracturing is not practically implementable while field application of zipper fracturing technique is more practical and widely used.

A Fully Coupled Model for Hydraulic-Fracture Growth During Multiwell-Fracturing Treatments: Enhancing Fracture Complexity

Summary Multiwell-completion techniques, such as sequential fracturing, zipper fracturing, and simultaneous fracturing, have been proposed to improve fracture complexity and connectivity. Critical geomechanics behind the multiwell-fracturing techniques include pore-pressure propagation, cooling stress, tip-induced shear stress, and reversal of stress anisotropy. To optimize multiwell-fracturing treatments, we numerically investigated fracture growth from the perspective of thermo/hydromechanical (THM) coupling. The coupled geomechanics and fluid-heat-flow model is derived from a mixed finite-element (FE) and finite-volume (FV) method, which is capable of simulating multifracture growth in heterogeneous reservoirs. In this study, both hydraulic-fracture (HF) propagation and natural-fracture (NF) reactivation in opening or shearing patterns were taken into account. Particularly, an elastoplastic fracture constitutive model was adopted to predict permanent enhancement of fracture aperture. The effects of perforation-cluster spacing, well spacing, and the fracturing sequence of multiwell completion upon fracture complexity were studied, where the total hydraulically fractured area was treated as the primary indicator of HF effectiveness. By numerical parametric studies, we determined four findings. First, there is an optimal cluster spacing for maximizing the total fracture area for a stage with a given length. Cluster spacing mainly affects stress distribution during HF, which subsequently affects the path of newly created fracture propagation and crossing behaviors (i.e., crossing, arresting, or offsetting). Second, suitable well spacing should be chosen carefully to avoid the hydraulic interconnection between the tip-to-tip stages, as well as to make use of tip-induced shear stresses. Third, the fracturing sequence for multiwell completion is of critical importance. Among three multiwell-completion schemes (i.e., sequential, zipper, and simultaneous fracturing), the zipper-fracturing technique achieves the best fracturing effectiveness for this case study. Fourth, the effect of stress perturbation on NFs can be quite different, depending on the position relative to the created stimulated reservoir volume (SRV). The coupled model significantly improves our understanding of multiwell-fracturing treatments and then provides us with a means to optimize the multiwell completion, enhancing fracture complexity to effectively improve productivity.

Prediction and analysis of the stimulated reservoir volume for shale gas reservoirs based on rock failure mechanism

The ultra-low-permeability shale gas reservoir has a lot of well-developed natural fractures. It has been proven that hydraulic fracture growth pattern is usually a complex network fracture rather than conventional single planar fractures by micro-seismic monitoring, which can be explained as the shear and tensile failure of natural fractures or creation of new cracks due to the increase in reservoir pore pressure caused by fluid injection during the process of hydraulic fracturing. In order to simulate the network fracture growth, a mathematical model was established based on full tensor permeability, continuum method and fluid mass conservation equation. Firstly, the governing equation of fluid diffusivity based on permeability tensor was solved to obtain the reservoir pressure distribution. Then Mohr–Coulomb shear failure criterion and tensile failure criterion were used to decide whether the rock failed or not in any block on the basis of the calculated reservoir pressure. The grid-block permeability was modified according to the change of fracture aperture once any type of rock failure criterion was met within a grid block. Finally, the stimulated reservoir volume (SRV) zone was represented by an enhancement permeability zone. After calibrating the numerical solution of the model with the field micro-seismic information, a sensitivity study was performed to analyze the effects of some factors including initial reservoir pressure, injection fluid volume, natural fracture azimuth angle and horizontal stress difference on the SRV (shape, size, bandwidth and length). The results show that the SRV size increases with the increasing initial pore reservoir and injection fluid volume, but decreases with the increase in the horizontal principal stress difference and natural fracture azimuth angle. The SRV shape is always similar for different initial pore reservoir and injection fluid volume. The SRV is observed to become shorter in length and wider in bandwidth with the decrease in natural fracture azimuth angle and horizontal principal stress difference.

Characterization of Hydraulic Fractures Growth During the Äspö Hard Rock Laboratory Experiment (Sweden)

A crucial issue to characterize hydraulic fractures is the robust, accurate and automated detection and location of acoustic emissions (AE) associated with the fracture nucleation and growth process. Waveform stacking and coherence analysis techniques are here adapted using massive datasets with very high sampling (1 MHz) from a hydraulic fracturing experiment that took place 410 m below surface in the Aspo Hard Rock Laboratory (Sweden). We present the results obtained during the conventional, continuous water injection experiment Hydraulic Fracture 2. The resulting catalogue is composed of more than 4000 AEs. Frequency–magnitude distribution from AE magnitudes (MAE) reveals a high b value of 2.4. The magnitude of completeness is also estimated approximately MAE 1.1, and we observe an interval range of MAE between 0.77 and 2.79. The hydraulic fractures growth is then characterized by mapping the spatiotemporal evolution of AE hypocentres. The AE activity is spatially clustered in a prolate ellipsoid, resembling the main activated fracture volume (~105 m3), where the lengths of the principal axes (a = 10 m; b = 5 m; c = 4 m) define its size and its orientation can be estimated for a rupture plane (strike ~123°, dip ~60°). An asymmetric rupture process regarding to the fracturing borehole is clearly exhibited. AE events migrate upwards covering the depth interval between 404 and 414 m. After completing each injection and reinjection phase, the AE activity decreases and appears located in the same area of the initial fracture phase, suggesting a crack-closing effect.