Fracture Growth Research Articles

Stable Created Fracture Growth between Two Parallel Boreholes

Stable Created Fracture Growth between Two Parallel Boreholes

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.

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.

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.

Microseismic analysis over a single horizontal distributed acoustic sensing fiber using guided waves

A single horizontal distributed acoustic sensing (DAS) fiber is notoriously challenging for microseismic analysis even when it is close to recorded events. Due to its uniaxial measurement, locations suffer from circular ambiguity. Nonetheless, in unconventional plays, the presence of dispersive guided waves in the DAS records can partially resolve such ambiguity. If the reservoir has lower seismic velocities than its surrounding medium, it can act as a waveguide. In this case, guided waves are generated only by microseismic events occurring inside or close to the reservoir, and their propagation is confined to the reservoir. We first train a machine learning model for microseismic event detection using a unique data set of almost 7000 manually picked events and an equal number of noise windows. Applying the trained model to 10 stimulation stages from two offset wells yields more than 100,000 event detections, with a higher sensitivity than manual labeling. Detected events undergo a localization procedure based on the dispersion properties of guided waves, estimated in-situ from known perforation shots. Location results allow us to reconstruct the spatio-temporal pattern of fracture development. We observe a dominant fracture propagation direction for all stages, which indicates the effect of the regional stress in the reservoir. We qualitatively validate the direction and extent of the fracture growth by perforation shot analysis. We have found the first application of microseismic event location with a single straight fiber, which is considered impossible without a waveguide structure.

Modeling Hydraulic Fracturing and Blow-Out Failure of Tunnel Face During Shield Tunneling in Soft Soils

A common conflict of objectives for shield tunneling is to provide sufficient support pressure to maintain the stability of the tunnel face while avoiding blow-out of the tunnel face. Slurry-induced hydraulic fracturing, which is an important cause of blow-out failure in slurry-type shield tunneling, is investigated in this study. A fracture initiation mechanism for soft soils is developed and the fracturing pressure is described using a combined shear and tensile failure criteria within the cavity expansion theory framework. A slurry-induced fracture propagation model, coupled with the fracture initiation mechanism, is then proposed for predicting the fracture length and growth rate in front of tunnel face. The model is successfully applied to test data from the literature, and used in a parametric analysis. The results show that a fracture may easily extend to the ground surface when tunneling in ground with low strength parameters or shallow depth, and hydraulic fracture can be mitigated by using a high-density slurry. Finally, some design charts are provided to guide engineers in selecting a reasonable range of slurry pressure during shield tunneling, thus mitigating the risks of blow-out as well as maintaining face stability.

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 of the effect of water-shale interaction on fracture generation and permeability change in shales under stress anisotropy

Clay swelling due to the rock-water reaction occurs commonly during the fracturing of shales. Lots of experiments have been conducted to shed a light on the role of clay swelling in fracture generation and permeability change in shales. However, stress anisotropy was not considered in most of the previous research, which makes the results and conclusions less convincing. To fill this research gap, this paper employed a practical experimental methodology that combines clay swelling, fracture generation, permeability change, and stress anisotropy. The samples with artificial fractures through the core were used to conduct the tests. The fluid was pumped at a constant flow rate of 2 ml/min to imitate the fracturing fluid. CT scanning was applied to capture the images of fracture growth. The pressure data were recorded to qualitatively show the change of permeability in samples. The results reveal that clay swelling can impact fracture generation through two ways: generation of micro-fractures and weakening effect on the mechanical strength of shales. With the effect of clay swelling, fractures can be generated much easier when shale is under stress anisotropy. Pressure data shows that the upstream pressure decreases when fractures through the core are generated. It means whether clay swelling is beneficial to the recovery of samples' permeability depends on the generated fractures. When fractures are generated and connected to form a flow path, clay swelling can have a positive effect on the recovery of samples' permeability. Besides, particle detachment due to clay swelling is one possible reason for the recovery of samples’ permeability by increasing the width of the existing fractures.

Novel Learnings of Proppant Transport Behavior in Unconventional Hydraulic Fractures

Summary Effective proppant placement has been one of the key objectives of hydraulic fracturing. Different proppant and fracture fluid characteristics and placement methodologies have been historically applied based on learnings from standard proppant transport studies with parallel plate slots. The standard test setup represents a simplified planar fracture with constant width and confined height, incorporating only basic flow characteristics, and thus, is inadequate to capture unique phenomena of proppant transport in unconventional reservoirs. In this study, proppant transport laboratory tests were conducted on a large-scale (10×20 ft) tortuous slot flow system. This novel setup incorporates many significant unconventional fracture features, including lateral and vertical tortuosity, variable width, leakoff, fluid dynamics replicating upward fracture growth, and so on. Proppant transport behavior was investigated with multiple parameters such as proppant size, density, and concentration; fracture fluid type and viscosity; pumping sequence; pump rate; and fracture properties (width, leakoff location and rate, fracture tortuosity profile, and flow directions). The detailed parametric and integrated study of test results includes analysis of proppant dune evolution, dune shape, particle-size distribution across dune, propped area, fluid, and proppant collected from leakoff and exit ports. Multiple unique phenomena occurring at tortuous interfaces were observed, including the generation of isolated pockets of proppant pack, restriction of upward movement owing to proppant bridging, and creation of discontinuous and sparsely distributed proppant pillars above the dune. The test results demonstrated a larger proppant dune angle in front of the dune peak during injection and a subsequent falloff of proppant pack with a higher percentage of smaller mesh proppant backfilling the area at and near the inlet (analogous to the wellbore). Self-segregation of proppant in slickwater as per mesh size resulted in higher percentage of smaller mesh (larger size) proppant settled near the injection point, and a higher percentage of larger mesh (smaller size) proppant placed farther in the system. These observations and novel learnings highlight that it is critical to account for tortuous fracture pathway, leakoff effects, and flow directions (both lateral and upward) to better understand proppant transport behaviors in unconventional fractures. A partially proppant-filled fracture area is recognized in unconventional fracture in addition to general classification of propped and unpropped fracture area. Using proppant with large mesh size distribution range or pumping smaller mesh proppant first in slickwater helps achieve dual benefits of higher near-wellbore conductivity and improved far-field transport. This study demonstrates and physically verifies unique proppant transport behaviors in unconventional hydraulic fractures. It also provides novel learnings that will help the industry to optimize hydraulic fracture design through the selection of optimum proppant and fluid properties with enhanced pumping strategies for overall well productivity improvement in an unconventional reservoir.

On the validation of mixed-mode I/II crack growth theories for anisotropic rocks

We evaluate the accuracy of three well-known fracture growth theories to predict crack trajectories in anisotropic rocks through comparison with new experimental data. The results of 99 fracture toughness tests on the metamorphic Grimsel Granite under four different ratios of mixed-mode I/II loadings are reported. For each ratio, the influence of the anisotropy orientation on the direction of fracture growth is also analyzed. Our results show that for certain loading configurations, the anisotropy offsets the loading influence in determining the direction of crack growth, whereas in other configurations, these factors reinforce each other. To evaluate the accuracy of the fracture growth theories, we compare the experiment results for the kink angle and the effective fracture toughness with the predictions of the maximum tangential stress (MTS), the maximum energy release rate (MERR), and the maximum strain energy density (MSED) criteria. The criteria are first assessed in their classical forms employed in the literature. It is demonstrated that the energy-based criteria in their classical formulation cannot yield good predictions. We then present modified forms of the ERR and SED functions in which the tensile and shear components are decomposed. These modified forms give significantly better predictions of fracture growth paths. The evaluation of the three criteria illustrates that the modified MSED criterion is the least accurate model even in the modified form, while the results predicted by MTS and modified MERR are well matched with the experimental results.

Second-order optimality conditions for an optimal control problem governed by a regularized phase-field fracture propagation model

We prove second-order optimality conditions for an optimal control problem of tracking-type for a time-discrete regularized phase-field fracture or damage propagation model. The energy minimization problem describing the fracture process contains a penalization term for violation of the irreversibility condition in the fracture growth process, as well as a viscous regularization corresponding to a time-step restriction in a temporal discretization of the problem. In the control problem, the energy minimization problem is replaced by its Euler–Lagrange equations. While the energy minimization functional is convex due to the viscous approximation, the associated Euler–Lagrange equations are of quasilinear type, making the control problem nonconvex. We prove second-order necessary as well as second-order sufficient optimality conditions without two-norm discrepancy.

Evolution mechanism of optical fiber strain induced by multi-fracture growth during fracturing in horizontal wells

A forward model for optical fiber strain was established based on a planar 3D multi-fracture model. Then the forward method calculating distributed fiber strain induced by multi-fracture growth was proposed. Based on this method, fiber strain evolution during fracturing of the horizontal well was numerically simulated. Fiber strain evolution induced by fracture growth can be divided into three stages: strain increasing, shrinkage convergence, and straight-line convergence, whereas the evolution of fiber strain rate has four stages: strain rate increasing, shrinkage convergence, straight-line convergence, and strain rate reversal after pumping stops. Fiber strain does not flip after pumping stop, while the strain rate flips after pumping stop so that strain rate can reflect injection dynamics. The time when the fracture extends to the fiber and inter-well pressure channeling can be identified by the straight-line convergence band of distributed fiber strain or strain rate, and the non-uniform growth of multiple fractures can be evaluated by using the instants of fractures reaching the fiber monitoring well. When the horizontal section of the fiber monitoring well is within the height range of a hydraulic fracture, the instant of the fracture reaching the fiber can be identified; otherwise, the converging band is not apparent. In multi-stage fracturing, under the influence of stress shadow from previous fracturing stages, the tensile region of fiber strain may not appear, but the fiber strain rate can effectively show the fracture growth behavior in each stage. The evolution law of fiber strain rate in single-stage fracturing can be applied to multi-stage fracturing.

Containment of Water-Injection-Induced Fractures: The Role of Heat Conduction and Thermal Stresses

Summary Reservoir cooling by water or wastewater injection can significantly change the stress in the target injection zones and the bounding layers. Out-of-zone fracture growth is substantially affected by these poro-thermo-elastic stress changes occurring in heterogeneous rock layers. No previous study has systematically investigated the influence of both heat conduction and convection and the associated stress alteration and fracture height growth during long-term water injection in multiple layers. Without understanding this coupled effect, it is not possible to predict the injection-induced fracture geometry or the conditions under which these fractures will breach the bounding shale layers. This paper presents a model and results that clearly show that accounting for thermal conduction between the injection sand and the bounding shale is crucial in predicting fracture containment during water injection. We developed a fully coupled compositional reservoir/fracturing simulator that solves poro-thermo-elastic equations. We used it to simulate 3D fracture propagation induced by cold water injection and, at the same time, calculate changes in the stress field induced by thermo-poro-elastic effects in heterogeneous reservoir layers. The stress in the bounding layer is shown to change significantly as a result of thermal conduction from the layer below. We first validate our model with existing analytical solutions and then present synthetic cases and simulate a field case. Simulation results show that fracture height growth can be underpredicted if heat conduction between the target injection sands and bounding shales is ignored. We identify the effects of fluid properties, rock properties, and injection temperature on thermal-conduction-induced stress changes and fracture containment for the first time.

An Improved Embedded Discrete Fracture Model with Fracture Growth for Water-Induced Fracture Simulation in Low Permeability Reservoirs

Abstract Water injection is often used to supply formation energy in low permeability reservoirs. A lot of field data shows that fractures nearby the wellbores may extend hundreds of meters because of the poor injectability which is called water-induced fractures. The presence of these fractures significantly changes the flow of injected water thus affecting the development effects. However, few studies of reservoir numerical simulation methods have been presented to simulate the dynamic changes of fractures in the long-term waterflooding process. This study is based on the embedded discrete fracture model (EDFM) in which the fracture system has less dependence on the grid system. By improving the preprocessing algorithm, fracture growth can be considered in EDFM which is called the dynamic embedded discrete model (dEDFM). This new method provides an innovative idea for fracture propagation simulation by attaching new fracture elements to the original fractures once the failure criterion is satisfied. Meanwhile, there is no need to calculate the stress field once the in situ stress is provided, so the computational efficiency is greatly improved compared with the fluid-solid coupling method. Besides, dEDFM has a flexible way of handling fracture elements, so it is suitable for water-induced fracture simulation. Results show that fracture propagation speed is significantly influenced by matrix permeability, in situ stress, and injection intensity, and if the water-induced fractures propagate faster than the original waterfront movement velocity, changing law of the water content rate rising of production wells in different directions will be different. The contribution of this work lies in that it provides a suitable and efficient way for reservoir engineers to deal with water-induced fractures since the propagation of fractures can be considered when it comes to reservoir numerical simulation, and it is helpful for production data prediction and development adjustment in low permeability reservoirs.

Experimental investigation of mixed mode I-II fracture property of thermally treated granite under dynamic loading

In the process of deep underground resource development and utilization, the surrounding rock mass is not only affected by high temperatures, but also dependent on the dynamic stress environment. In this paper, the dynamic impact loading tests were carried out on the cracked straight-through Brazilian disc (CSTBD) granite specimens after heat treatment using the spilt Hopkinson pressure bar (SHPB) system. The effects of temperature and loading mode on the dynamic fracture toughness, fracture growth path, strain distribution, and fracture angle were analyzed. The results showed that, the fracture toughness of CSTBD granite specimen under dynamic loading decreases gradually as the mixed coefficient increases. The pure mode II fracture toughness is linearly related to that of pure mode I. High temperatures shows a negative effect on the fracture property of granite. Dynamic fracture toughness decreases with the increase of temperature, first gently (25–400 °C) and then sharply (400–800 °C). Under dynamic loading, the main crack initiates from the pre-crack tip, accompanied by obvious strain concentration, and then extends gradually to the loading end. The fracture angle of the main crack presents a generally increasing trend with the increase in loading angle, but is not closely related to the temperature of heat treatment.

Observations and Modeling of Fiber Optic Strain on Hydraulic Fracture Height Growth in Hydraulic Fracturing Test Site 2 (HFTS-2)

Summary Understanding fracture height growth can be of great significance to optimizing field development and improving recovery. The Hydraulic Fracturing Test Site 2 (HFTS-2) has provided a unique opportunity and an advanced data set to allow us to observe and understand fracture geometries rigorously. Low-frequency distributed acoustic sensing (LF-DAS) data from a vertical well in HFTS-2 showed three key observations: (i) excessive upward height growth (>1,000 ft) and limited downward growth of the hydraulic fractures during pumping, (ii) considerable additional upward fracture height growth (~300 ft) after well shut in, and (iii) very complex LF-DAS strain rate patterns for a small fiber-to-stage offset. Advanced geomechanical modeling was performed to simulate the hydraulic fracture propagation and the resulting strain responses in the vertical direction. The modeling results demonstrated asymmetric upward and downward fracture height growths as observed in HFTS-2 with a similar upward height growth rate. Simulated waterfall plots of vertical strain rate showed distinct patterns for different fiber-to-fracture distances. The upward-growing fracture tip can be clearly identified by the interfaces between compressing and extending zones. It was also found that the complex strain rate patterns observed in HFTS-2 for small fiber-stage offsets were not caused by the mechanical layering but possibly result from the simultaneous propagation of multiple hydraulic fractures at different rates. The simulation results improved the understating of the HFTS-2 LF-DAS data, and the simulated strain rate patterns could also serve as templates for fracture height interpretation from LF-DAS data in future.

Investigation on the influence of multiple fracture interference on hydraulic fracture propagation in tight reservoirs

The combination of horizontal well drilling and staged fracturing technology is one of the most effective ways to increase unconventional oil and gas production. The orientation of the horizontal wellbore is mostly considered to be consistent with the minimum horizontal principal stress in the numerical simulation. However, horizontal wellbores are usually at an angle to the minimum principal stress in field operations. In this case, the dynamic growth of the fractures will be limited during subsequent perforation and fracturing operations. Therefore, the objective of this paper is to build an effective numerical model to investigate the propagation of hydraulic fractures in the case of a horizontal wellbore that is not co-linear with the minimum horizontal principal stress. The extended finite element method is applied for multi-stage fracturing flow-solid coupling in horizontal wells. In addition, the effect of sequential and alternate fracturing on the propagation of fractures in horizontal wells was compared. The simulation results show that fracture growth on one side of the horizontal wellbore is severely restricted as the pinch angle increases. It is most evident in sequential fracturing mode while increasing the fracture spacing is one of the effective ways to reduce inter-fracture interference. Meanwhile, compared to sequential fracturing, alternate fracturing is more effective in reducing inter-fracture interference, allowing for effective fracturing at closer fracture spacing. Finally, the density of the fracturing section has been increased, and a higher reservoir reconstruction area can be obtained. This work, for the first time, evaluates the dynamic propagation of fractures when the horizontal wellbore is not collinear with the minimum horizontal principal stress orientation and helps operators to optimize the fracturing process.

Experimental study on deformation and permeability enhancement of oil sand reservoir by hydraulic fracturing technique under true triaxial stress

AbstractHydraulic fracturing technology is often applied to form a permeable zone for geothermal resources near the borehole in tight reservoirs to improve the permeability and extraction efficiency. Steam or hot water is often injected to dissolve the heavy oil to increase its fluidity during the extraction. As the numerical simulation or two‐dimensional physical experiments have great limitations to simulate hydraulic fracturing of oil sand reservoirs, this study conducted a large‐scale three‐dimensional physical simulation experimental study of hydraulic fracturing with high temperature of oil sand reservoir under true triaxial stress state and monitored the water pressure change at various points inside the box during the hydraulic fracturing by laying pressure sensors. The experimental results showed that the hydraulic breakdown pressure of oil sands increases with the increase in σ2, which is related to the increase in σ2 limiting the fracture growth and the decrease in effective stress during fluid injection. To better describe the breakdown pressure variation, we developed a new oil sand breakdown pressure prediction model considering the true triaxial stress condition, which showed a good prediction effect. Due to the formation of fluid hysteresis zone during the fracture expansion, the fluid pressure recorded by the internal pressure sensor lagged behind the injection pressure. Hydraulic fracturing produced shear fractures inside the oil sands under low σ2 conditions and tensile fractures under high σ2 conditions, and the permeability was significantly increased after hydraulic fracturing, in which the shear fractures formed under low σ2 showed a better permeability enhancement effect than the tensile fractures formed under high σ2. The research and analysis in this study can provide reasonable suggestions and feasibility analysis for the design and construction of heavy oil extraction.