scholarly journals An Analytical Framework for Stress Shadow Analysis During Hydraulic Fracturing – Applied to the Bakken Formation, Saskatchewan, Canada

2021 ◽  
Author(s):  
Mostafa Gorjian ◽  
Sepidehalsadat Hendi ◽  
Christopher D. Hawkes
Keyword(s):  
Hydraulic Fracturing ◽  
Large Scale ◽  
Shear Failure ◽  
Microseismic Monitoring ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Bakken Formation ◽  
Stress Shadow

Abstract. This paper presents selected results of a broader research project pertaining to the hydraulic fracturing of oil reservoirs hosted in the siltstones and fine grained sandstones of the Bakken Formation in southeast Saskatchewan, Canada. The Bakken Formation contains significant volumes of hydrocarbon, but large-scale hydraulic fracturing is required to achieve economic production rates. The performance of hydraulic fractures is strongly dependent on fracture attributes such as length and width, which in turn are dependent on in-situ stresses. This paper reviews methods for estimating changes to the in-situ stress field (stress shadow) resulting from mechanical effects (fracture opening), poro-elastic effects, and thermo-elastic effects associated with fluid injection for hydraulic fracturing. The application of this method is illustrated for a multi-stage hydraulic fracturing operation, to predict principal horizontal stress magnitudes and orientations at each stage. A methodology is also presented for using stress shadow models to assess the potential for inducing shear failure on natural fractures. The results obtained in this work suggest that thermo and poro-elastic stresses are negligible for hydraulic fracturing in the Bakken Formation of southeast Saskatchewan, hence a mechanical stress shadow formulation is used for analyzing multistage hydraulic fracture treatments. This formulation (and a simplified version of the formulation) predicts an increase in instantaneous shut-in pressure (ISIP) that is consistent with field observations (i.e., ISIP increasing from roughly 21.6 MPa to values slightly greater than 26 MPa) for a 30-stage fracture treatment. The size of predicted zones of shear failure on natural fractures are comparable with the event clouds observed in microseismic monitoring when assumed values of 115°/65° are used for natural fracture strike/dip; however, more data on natural fracture attributes and more microseismic monitoring data for the area are required before rigorous assessment of the model is possible.

Predicting Hydraulic Fracturing in a Carbonate Gas Reservoir in Abu Dhabi Using 1D Mechanical Earth Model: Uncertainty and Constraints

2015 ◽  
Author(s):  
Manhal Sirat ◽  
Mujahed Ahmed ◽  
Xing Zhang
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Natural Fracture ◽  
Abu Dhabi ◽  
Hydraulic Fractures ◽  
Gas Reservoir ◽  
In Situ Stresses ◽  
Tight Carbonate ◽  
Different Depths

Abstract In-situ stress state plays an important role in controlling fracture growth and containment in hydraulic fracturing managements. It is evident that the mechanical properties, existing stress regime and the natural fracture network of its reservoir rocks and the surrounding formations mainly control the geometry, size and containments of produced hydraulic fractures. Furthermore, the three principal in situ stresses' axes swap directions and magnitudes at different depths giving rise to identifying different mechanical bedrocks with corresponding stress regimes at different depths. Hence predicting the hydro-fractures can be theoretically achieved once all the above data are available. This is particularly difficult in unconventional and tight carbonate reservoirs, where heterogeneity and highly stress variation, in terms of magnitude and orientation, are expected. To optimize the field development plan (FDP) of a tight carbonate gas reservoir in Abu Dhabi, 1D Mechanical Earth Models (MEMs), involving generating the three principal in-situ stresses' profiles and mechanical property characterization with depth, have been constructed for four vertical wells. The results reveal the swap of stress magnitudes at different mechanical layers, which controls the dimension and orientation of the produced hydro-fractures. Predicted containment of the Hydro-fractures within the specific zones is likely with inevitable high uncertainty when the stress contrast between Sv, SHmax with Shmin respectively as well as Young's modulus and Poisson's Ratio variations cannot be estimated accurately. The uncertainty associated with this analysis is mainly related to the lacking of the calibration of the stress profiles of the 1D MEMs with minifrac and/or XLOT data, and both mechanical and elastic properties with rock mechanic testing results. This study investigates the uncertainty in predicting hydraulic fracture containment due to lacking such calibration, which highlights that a complete suite of data, including calibration of 1D MEMs, is crucial in hydraulic fracture treatment.

A Peridynamics Model for the Propagation of Hydraulic Fractures in Heterogeneous, Naturally Fractured Reservoirs

2015 ◽  
Author(s):  
Hisanao Ouchi ◽  
Amit Katiyar ◽  
John T. Foster ◽  
Mukul M. Sharma
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Two Dimensions ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Fracture Networks ◽  
Complex Fracture ◽  
Nonlocal Continuum Theory

Abstract A novel fully coupled hydraulic fracturing model based on a nonlocal continuum theory of peridynamics is presented and applied to the fracture propagation problem. It is shown that this modeling approach provides an alternative to finite element and finite volume methods for solving poroelastic and fracture propagation problems and offers some clear advantages. In this paper we specifically investigate the interaction between a hydraulic fracture and natural fractures. Current hydraulic fracturing models remain limited in their ability to simulate the formation of non-planar, complex fracture networks. The peridynamics model presented here overcomes most of the limitations of existing models and provides a novel approach to simulate and understand the interaction between hydraulic fractures and natural fractures. The model predictions in two-dimensions have been validated by reproducing published experimental results where the interaction between a hydraulic fracture and a natural fracture is controlled by the principal stress contrast and the approach angle. A detailed parametric study involving poroelasticity and mechanical properties of the rock is performed to understand why a hydraulic fracture gets arrested or crosses a natural fracture. This analysis reveals that the poroelasticity, resulting from high fracture fluid leak-off, has a dominant influence on the interaction between a hydraulic fracture and a natural fracture. In addition, the fracture toughness of the rock, the toughness of the natural fracture, and the shear strength of the natural fracture also affect the interaction between a hydraulic fracture and a natural fracture. Finally, we investigate the interaction of multiple completing fractures with natural fractures in two-dimensions and demonstrate the applicability of the approach to simulate complex fracture networks on a field scale.

Numerical modeling of seismicity induced by fluid injection in naturally fractured reservoirs

Geophysics ◽  
2011 ◽  
Vol 76 (6) ◽  
pp. WC167-WC180 ◽  
Author(s):  
Xueping Zhao ◽  
R. Paul Young
Keyword(s):  
Numerical Modeling ◽  
Fractured Reservoirs ◽  
Seismic Source ◽  
Microseismic Monitoring ◽  
Naturally Fractured Reservoirs ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Field Observations ◽  
Natural Fractures ◽  
Naturally Fractured

The interaction between hydraulic and natural fractures is of great interest for the energy resource industry because natural fractures can significantly influence the overall geometry and effectiveness of hydraulic fractures. Microseismic monitoring provides a unique tool to monitor the evolution of fracturing around the treated rock reservoir, and seismic source mechanisms can yield information about the nature of deformation. We performed a numerical modeling study using a 2D distinct-element particle flow code ([Formula: see text]) to simulate realistic conditions and increase understanding of fracturing mechanisms in naturally fractured reservoirs, through comparisons with results of the geometry of hydraulic fractures and seismic source information (locations, magnitudes, and mechanisms) from both laboratory experiments and field observations. A suite of numerical models with fully dynamic and hydromechanical coupling was used to examine the interaction between natural and induced fractures, the effect of orientation of a preexisting fracture, the influence of differential stress, and the relationship between the fluid front, fracture tip, and induced seismicity. The numerical results qualitatively agree with the laboratory and field observations, and suggest possible mechanics for new fracture development and their interaction with a natural fracture (e.g., a tectonic fault). Therefore, the tested model could help in investigating the potential extent of induced fracturing in naturally fractured reservoirs, and in interpreting microseismic monitoring results to assess the effectiveness of a hydraulic fracturing project.

scholarly journals Numerical Investigation of the Fracturing Effect Induced by Disturbing Stress of Hydrofracturing

2021 ◽  
Vol 9 ◽  
Author(s):  
Xinglong Zhao ◽  
Bingxiang Huang ◽  
Giovanni Grasselli
Keyword(s):  
Shear Stress ◽  
Fracture Surface ◽  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Shear Failure ◽  
Fluid Pressure ◽  
Natural Fracture ◽  
Coal Bed ◽  
Natural Fractures ◽  
Fracture Failure

Fracturing induced by disturbing stress of hydraulic fracturing is the frontier common core scientific problem of reservoir stimulation of coal bed methane and shale gas. The finite-discrete element method, numerical calculation method, is used to analyze the basic law of shear failure and tension failure of natural fractures induced by the disturbing stress of the hydraulic fracture. The simulation results show that when natural fractures and other weak structures exist on the front or both sides of hydraulic fracture, the shear stress acting on the surface of natural fracture will increase until the natural fracture failure, which is caused by the disturbing stress of hydraulic fracturing. The seepage area on the front and both sides of the hydraulic fracture did not extend to the natural fracture while the natural fracture failure occurred. It indicates that the shear failure of natural fractures is induced by the disturbing stress of hydraulic fracturing. When the hydraulic fracture propagates to the natural fracture, the hydraulic tension fracture and disturbed shear fractures are connected and penetrated. As the fluid pressure within the natural fracture surface increases, the hydraulic fracture will continue to propagate through the natural fracture. Meanwhile, due to the action of fluid pressure, a tensile stress concentration will occur at the tip of the natural fracture, which will induce the airfoil tension failure of the natural fracture. With the increase of the principal stress difference, the range of the disturbing stress area and the peak value of the disturbing stress at the front of the hydraulic fracture tip increase, as well as the shear stress acting on the natural fracture surface. During the process of hydraulic fracture approaching natural fracture, the disturbing stress is easier to induce shear failure of natural fracture. With the increase of the cohesive force of natural fracture, the ability of natural fractures to resist shear failure increases. As the hydraulic fracture approaches natural fractures, the disturbing stress is more difficult to induce shear failure of natural fracture. This study will help to reveal the formation mechanism of the fracture network during hydraulic fracturing in the natural fractures developed reservoir.

Hydraulic Fracturing at Clair: Unlocking the Potential of Europe's Largest Reservoir

2022 ◽  
Author(s):  
Alistair Malcolm Roy ◽  
Graeme Henry Allan ◽  
Corrado Giuliani ◽  
Shakeel Ahmad ◽  
Charlotte Giraud ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Phase 1 ◽  
Poor Quality ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Production Test ◽  
Natural Fractures ◽  
The South ◽  
Initial Development ◽  
Matrix Quality

Abstract The Greater Clair area, Europe's largest oilfield, has two existing platforms, Clair Phase 1 and Clair Ridge, on production with future potential for a third platform targeting undeveloped Lower Clair Group to the South of Ph1. Clair Phase 1 was the initial development of Clair, targeting Lower Clair Group (LCG) reservoir consisting of a complex Devonian sandstone in six units. Most Phase 1 wells penetrated relatively good quality reservoir enhanced by natural fractures, while more recently Clair Ridge wells took a similar approach targeting natural fractures, however that strategy is continually being evaluated. In some areas however low matrix quality and lack of natural fractures were the dominant characteristics resulting in lower production rates. A brief comparison of the range of production outcomes will be presented, including potential downsides of reliance on natural fractures. Given the large oil volumes in areas of known poorer rock quality, alongside variable production results, a hydraulic fracturing trial was initiated in 2017. Well 206/08-A23 (A23) targeted previously under-developed, poor-quality Unit VI within the Phase 1 Graben area where natural fractures are absent. A pre-frac production test established baseline production of 900BOPD in December 2018. The A23 objectives included subsequent hydraulically fracturing the well to test this techniques ability to unlock production from tight, matrix dominated formation. Detailed analysis of core, log and limited vertical well fracturing data (from initial fracturing trials of 1980's vintage), yielded robust designs. Key challenges included overcoming very low KV/KH ratios with fracture heights exceeding 300ft. The resulting detailed designs provided consistent and predictable hydraulic fracturing execution in A23 in 2019, including placement of four planned 500klbs treatments combined with coil clean-outs after each stage to unload solids and fluids from the well. Initial fracture designs were conservative in terms of pad and proppant scheduling which, alongside learnings around operational logistics offshore West of Shetlands and completion design, offer significant optimisations for future hydraulic fractures. Post frac A23 became the highest non-natural fractured producer across Clair. Initially a six-fold production increase was observed with monitoring of transient production ongoing. Tracer analysis confirmed production contribution from all zones. Proving fracturing technology brings opportunities to unlock poorer Phase 1 and Ridge reservoir areas. Additionally, significant portions of the undeveloped Lower Clair Group to the South of Ph1 comprises lower permeability reservoir with higher viscosity oil and reduced natural fracture presence. Hydraulic fracturing is therefore a crucial completion technique for developing this lower quality reservoir and brings significant value enhancement to the project. Efficient delivery of numerous large fractures in a harsh offshore environment West of Shetlands presents significant challenges. The influence of how the A23 fracturing results and learnings are guiding future hydraulic fracturing concept are detailed, including optimising platform engineering design to facilitate efficient fracturing operations while maintaining the required productivity in this challenging scenario.

scholarly journals Numerical Simulation of Artificial Fracture Propagation in Shale Gas Reservoirs Based on FPS-Cohesive Finite Element Method

Geofluids ◽  
2019 ◽  
Vol 2019 ◽  
pp. 1-16 ◽  
Author(s):  
Xiaoqiang Liu ◽  
Zhanqing Qu ◽  
Tiankui Guo ◽  
Ying Sun ◽  
Zhifeng Shi ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Finite Element ◽  
Hydraulic Fracturing ◽  
In Situ Stress ◽  
Natural Fracture ◽  
Natural Fractures ◽  
Rock Matrix ◽  
Gas Reservoirs ◽  
Artificial Fracture

The simulation of hydraulic fracturing by the conventional ABAQUS cohesive finite element method requires a preset fracture propagation path, which restricts its application to the hydraulic fracturing simulation of a naturally fractured reservoir under full coupling. Based on the further development of a cohesive finite element, a new dual-attribute element of pore fluid/stress element and cohesive element (PFS-Cohesive) method for a rock matrix is put forward to realize the simulation of an artificial fracture propagating along the arbitrary path. The effect of a single spontaneous fracture, two intersected natural fractures, and multiple intersected spontaneous fractures on the expansion of an artificial fracture is analyzed by this method. Numerical simulation results show that the in situ stress, approaching angle between the artificial fracture and natural fracture, and natural fracture cementation strength have a significant influence on the propagation morphology of the fracture. When two intersected natural fractures exist, the second one will inhibit the propagation of artificial fractures along the small angle of the first natural fractures. Under different in situ stress differences, the length as well as aperture of the hydraulic fracture in a rock matrix increases with the development of cementation superiority of natural fractures. And with the increasing of in situ horizontal stress differences, the length of the artificial fracture in a rock matrix decreases, while the aperture increases. The numerical simulation result of the influence of a single natural fracture on the propagation of an artificial fracture is in agreement with that of the experiment, which proves the accuracy of the PFS-Cohesive FEM for simulating hydraulic fracturing in shale gas reservoirs.

A Case Study Using Integrated Multi Disciplinary Approach to Model Microseismic Events During Stimulation

2021 ◽  
Author(s):  
Ghazal Izadi ◽  
Colleen Barton ◽  
Pierre-Francois Roux ◽  
Tebis Llobet ◽  
Thiago Pessoa ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Natural Fracture ◽  
Fracture Model ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Unconventional Reservoir ◽  
Geological Conditions ◽  
Source Mechanisms

Abstract For tight reservoirs where hydraulic fracturing is required to enable sufficient fluid mobility for economic production, it is critical to understand the placement of induced fractures, their connectivity, extent, and interaction with natural fractures within the system. Hydraulic fracture initiation and propagation mechanisms are greatly influenced by the effect of the stress state, rock fabric and pre-existing features (e.g. natural fractures, faults, weak bedding/laminations). A pre-existing natural fracture system can dictate the mode, orientation and size of the hydraulic fracture network. A better understanding of the fracture growth phenomena will enhance productivity and also reduce the environmental footprint as less fractures can be created in a much more efficient way. Assessing the role of natural fractures and their interaction with hydraulic fractures in order to account for them in the hydraulic fracture model is achieved by leveraging microseismicity. In this study, we have used a combination of borehole and surface microseismic monitoring to get high vertical resolution locations and source mechanisms. 3D numerical modelling of hydraulic fracturing in complex geological conditions to predict fracture propagation is essential. 3D hydraulic fracturing simulation includes modelling capabilities of stimulation parameters, true 3D fracture propagation with near wellbore 3D complexity including a coupled DFN and the associated microseismic event generation capability. A 3D hydraulic fracture model was developed and validated by matching model predictions to microseismic observations. Microseismic source mechanisms are leveraged to determine the location and geometry of pre-existing features. In this study, we simulate a DFN based on the recorded seismicity of multi stage hydraulic fractures in a horizontal well. The advanced 3D hydraulic fracture modelling software can integrate effectively and efficiently data from a variety of multi-disciplinary sources and scales to create a subsurface characterization of the unconventional reservoir. By incorporating data from 3D seismic, LWD/wireline, core, completion/stimulation monitoring, and production, the software generates a holistic reservoir model embedded in a modular, multi-physics software platform of coupled numerical solvers that capture the fundamental physics of the processes being modelled. This study illustrates the importance of a powerful software tool that captures the necessary physics of stimulation to predict the effects of various completion designs and thereby ensure the most accurate representation of an unconventional reservoir response to a stimulation treatment.

Numerical Simulation Study of Proppant Transport in Cross Fractures

2022 ◽  
Author(s):  
Cong Lu ◽  
Li Ma ◽  
Jianchun Guo
Keyword(s):  
Hydraulic Fracturing ◽  
Transport Model ◽  
Injection Rate ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Fluid Viscosity ◽  
Natural Fractures ◽  
Fracturing Fluid ◽  
Proppant Transport ◽  
Approach Angle

Abstract Hydraulic fracturing technology is an important means to stimulate unconventional reservoirs, and the placement morphology of proppant in cross fractures is a key factor affecting the effect of hydraulic fracturing. It is very important to study the proppant transport law in cross fractures. In order to study the proppant transportation law in cross fractures, based on the CFD-DEM method, a proppant transport model in cross fractures was established. From the two aspects of the flow field in the fractures and the morphology of the proppant dune, the influence of the natural fracture approach angle, the fracturing fluid viscosity and injection rate on the proppant transport is studied. Based on the principle of hydropower similarity, the conductivity of proppant dune under different conditions is quantitatively studied. The results show that the natural fracture approach angle affects the distribution of proppant and fracturing fluid in natural fractures, and further affects the proppant placement morphology in hydraulic fractures and natural fractures. When the fracturing fluid viscosity is low and the displacement is small, the proppant forms a "high and narrow" dune at the entrance of the fracture. With the increase of the fracturing fluid viscosity and injection rate, the proppant settles to form a "short and wide" placement morphology. Compared with the natural fracture approach angle, the fracturing fluid viscosity and injection rate have a more significant impact on the conductivity of proppant dune. This paper investigated the proppant transportation in cross fractures, and quantitatively analyzes the conductivity of proppant dunes with different placement morphology. The results of this study can provide theoretical guidance for the design of hydraulic fracturing.

scholarly journals Experimental and Numerical Investigation on Basic Law of Dense Linear Multihole Directional Hydraulic Fracturing

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-19
Author(s):  
Xin Zhang ◽  
Yuqi Zhang
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Large Scale ◽  
Pore Water Pressure ◽  
Water Pressure ◽  
In Situ Stress ◽  
Hydraulic Fractures ◽  
Directional Hydraulic Fracturing ◽  
Basic Law

Using the dense linear multihole to control the directional hydraulic fracturing is a significant technical method to realize roof control in mining engineering. By combining the large-scale true triaxial directional hydraulic fracturing experiment with the discrete element numerical simulation experiment, the basic law of dense linear holes controlling directional hydraulic fracturing was studied. The results show the following: (1) Using the dense linear holes to control directional hydraulic fracturing can effectively form directional hydraulic fractures extending along the borehole line. (2) The hydraulic fracturing simulation program is very suitable for studying the basic law of directional hydraulic fracturing. (3) The reason why the hydraulic fracture can be controlled and oriented is that firstly, due to the mutual compression between the dense holes, the maximum effective tangential tensile stress appears on the connecting line of the drilling hole, where the hydraulic fracture is easy to be initiated. Secondly, due to the effect of pore water pressure, the disturbed stress zone appears at the tip of the hydraulic fracture, and the stress concentration zone overlaps with each other to form the stress guiding strip, which controls the propagation and formation of directional hydraulic fractures. (4) The angle between the drilling line and the direction of the maximum principal stress, the in situ stress, and the hole spacing has significant effects on the directional hydraulic fracturing effect. The smaller the angle, the difference of the in situ stress, and the hole spacing, the better the directional hydraulic fracturing effect. (5) The directional effect of synchronous hydraulic fracturing is better than that of sequential hydraulic fracturing. (6) According to the multihole linear codirectional hydraulic fracturing experiments, five typical directional hydraulic fracture propagation modes are summarized.

scholarly journals Numerical Modelling of Interaction between Hydraulic Fractures and Natural Fractures by Using the Extended Finite Element Method

2020 ◽  
Vol 2020 ◽  
pp. 1-9
Author(s):  
Peilun Li ◽  
Yan Dong ◽  
Sheng Wang ◽  
Peichao Li
Keyword(s):  
Finite Element Method ◽  
Finite Element ◽  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Extended Finite Element Method ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Extended Finite Element ◽  
Element Method

Natural fractures usually develop in shale reservoirs. Thereby, in the process of hydraulic fracturing, it is inevitable that hydraulic fractures will intersect with natural fractures. In order to reveal the interaction mechanism between hydraulic-induced fractures and natural fractures, a two-dimensional fracture intersection model based on the extended finite element method (XFEM) is proposed, and the different types of intersecting criteria reported in the literature are compared. Then, the effects of natural fracture azimuth, fluid pressure in hydraulic fracture, and in situ principal stress difference on hydraulic fracturing are studied in detail. The results show that the fracture morphology is different under different criteria and working conditions. And the stress concentration phenomenon mainly concentrates on the tip in the obtuse angle side of natural fracture. Meanwhile, different fluid pressures in hydraulic fracture can also induce different intersection patterns. The obtained results in this work are of great benefit to understand the intersection mechanism between hydraulic fractures and natural fractures.

Sign in / Sign up

Export Citation Format

Share Document