Deviation of hydraulic fractures through poroelastic stress changes induced by fluid injection and pumping

1997 ◽  
Vol 34 (6) ◽  
pp. 1009-1019 ◽  
Author(s):  
I. Berchenko ◽  
E. Detournay
Keyword(s):  
Fluid Injection ◽  
Hydraulic Fractures ◽  
Stress Changes

Dynamic Modeling of Channel Formation During Fluid Injection Into Unconsolidated Formations

SPE Journal ◽  
2015 ◽  
Vol 20 (04) ◽  
pp. 689-700 ◽  
Author(s):  
S.. Ameen ◽  
A. Dahi Taleghani
Keyword(s):  
Preferential Flow ◽  
Volume Fraction ◽  
Injection Pressure ◽  
Internal Erosion ◽  
Fluid Injection ◽  
Critical Threshold ◽  
Model Parameters ◽  
Flow Paths ◽  
Preferential Flow Paths ◽  
Stress Changes

Summary Injectivity loss is a common problem in unconsolidated-sand formations. Injection of water into a poorly cemented granular medium may lead to internal erosion, and consequently formation of preferential flow paths within the medium because of channelization. Channelization in the porous medium might occur when fluid-induced stresses become locally larger than a critical threshold and small grains are dislodged and carried away; hence, porosity and permeability of the medium will evolve along the induced flow paths. Vice versa, flowback during shut-in might carry particles back to the well and cause sand accumulation inside the well, and subsequently loss of injectivity. In most cases, to maintain the injection rate, operators will increase injection pressure and pumping power. The increased injection pressure results in stress changes and possibly further changes in channel patterns around the wellbore. Experimental laboratory studies have confirmed the presence of the transition from uniform Darcy flow to a fingered-pattern flow. To predict these phenomena, a model is needed to fill this gap by predicting the formation of preferential flow paths and their evolution. A model based on the multiphase-volume-fraction concept is used to decompose porosity into mobile and immobile porosities where phases may change spatially, evolve over time, and lead to development of erosional channels depending on injection rates, viscosity, and rock properties. This model will account for both particle release and suspension deposition. By use of this model, a methodology is proposed to derive model parameters from routine injection tests by inverse analysis. The proposed model presents the characteristic behavior of unconsolidated formation during fluid injection and the possible effect of injection parameters on downhole-permeability evolution.

Fluid-induced aseismic fault slip outpaces pore-fluid migration

Science ◽  
2019 ◽  
Vol 364 (6439) ◽  
pp. 464-468 ◽  
Author(s):  
Pathikrit Bhattacharya ◽  
Robert C. Viesca
Keyword(s):  
Pore Fluid ◽  
Fluid Injection ◽  
Fluid Migration ◽  
Aseismic Slip ◽  
Earthquake Triggering ◽  
Effective Normal Stress ◽  
Shear Rupture ◽  
Stress Changes ◽  
Slip History ◽  
Rupture Model

Earthquake swarms attributed to subsurface fluid injection are usually assumed to occur on faults destabilized by increased pore-fluid pressures. However, fluid injection could also activate aseismic slip, which might outpace pore-fluid migration and transmit earthquake-triggering stress changes beyond the fluid-pressurized region. We tested this theoretical prediction against data derived from fluid-injection experiments that activated and measured slow, aseismic slip on preexisting, shallow faults. We found that the pore pressure and slip history imply a fault whose strength is the product of a slip-weakening friction coefficient and the local effective normal stress. Using a coupled shear-rupture model, we derived constraints on the hydromechanical parameters of the actively deforming fault. The inferred aseismic rupture front propagates faster and to larger distances than the diffusion of pressurized pore fluid.

Fracture Initiation and Propagation in a Deep Shale Gas Reservoir Subject to an Alternating-Fluid-Injection Hydraulic-Fracturing Treatment

SPE Journal ◽  
2019 ◽  
Vol 24 (04) ◽  
pp. 1839-1855 ◽  
Author(s):  
Bing Hou ◽  
Zhi Chang ◽  
Weineng Fu ◽  
Yeerfulati Muhadasi ◽  
Mian Chen
Keyword(s):  
Hydraulic Fracturing ◽  
Shale Gas ◽  
Fracture Initiation ◽  
Fluid Injection ◽  
Hydraulic Fractures ◽  
Stress Difference ◽  
Gas Reservoirs ◽  
Complex Fracture ◽  
Initiation And Propagation

Summary Deep shale gas reservoirs are characterized by high in-situ stresses, a high horizontal-stress difference (12 MPa), development of bedding seams and natural fractures, and stronger plasticity than shallow shale. All of these factors hinder the extension of hydraulic fractures and the formation of complex fracture networks. Conventional hydraulic-fracturing techniques (that use a single fluid, such as guar fluid or slickwater) do not account for the initiation and propagation of primary fractures and the formation of secondary fractures induced by the primary fractures. For this reason, we proposed an alternating-fluid-injection hydraulic-fracturing treatment. True triaxial hydraulic-fracturing tests were conducted on shale outcrop specimens excavated from the Shallow Silurian Longmaxi Formation to study the initiation and propagation of hydraulic fractures while the specimens were subjected to an alternating fluid injection with guar fluid and slickwater. The initiation and propagation of fractures in the specimens were monitored using an acoustic-emission (AE) system connected to a visual display. The results revealed that the guar fluid and slickwater each played a different role in hydraulic fracturing. At a high in-situ stress difference, the guar fluid tended to open the transverse fractures, whereas the slickwater tended to activate the bedding planes as a result of the temporary blocking effect of the guar fluid. On the basis of the development of fractures around the initiation point, the initiation patterns were classified into three categories: (1) transverse-fracture initiation, (2) bedding-seam initiation, and (3) natural-fracture initiation. Each of these fracture-initiation patterns had a different propagation mode. The alternating-fluid-injection treatment exploited the advantages of the two fracturing fluids to form a large complex fracture network in deep shale gas reservoirs; therefore, we concluded that this method is an efficient way to enhance the stimulated reservoir volume compared with conventional hydraulic-fracturing technologies.

scholarly journals The 2017 Mw 5.5 Pohang Earthquake, South Korea, and Poroelastic Stress Changes Associated With Fluid Injection

2020 ◽  
Vol 125 (6) ◽  
Author(s):  
H. Lim ◽  
K. Deng ◽  
Y.H. Kim ◽  
J.‐H. Ree ◽  
T.‐R. A. Song ◽  
...  
Keyword(s):  
South Korea ◽  
Fluid Injection ◽  
Stress Changes

scholarly journals Fault slip in hydraulic stimulation of geothermal reservoirs: Governing mechanisms and process-structure interaction

2020 ◽  
Vol 39 (12) ◽  
pp. 893-900
Author(s):  
Inga Berre ◽  
Ivar Stefansson ◽  
Eirik Keilegavlen
Keyword(s):  
Fault Reactivation ◽  
Fluid Injection ◽  
Hydraulic Stimulation ◽  
Structure Interaction ◽  
Geothermal Reservoirs ◽  
Biot Coefficient ◽  
Matrix Permeability ◽  
Stress Changes ◽  
Process Structure ◽  
Stimulation Of

Hydraulic stimulation of geothermal reservoirs in low-permeability basement and crystalline igneous rock can enhance permeability by reactivation and shear dilation of existing fractures. The process is characterized by interaction between fluid flow, deformation, and the fractured structure of the formation. The flow is highly affected by the fracture network, which in turn is deformed because of hydromechanical stress changes caused by the fluid injection. This process-structure interaction is decisive for the outcome of hydraulic stimulation, and, in analysis of governing mechanisms, physics-based modeling has potential to complement field and experimental data. Here, we show how recently developed simulation technology is a valuable tool to understand governing mechanisms of hydromechanical coupled processes and the reactivation and deformation of faults. The methodology fully couples flow in faults and matrix with poroelastic matrix deformation and a contact mechanics model for the faults, including dilation because of slip. Key elements are high aspect ratios of faults and strong nonlinearities in highly coupled governing equations. Example simulations using our open-source software illustrate direct and indirect hydraulic fault reactivation and corresponding permeability enhancement. We investigate the effect of the fault and matrix permeability and the Biot coefficient. A higher matrix permeability leads to more leakage from a permeable fault and thus suppresses reactivation and slip of the fault compared to the case with a lower matrix permeability. If a fault is a barrier to flow, increase of pressure because of the fluid injection results in stabilization of the fault; the situation is opposite if the fault is highly permeable compared to the matrix. For the given setup, lowering the Biot coefficient results in more slip than the base case. While conceptually simple, the examples illustrate the strong hydromechanical couplings and the prospects of physics-based numerical models in investigating the dynamics.

Multi-phase hydromechanical modeling of induced seismicity: general insights and the case study of the deep geothermal project in St. Gallen, Switzerland

2020 ◽  
Author(s):  
Dominik Zbinden ◽  
Antonio Pio Rinaldi ◽  
Tobias Diehl ◽  
Stefan Wiemer
Keyword(s):  
Fluid Flow ◽  
Induced Seismicity ◽  
Gas Flow ◽  
Fluid Injection ◽  
Induced Earthquakes ◽  
Stress Changes ◽  
Reservoir Conditions ◽  
Multi Phase ◽  
Phase Fluid

<p>Industrial projects that involve fluid injection into the deep underground (e.g., geothermal energy, wastewater disposal) can induce seismicity, which may jeopardize the acceptance of such geo-energy projects and, in the case of larger induced earthquakes, damage infrastructure and pose a threat to the population. Such earthquakes can occur because fluid injection yields pressure and stress changes in the subsurface, which can reactivate pre-existing faults. Many studies have so far focused on injection into undisturbed reservoir conditions (i.e., hydrostatic pressure and single-phase flow), while only very few studies consider disturbed <em>in-situ</em> conditions including multi-phase fluid flow (i.e., gas and water). Gas flow has been suggested as a trigger mechanism of aftershocks in natural seismic sequences and can play an important role at volcanic sites. In addition, the deep geothermal project in St. Gallen, Switzerland, is a unique case study where an induced seismic sequence occurred almost simultaneously with a gas kick, suggesting that the gas may have affected the induced seismicity.</p><p>Here, we focus on the hydro-mechanical modeling of fluid injection into disturbed reservoir conditions considering multi-phase fluid flow. We couple the fluid flow simulator TOUGH2 with different geomechanical codes to study the effect of gas on induced seismicity in general and in the case of St. Gallen. The results show that overpressurized gas can affect the size and timing of induced earthquakes and that it may have contributed to enhance the induced seismicity in St. Gallen. Our findings can lead to a more detailed understanding of the influence of a gas phase on the induced seismicity.</p>

Simulation of Stress Changes of Shale Reservoirs during Hydraulic Fracturing to Create Fracture Networks

2013 ◽  
Vol 419 ◽  
pp. 10-16
Author(s):  
G.M. Zhang ◽  
J.D. Liu ◽  
C.M. Xiong ◽  
H. Liu ◽  
J. Jin
Keyword(s):  
Pore Pressure ◽  
Hydraulic Fracture ◽  
Theoretical Data ◽  
Element Model ◽  
Hydraulic Fractures ◽  
Theoretical Studies ◽  
Fracture Networks ◽  
Stress Anisotropy ◽  
Stress Changes ◽  
Simulation Results

Theoretical studies have shown that the generation of hydraulic fractures reduces or even reverses the stress anisotropy between the fractures and results in increasing the complexity of fractures. A finite element model was established in which the pore pressure element was used to simulate the behavior of porous media and the pore pressure cohesive element was adopted to catch the characters of hydraulic fracture. A special fracturing manner was adopted to create complicated fracture networks by reducing or even reversing the stress anisotropy between fractures. The geometries of hydraulic fractures, strains, stresses, pore pressure distributions and fluid pressures within the fractures are obtained. The results of the model are fit well with the corresponding theoretical data. The simulation results show that the stress anisotropy is reduced resulting from the generation of the hydraulic fracture, multiple parallel transverse fractures of horizontal well further reduce or even reverse the stress anisotropy in some place of the reservoir. The simulation results validate the feasibility of the theoretical studies and the expected complex network fractures could be created by adopting the special fracturing manner.

The effect of kerogen on the elastic anisotropy of organic-rich shales

Geophysics ◽  
2013 ◽  
Vol 78 (2) ◽  
pp. D65-D74 ◽  
Author(s):  
Colin M. Sayers
Keyword(s):  
Elastic Properties ◽  
Trajectory Optimization ◽  
Elastic Anisotropy ◽  
In Situ Stress ◽  
Hydraulic Fractures ◽  
Deformation And Failure ◽  
Reservoir Rocks ◽  
Stress Changes ◽  
Shale Anisotropy

The elastic properties of reservoir rocks are important for geomechanics applications; the most important of which are: analysis of stress changes due to production, analysis of rock deformation and failure, wellbore trajectory optimization, and the design of hydraulic fractures. Organic-rich shales are often observed to be strongly anisotropic due to the partial alignment of anisotropic clay minerals and the bedding-parallel lamination of organic material within the shale. Neglecting shale anisotropy may lead to incorrect estimates of the in situ stress or stress changes resulting from production. As a result, isotropic models may fail to describe geomechanical behavior correctly. The distribution of the organic phase plays an important role in determining the elastic properties of organic-rich shales, and this has a significant effect on production-induced stress changes. The presence of kerogen leads to a decrease in all of the elastic moduli, and has a significant effect on the geomechanical behavior of shales. The change in horizontal effective stress for a given change in pore pressure resulting from production is greater for kerogen-rich shales, and the neglect of anisotropy in predicting such stress changes may lead to significant errors.

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