scholarly journals Cascading earthquakes on a fracture network in a geo-energy reservoir

2021 ◽  
Author(s):  
Kadek Hendrawan Palgunadi ◽  
Alice-Agnes Gabriel ◽  
Dimitry Garagash ◽  
Paul Martin Mai
Keyword(s):  
Fracture Network ◽  
Stress Conditions ◽  
Moment Magnitude ◽  
Fluid Injection ◽  
Fracture Density ◽  
Dynamic Rupture ◽  
Induced Earthquakes ◽  
Complex Fracture ◽  
Initial Rupture ◽  
Main Fault

<p>The increasing rate of induced seismicity in subsurface reservoirs, exceeding occasionally moment magnitude 5, has generated significant attention among earthquake scientists and regulators over the last decade. Fluid injection activity during the operation stage often produces a significant, sometimes even destructive, earthquake. Many approaches have been proposed to monitor, model, and predict the injection-related seismicity to avoid an earthquake larger than a threshold set by the regulator (e.g., Mw 2.0). However, unexpected higher magnitude events occur exceeding what is predicted by empirical models, theoretical relations, or computer simulations. </p><p>Current models do not consider that subsurface reservoirs consist of complex fracture networks characterized by connected and unconnected individual fracture planes, often comprising a larger but inactive fault (unfavorably oriented with respect to regional stress). Fluid injection may then perturb stress conditions and trigger an initial rupture on fractures close to the injection well; this initial event may then dynamically trigger other fractures and potentially generate a large earthquake. </p><p>We inspect conditions leading to induced earthquakes taking into account the complex fracture network intersected to an inactive fault using dynamic earthquake rupture simulations. We generate the fracture network using a nearest-neighbor method following statistical parameters (power-law distribution of fracture length and fracture density) based on field data. There are 134 fractures consisting of 95 connected fractures, 3 fractures connected with at least one fracture, and 38 unconnected fractures. We focus on two fracture populations oriented in strike N110E ± 10° and N210E ± 10°, respectively. The main fault has a depth-dependent dip orientation which results in a listric fault geometry. </p><p>For our dynamic rupture simulations, we use the open-source software SeisSol (https://github.com/SeisSol/SeisSol), apply a laboratory-based rate-and-state with rapid velocity weakening friction law, and assign source radius-dependent characteristic length (L parameter) to the fractures. We vary stress conditions (maximum horizontal orientation, static-pore pressure, and prestress ratio) and conduct an initial static Mohr-Coulomb analysis before running the expensive dynamic rupture simulation. We choose conditions that lead to cascading rupture with (case 1) and without (case 2) the involvement of the main fault. Case 1 has higher artificial overstress within the nucleation area than case 2. Our simulation shows intricate rupture progression over small fractures via rupture branching with the parallel and orthogonal connected fractures. The rupture can also transfer to the unconnected fractures through dynamic triggering from the closest neighboring fracture. Case 1 produces a moment magnitude of Mw 6.36 that is equivalent to case 2. Our preliminary result reveals that connected fractures can generate a significant and potentially large induced earthquake if all fractures are favorable to the stress condition.</p>

scholarly journals Dynamic Fault Interaction during a Fluid-Injection-Induced Earthquake: The 2017 Mw 5.5 Pohang Event

2020 ◽  
Vol 110 (5) ◽  
pp. 2328-2349
Author(s):  
Kadek Hendrawan Palgunadi ◽  
Alice-Agnes Gabriel ◽  
Thomas Ulrich ◽  
José Ángel López-Comino ◽  
Paul Martin Mai
Keyword(s):  
Fault Plane ◽  
Fluid Pressure ◽  
Local Stress ◽  
Stress Conditions ◽  
Fluid Injection ◽  
Geothermal System ◽  
Dynamic Rupture ◽  
Fault Interaction ◽  
Induced Earthquake ◽  
Secondary Fault

ABSTRACT The 15 November 2017 Mw 5.5 Pohang, South Korea, earthquake has been linked to hydraulic stimulation and fluid injections, making it the largest induced seismic event associated with an enhanced geothermal system. To understand its source dynamics and fault interactions, we conduct the first 3D high-resolution spontaneous dynamic rupture simulations of an induced earthquake. We account for topography, off-fault plastic deformation under depth-dependent bulk cohesion, rapid velocity weakening friction, and 1D subsurface structure. A guided fault reconstruction approach that clusters spatiotemporal aftershock locations (including their uncertainties) is used to identify a main and a secondary fault plane that intersect under a shallow angle of 15°. Based on simple Mohr–Coulomb failure analysis and 180 dynamic rupture experiments in which we vary local stress loading conditions, fluid pressure, and relative fault strength, we identify a preferred two-fault-plane scenario that well reproduces observations. We find that the regional far-field tectonic stress regime promotes pure strike-slip faulting, whereas local stress conditions constrained by borehole logging generate the observed thrust-faulting component. Our preferred model is characterized by overpressurized pore fluids, nonoptimally oriented but dynamically weak faults and a close-to-critical local stress state. In our model, earthquake rupture “jumps” to the secondary fault by dynamic triggering, generating a measurable non-double-couple component. Our simulations suggest that complex dynamic fault interaction may occur during fluid-injection-induced earthquakes and that local stress perturbations dominate over regional stress conditions. Therefore, our findings have important implications for seismic hazard in active georeservoir.

scholarly journals Numerical Investigation of Fracture Compressibility and Uncertainty on Water-Loss and Production Performance in Tight Oil Reservoirs

Energies ◽  
2019 ◽  
Vol 12 (7) ◽  
pp. 1189 ◽  
Author(s):  
Kai Liao ◽  
Shicheng Zhang ◽  
Xinfang Ma ◽  
Yushi Zou
Keyword(s):  
Water Loss ◽  
Fracture Network ◽  
Production Performance ◽  
Oil Reservoirs ◽  
Natural Fracture ◽  
Tight Oil ◽  
Fracture Density ◽  
Breakthrough Time ◽  
Complex Fracture ◽  
Fracture Closure

Multi-stage hydraulic fracturing along with horizontal wells are widely used to create complex fracture networks in tight oil reservoirs. Analysis of field flowback data shows that most of the fracturing fluids are contained in a complex fracture network, and fracture-closure is the main driving mechanism during early clean up. At present, the related fracture parameters cannot be accurately obtained, so it is necessary to study the impacts of fracture compressibility and uncertainty on water-loss and the subsequent production performance. A series of mechanistic models are established by considering stress-dependent porosity and permeability. The impacts of fracture uncertainties, such as natural fracture density, proppant distribution, and natural fracture heterogeneity on flowback and productivity are quantitatively assessed. Results indicate that considering fracture closure during flowback can promote water imbibition into the matrix and delay the oil breakthrough time compared with ignoring fracture closure. With the increase of natural fracture density, oil breakthrough time is advanced, and more water is retained underground. When natural fractures connected with hydraulic fractures are propped, well productivity will be enhanced, but proppant embedment can cause a loss of oil production. Additionally, the fracture network with more heterogeneity will lead to the lower flowback rate, which presents an insight in the role of fractures in water-loss.

Numerical Simulation of Complex Fracture Network Development by Hydraulic Fracturing in Naturally Fractured Ultratight Formations

2013 ◽  
Author(s):  
Hannes Hofmann ◽  
Tayfun Babadagli ◽  
Günter Zimmermann
Keyword(s):  
Fracture Network ◽  
Natural Fracture ◽  
Fracture Networks ◽  
Network Development ◽  
Complex Fracture ◽  
Fracture Patterns ◽  
Fracture Systems ◽  
Fracture Development ◽  
Complex Fracture Network ◽  
Treatment Designs

The creation of large complex fracture networks by hydraulic fracturing is imperative for enhanced oil recovery from tight sand or shale reservoirs, tight gas extraction, and Hot-Dry-Rock (HDR) geothermal systems to improve the contact area to the rock matrix. Although conventional fracturing treatments may result in bi-wing fractures, there is evidence by microseismic mapping that fracture networks can develop in many unconventional reservoirs, especially when natural fracture systems are present and the differences between the principle stresses are low. However, not much insight is gained about fracture development as well as fluid and proppant transport in naturally fractured tight formations. In order to clarify the relationship between rock and treatment parameters, and resulting fracture properties, numerical simulations were performed using a commercial Discrete Fracture Network (DFN) simulator. A comprehensive sensitivity analysis is presented to identify typical fracture network patterns resulting from massive water fracturing treatments in different geological conditions. It is shown how the treatment parameters influence the fracture development and what type of fracture patterns may result from different treatment designs. The focus of this study is on complex fracture network development in different natural fracture systems. Additionally, the applicability of the DFN simulator for modeling shale gas stimulation and HDR stimulation is critically discussed. The approach stated above gives an insight into the relationships between rock properties (specifically matrix properties and characteristics of natural fracture systems) and the properties of developed fracture networks. Various simulated scenarios show typical conditions under which different complex fracture patterns can develop and prescribe efficient treatment designs to generate these fracture systems. Hydraulic stimulation is essential for the production of oil, gas, or heat from ultratight formations like shales and basement rocks (mainly granite). If natural fracture systems are present, the fracturing process becomes more complex to simulate. Our simulation results reveal valuable information about main parameters influencing fracture network properties, major factors leading to complex fracture network development, and differences between HDR and shale gas/oil shale stimulations.

Analyzing the Impacts of Meshing and Grid Alignment in Dual-Porosity Dual-Permeability Upscaling

2021 ◽  
pp. 1-20
Author(s):  
Ziming Xu ◽  
Juliana Y. Leung
Keyword(s):  
Fracture Network ◽  
Fracture Plane ◽  
Fracture Density ◽  
Shape Factors ◽  
Stimulated Reservoir Volume ◽  
Reservoir Volume ◽  
Multiple Length Scales ◽  
Fracture Intensity ◽  
Cumulative Production ◽  
The Difference

Summary The discrete fracture network (DFN) model is widely used to simulate and represent the complex fractures occurring over multiple length scales. However, computational constraints often necessitate that these DFN models be upscaled into a dual-porositydual-permeability (DPDK) model and discretized over a corner-point grid system, which is still commonly implemented in many commercial simulation packages. Many analytical upscaling techniques are applicable, provided that the fracture density is high, but this condition generally does not hold in most unconventional reservoir settings. A particular undesirable outcome is that connectivity between neighboring fracture cells could be erroneously removed if the fracture plane connecting the two cells is not aligned along the meshing direction. In this work, we propose a novel scheme to detect such misalignments and to adjust the DPDK fracture parameters locally, such that the proper fracture connectivity can be restored. A search subroutine is implemented to identify any diagonally adjacent cells of which the connectivity has been erroneously removed during the upscaling step. A correction scheme is implemented to facilitate a local adjustment to the shape factors in the vicinity of these two cells while ensuring the local fracture intensity remains unaffected. The results are assessed in terms of the stimulated reservoir volume calculations, and the sensitivity to fracture intensity is analyzed. The method is tested on a set of tight oil models constructed based on the Bakken Formation. Simulation results of the corrected, upscaled models are closer to those of DFN simulations. There is a noticeable improvement in the production after restoring the connectivity between those previously disconnected cells. The difference is most significant in cases with medium DFN density, where more fracture cells become disconnected after upscaling (this is also when most analytical upscaling techniques are no longer valid); in some 2D cases, up to a 22% difference in cumulative production is recorded. Ignoring the impacts of mesh discretization could result in an unintended reduction in the simulated fracture connectivity and a considerable underestimation of the cumulative production.

scholarly journals Performance-based fractal fracture model for complex fracture network simulation

2017 ◽  
Vol 15 (1) ◽  
pp. 126-134 ◽  
Author(s):  
Wen-Dong Wang ◽  
Yu-Liang Su ◽  
Qi Zhang ◽  
Gang Xiang ◽  
Shi-Ming Cui
Keyword(s):  
Network Simulation ◽  
Fracture Network ◽  
Fracture Model ◽  
Complex Fracture ◽  
Complex Fracture Network ◽  
Fractal Fracture

scholarly journals A New Approach for Automatic Optimization of Complex Fracture Network in Shale Reservoirs

Lithosphere ◽  
2021 ◽  
Vol 2021 (Special 1) ◽  
Author(s):  
Haibo Wang ◽  
Tong Zhou ◽  
Fengxia Li
Keyword(s):  
Shale Gas ◽  
Flow Model ◽  
Optimization Method ◽  
Fracture Network ◽  
Gas Reservoirs ◽  
Fracture Length ◽  
Complex Fracture ◽  
Shale Gas Reservoirs ◽  
Automatic Optimization ◽  
Complex Fracture Network

Abstract Shale gas reservoirs have gradually become the main source for oil and gas production. The automatic optimization technology of complex fracture network in fractured horizontal wells is the key technology to realize the efficient development of shale gas reservoirs. In this paper, based on the flow model of shale gas reservoirs, the porosity/permeability of the matrix system and natural fracture system is characterized. The fracture network morphology is finely characterized by the fracture network expansion calculation method, and the flow model was proposed and solved. On this basis, the influence of matrix permeability, matrix porosity, fracture permeability, fracture porosity, and fracture length on the production of shale gas reservoirs is studied. The optimal design of fracture length and fracture location was carried, and the automatic optimization method of complex fracture network parameters based on simultaneous perturbation stochastic approximation (SPSA) was proposed. The method was applied in a shale gas reservoir, and the results showed that the proposed automatic optimization method of the complex fracture network in shale gas reservoirs can automatically optimize the parameters such as fracture location and fracture length and obtain the optimal fracture network distribution matching with geological conditions.

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