Hydraulic fracturing has been inferred to trigger the majority of injection-induced earthquakes in western Canada, in contrast to the Midwestern United States, where massive saltwater disposal is the dominant triggering mechanism. A template-based earthquake catalog from a seismically active Canadian shale play, combined with comprehensive injection data during a 4-month interval, shows that earthquakes are tightly clustered in space and time near hydraulic fracturing sites. The largest event [moment magnitude (MW) 3.9] occurred several weeks after injection along a fault that appears to extend from the injection zone into crystalline basement. Patterns of seismicity indicate that stress changes during operations can activate fault slip to an offset distance of >1 km, whereas pressurization by hydraulic fracturing into a fault yields episodic seismicity that can persist for months.

https://science.sciencemag.org/content/sci/354/6318/1406.full.pdf

Fault activation by hydraulic fracturing in western Canada.

3D computer simulations and experiments are employed to study random packings of compressible spherical grains under external confining stress. In the rigid ball limit, we find a continuous transition in which the stress vanishes as (straight phi-straight phi(c))(beta), where straight phi is the (solid phase) volume density. The value of straight phi(c) depends on whether the grains interact via only normal forces (giving rise to random close packings) or by a combination of normal and friction generated transverse forces (producing random loose packings). In both cases, near the transition, the system's response is controlled by localized force chains.

Packings of Compressible Granular Materials

A recently developed unconventional fracture model (UFM) is able to simulate complex fracture network propagation in a formation with pre-existing natural fractures. A method for computing the stress shadow from fracture branches in a complex hydraulic fracture network (HFN) based on an enhanced 2D displacement discontinuity method with correction for finite fracture height is implemented in UFM and is presented in detail including approach validation and examples. The influence of stress shadow effect from the HFN generated at previous treatment stage on the HFN propagation and shape at new stage is also discussed.

Numerical Modeling of Hydraulic Fractures Interaction In Complex Naturally Fractured Formations

Numerical Modeling of Hydraulic Fractures Interaction in Complex Naturally Fractured Formations

Multistage fracturing of the horizontal well is recognized as the main stimulation technology for shale gas development. The hydraulic fracture geometry and stimulated reservoir volume (SRV) is interpreted by using the microseismic mapping technology. In this paper, we used a computerized tomography (CT) scanning technique to reveal the fracture geometry created in natural bedding-developed shale (cubic block of 30 cm × 30 cm × 30 cm) by laboratory fracturing. Experimental results show that partially opened bedding planes are helpful in increasing fracture complexity in shale. However, they tend to dominate fracture patterns for vertical stress difference Δσ
 v
  ≤ 6 MPa, which decreases the vertical fracture number, resulting in the minimum SRV. A uniformly distributed complex fracture network requires the induced hydraulic fractures that can connect the pre-existing fractures as well as pulverize the continuum rock mass. In typical shale with a narrow (<0.05 mm) and closed natural fracture system, it is likely to create complex fracture for horizontal stress difference Δσ
 h
  ≤ 6 MPa and simple transverse fracture for Δσ
 h
  ≥ 9 MPa. However, high naturally fractured shale with a wide open natural fracture system (>0.1 mm) does not agree with the rule that low Δσ
 h
 is favorable for uniformly creating a complex fracture network in zone. In such case, a moderate Δσ
 h
 from 3 to 6 MPa is favorable for both the growth of new hydraulic fractures and the activation of a natural fracture system. Shale bedding, natural fracture, and geostress are objective formation conditions that we cannot change; we can only maximize the fracture complexity by controlling the engineering design for fluid viscosity, flow rate, and well completion type. Variable flow rate fracturing with low-viscosity slickwater fluid of 2.5 mPa s was proved to be an effective treatment to improve the connectivity of induced hydraulic fracture with pre-existing fractures. Moreover, the simultaneous fracturing can effectively reduce the stress difference and increase the fracture number, making it possible to generate a large-scale complex fracture network, even for high Δσ
 h
 from 6 MPa to 12 MPa.

Experimental Investigation into Hydraulic Fracture Network Propagation in Gas Shales Using CT Scanning Technology

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A general poro-elastic model for pad-scale fracturing of horizontal wells

Hydraulic fracturing in shale formations induces microseismic events in a region we refer to as the microseismic volume. Many of these microseismic events are signatures of failure in the formation that are believed to be a result of induced unpropped (IU) fractures beyond the primary propped fracture. Areally extensive microseismicity may be evidence that these IU fractures occur and extend spatially beyond the propped fracture during pumping in many unconventional reservoirs. We present evidence that these fractures close over time after pumping is stopped and that this closure of IU fractures can have a significant impact on stress interference between fractures. To illustrate these effects, microseismic and radioactive-tracer data are presented for four laterals drilled and fractured from a single pad. Two wells on this pad were fractured with the consecutive-fracturing sequence, and the other two wells were fractured with the zipper-fracturing sequence. Geomechanical simulations were performed to model the pad scenario and explain the microseismic and tracer observations, with emphasis on the two different fracturing sequences. Our simulations show that the opening of the IU fractures results in significant temporary changes to the stress field in the rock. One consequence of this is that later fracture stages tend to propagate into the open-fracture networks of IU fractures created earlier because of stress reorientation. This can lead to inefficient usage of fluid, proppant, and capital because the region that is being stimulated has already been stimulated by the previous stage. By analyzing the net pressure, radioactive-tracer data, and microseismic data from the four-well pad, we show that these IU fractures close over time because the fracture fluid leaks off. This reduces the stress shadow, and subsequent induced fractures are no longer subjected to the significantly altered stresses, allowing for more-efficient fracture-network coverage by subsequent fractures in a horizontal well. On the basis of the data presented and computer simulations, we propose the idea of maximizing the time between fracturing in the microseismic volume of a recently fractured region (within operational constraints). The time required for the IU fractures to close can be estimated from our models and varies on the basis of the reservoir and fluid properties from several hours to days. One example of how this is accomplished in practice is zipper fractures. However, our work suggests that there also may be other fracture-sequencing strategies for accomplishing this.

Ripudaman Manchanda

Papers

A general poro-elastic model for pad-scale fracturing of horizontal wells

Time Dependent Fracture Interference Effects in Pad Wells

Hydraulic Fracture Closure in a Poroelastic Medium and Its Implications on Productivity

Overcoming the Impact of Reservoir Depletion to Achieve Effective Parent Well Refracturing

Simulating the Life of Hydraulically Fractured Wells Using a Fully-Coupled Poroelastic Fracture-Reservoir Simulator