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

Efficient Incorporation of a Contact Model into a Fully Implicit Geomechanical Fracture Simulator

Interpreting Inter-Well Poroelastic Pressure Transient Data: An Analytical Approach

A New Reservoir Scale Model for Fracture Propagation and Stress Reorientation in Injection Wells

Laboratory Observations of the Effect of Pore Pressure on Hydraulic Fracture Growth


 During stimulation of unconventional reservoirs, offset well pressure measurements are often used to estimate hydraulic fracture geometry. These measurements can also be used to make a quantitative estimate of the created fracture network area and the permeability of the stimulated rock volume (SRV) around the hydraulic fractures. Offset well pressure measurements recorded in the field clearly show a change in the pressure response of the monitor well when the injection rate in a nearby fracture treated well is changed. The shut-in period between two frac stages in the treatment well corresponds to a distinct pressure fall-off in the monitor well. We present a workflow where we analyze and match this pressure fall-off in an offset monitor well in response to fluid leak-off from a hydraulic fracture in the treatment well to estimate SRV permeability and the created fracture network area. The workflow and model are applied to field data from the Permian Basin.
 A fully-coupled, 3-D, poroelastic reservoir-fracture simulator has been used to simulate pressure fall-off in the offset monitor well. Field data and simulation results are presented to show that during shut-in between two frac stages in the treatment well, a decrease in the injection rate causes the monitored offset well pressure to fall-off. We find that this fall-off in pressure is influenced by leak-off from the treatment well fracture. During the shut-in period, fluid leak-off from the treatment well fracture into the SRV region decreases the width of the fracture which consequently affects the stress-shadow and the poroelastic pressure fall-off in the offset monitor well. The pressure fall-off in the monitor well is, therefore, shown to be caused by 1) the fluid leak-off from the monitor well fracture and 2) stress-shadow relaxation around the monitor well fracture as fluid leaks-off from the nearby treatment well fracture into the formation.
 We present a new method to estimate the permeability of the stimulated region around the created fractures. We show that, along with the permeability of the SRV region, the stress-shadow of the treatment well fracture on the monitor well fracture also has a significant impact on the pressure fall-off in the monitor well. We use a conceptual model to estimate the created fracture network area which can be used as a metric to identify the effectiveness of a frac job and provide insights into the generated fracture complexity during the frac job. In addition, the estimated SRV permeability and fracture network area are critical inputs in production forecast simulations that can guide an operator to make better economic decisions in a relatively inexpensive manner.

Ripudaman Manchanda

Papers

Efficient Incorporation of a Contact Model into a Fully Implicit Geomechanical Fracture Simulator

Interpreting Inter-Well Poroelastic Pressure Transient Data: An Analytical Approach

A New Reservoir Scale Model for Fracture Propagation and Stress Reorientation in Injection Wells

Laboratory Observations of the Effect of Pore Pressure on Hydraulic Fracture Growth

Estimating Fracture Network Area and SRV Permeability by Analyzing Offset Well Pressure Measurements during Fracturing