Olga Kresse

Numerical Modeling of Hydraulic Fractures Interaction in Complex Naturally Fractured Formations

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.

Effect of Flow Rate and Viscosity on Complex Fracture Development in UFM Model

A recently developed unconventional fracture model (UFM*) is able to simulate complex fracture networks propagation in a formation with pre-existing natural fractures. Multiple fracture branches can propagate at the same time and crisscross each other. The behaviour of a hydraulic fracture when it intersects a natural fracture, whether being arrested, cross‐ ing, creating an offset, or dilating the natural fracture, plays a key role in predicting the re‐ sulting fracture footprint, microseismicity, and improving production evaluation. It is therefore critical to properly model the fracture interaction in a complex fracture model such as UFM. A new crossing model, called OpenT, taking into account the effect of flow rate and fluid viscosity on the hydraulic/natural fracture crossing behaviour is integrated in UFM simula‐ tor. The previous fracture crossing model is primarily based on the stress field at the ap‐ proaching hydraulic fracture tip and its interaction with the natural fracture. A new elasticity solution for the fracture contact has been developed. The new OpenT semi-analyti‐ cal crossing model quantifies the localized stress field induced in the natural fracture and in the rock and evaluates the size and length of open and shear slippage zones along the natu‐ ral fracture. The natural fracture activation and stress field near the intersection point are strongly dependent on the contacting hydraulic fracture opening and thus on fluid flow rate and viscosity. This new model is validated against laboratory experimental results and an advanced numerical model. In this paper we present the results of several test cases showing the influence of injection rate and fluid viscosity on the generated hydraulic fracture footprint in formations with pre© 2013 Kresse et al.; licensee InTech. This is an open access article distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited. existing natural fractures. The influence of the stress field anisotropy, intersection angle, as well as natural fractures properties are also important and are discussed. The results are then compared with the simulations using the previous crossing model which does not ac‐ count for the influence of fluid properties.

Analysis on the Impact of Fracturing Treatment Design and Reservoir Properties on Production from Shale Gas Reservoirs

Production from shale gas reservoirs depends greatly on the efficiency of hydraulic fracturing treatments. The cumulated experience in the industry has led to several best practices in treatment design, which have improved productivity of these reservoirs. However, further advancement of treatment design requires a deeper understanding of the complex physics involved in both hydraulic fracturing and production, such as stress shadow, proppant placement and treatment interaction with pre-existing natural fractures. This paper sheds light on the non-linear physics involved in the production of shale gas reservoirs by improving the understanding of the complex relation between gas production, the reservoir properties, and several treatment design parameters. A fracturing-to-production simulation workflow integrating the Unconventional Fracture Model (Weng et al., 2011), with the Unconventional Production Model (Cohen et al., 2012) is presented. By applying this workflow to a realistic reservoir, we did an extensive parametric study to investigate the relation between production and treatment design parameters such as fracturing fluid viscosity, proppant size, proppant concentration, proppant injection order, treatment volume, pumping rate, pad size and hybrid treatment. The paper also evaluates the influence of unconventional reservoir properties - such as permeability, horizontal stress, horizontal stress anisotropy, horizontal stress orientation, Poisson’s ratio and Young‘s modulus – on production. Since this paper focuses on fluid and proppant selection, our methodology was to run 28 simulations to cover the 2D parametric space of proppant size and fracturing fluid viscosity for all of these parameters. More than fourteen hundred simulations were run in this parametric study and the results provide guidelines for optimized treatment design. This paper illustrates how this unique workflow can identifies the optimum fluid and proppant selection that gives the maximum production for a given reservoir and completion. In addition, the parametric study shows how these optimums evolve as a function of reservoir and treatment parameters. The results validate several best practices in treatment design for shale. For example, combination of different sizes of proppant optimizes production by maximizing initial production and slowing down production decline. Simulations also confirm the best practice of injecting the smallest proppant first. The study explains why slickwater treatments should be injected at maximum pumping rate and preferably with 40/70 mesh sand. It also illustrates why reservoirs with high Young’s modulus (such as the Barnett shale) can be stimulated effectively with slickwater. Another key finding is that the optimum fluid viscosity increases with treatment volume.

Impact of Preexisting Natural Fractures on Hydraulic Fracture Simulation

In many unconventional shale reservoirs, preexisting natural fractures play a critical role in the creation of complex hydraulic fracture networks during stimulation due to the interaction between hydraulic fractures and the natural fractures or activation of the natural fractures by the fracture stimulation to provide enhanced permeability to increase the hydrocarbon production. In this chapter, we discuss the mechanics influencing the crossing behaviors when a hydraulic fracture intersects a natural fracture, which is a critical process influencing the generation of complex fractures. A complex hydraulic fracture network model that incorporates mechanical interaction between hydraulic fracture and natural fracture, as well as among hydraulic fractures, will be presented. We will then present examples of fracture simulations for various configurations of the natural fractures, in terms of some key parameters, such as their orientation, density, and length, to highlight the impact of the natural fractures on the generated hydraulic fracture network geometry. The impact of the resulting geometry on proppant distribution in the fracture network and production will also be examined.