Charles-Edouard Cohen

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.

Production Forecast after Hydraulic Fracturing in Naturally Fractured Reservoirs: Coupling a Complex Fracturing Simulator and a Semi- Analytical Production Model

The growing interest in exploiting shale resources is generating new technologies in fracture modeling and reservoir simulation. In the presence of pre-existing natural fractures, hydraulic fracture propagation and prop pant distribution can be very complex. Developing the tools to understand fr acture propagation and its link to production in sh ale reservoirs is one of the major technological challenges that the industr y is facing today. These challenges are being addre ssed with new hydraulic fracture simulators and production models for compl ex hydraulic fracture networks in shale reservoirs. However, the coupling between these two technologies is not matu re yet. This paper presents a simple automated workflow fro m simulating hydraulic fracture propagation in natu rally fractured reservoirs to the subsequent production. This work documents the coupling of an existing complex fract uring simulator with a new production model. The complex fracture model considers interactions with natural fractures, stre ss shadow effects and proppant placement. The production model is based on a semi-analytical approach applied to the discret e hydraulic fracture network. The analytical solution used to simulate t he flow from the matrix into the fracture network i s simple and well known, but it relies on the assumption of constant pressure in the fracture which can only be obtained with infinite fracture conductivity. An original feature of this model is an algorithm to extend the validity of the analytic al solution to all fracture conductivities, by calculating a local “time delay” based on mass balance. The validity of this appro ach is illustrated by a comparison with results from a standard reservoir s imulator. The simple automated workflow that combines the two simulators gives the opportunity to investigate the relation between production and fracture treatment design in naturally fractured reservoirs. This paper illustrates the ap plication of the workflow to realistic cases and th e sensitivity of several design parameters that affect well performance.

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.