Key Parameters Affecting Successful Hydraulic Fracture Design and Optimized Production in Unconventional Wells

Abstract

Multi-stage/multi-cluster hydraulic fracturing in horizontal wellbores is a key technology driving the development of unconventional resources in North America. It has been observed that complex fracture behavior can result from hydraulic fracture stimulation in these unconventional horizontal wells. Given the rapid pace of development, many operators strive to standardize their completion program to drive consistency, and efficiency, in operations and well performance. Unfortunately, the hydraulic fracture treatments may not be properly designed to maximize well deliverability, but instead focus on maximizing contacted reservoir volume (CRV). Generating fracture complexity is important in unconventional reservoirs, but maximum reservoir contact does not necessarily translate to an effectively stimulated reservoir with conductive fracture paths back to the wellbore. Hydraulic fracture modeling in resource plays is challenging and often reduced to rules of thumb and design concepts taken from other shale plays. Key parameters that should be considered to maximize production in unconventional reservoirs are not dissimilar to the key parameters proven successful time and again in conventional completion designs and fracturing treatments. The need for improved proppant pack permeability and fracture conductivity in unconventional wells has been well documented. However, there are additional completion and design considerations for unconventional wells such as natural fracture saturation, mid-field fracture complexity (MFFC), mechanical fracture interaction and transverse fracture production interference. This paper summarizes a number of important considerations and key parameters that are necessary to design successful hydraulic fracture treatments and enhance productivity in unconventional wells. Application and considerations of these parameters will help provide the operator with a systematic, engineering based design method for optimizing multistage/multi-cluster hydraulic fracture treatments in horizontal wellbores.

Effect of Fracture Geometry on Well Production in Hydraulic-Fractured Tight Oil Reservoirs

“…The Reynolds numbers of all the scenarios were calculated, and results showed that for the highest Reynolds number, oil flow was 1.02 and that for gas was 18.30. Different critical Reynolds numbers for non-Darcy flow have been reported in the literature (Bear 1972;Hassanizadeh and Gray 1987;Blick and Civan 1988), ranging from 3 to 100. Thus, non-Darcy flow was not expected for oil flow but may appear in gas flow, which was in accordance with simulation results.…”

“…Because of the reduction of secondary-fracture conductivity, these fractures cannot transport reservoir fluids to the main fracture and wellbore effectively. Taking the case with conductivity of 500 darcyÁmm for example, when the main fracture is 500 darcyÁmm, the dimensionless fracture conductivity is 25, which can be regarded as infinite conductivity (Bazan et al 2013). However, the dimensionless conductivity of the secondary fracture is reduced to approximately 3.…”

“…The grid-top value is calculated by the well's true vertical depth subsea. According to Bazan et al (2013), a fracture with dimensionless conductivity higher than 10 should be targeted while designing a stimulation job and such a fracture is close to infinite conductivity. However, it should be noted that the effective fracture conductivity in the reservoir can be as significant as 90% lower than their laboratory-measured values because of the effects of multiphase flow, proppant embedment, and uneven proppant concentration (Palisch et al 2007).…”

Investigation of the influence of natural fractures and in situ stress on hydraulic fracture propagation using a distinct-element approach

“…In a review of data derived from a large number of hydraulic fracture treatments, Cleary et al (1991) cite the presence of natural fractures as the key reason for misinterpreted data and arrested fracture propagation. Numerous other studies also show that parameter uncertainty due to the presence of natural fractures can significantly impact hydraulic fracture designs (e.g., Palisch et al 2007, Moos and Barton 2008, Zhang et al 2009, Dusseault et al 2011, Meyer et al 2013. Microseismic monitoring provides further field-based evidence that existing natural fractures favorably oriented for shear will activate in response to interactions with a hydraulic fracture treatment (e.g., Rutledge et al 2004;Wessels et al 2011, Williams-Stroud et al 2012.…”

Required Understanding for the Development of Shale Reservoirs in the Middle East in Light of Developments in North America

“…Young's modulus gives an indication of the degree of the stiffness (toughness) of a material. It is directly related to the ability of the material to deform under the effect of adding loads (Meyer et al 2013). The Young's modulus (static modulus of elasticity) is mathematically represented by Eq.…”