A Fresh Look At Stimulating Unconsolidated Sands With Proppant-Laden Fluids

Abstract

Can unconsolidated sands, with no intergranular cohesion forces, really be hydraulically fractured? Does conventional hydraulic fracturing theory adequately explain treatment behavior and production results? If the unconsolidated formation is considered to be a fluidized sand bed, is the classical linear-elastic two-wing hydraulic frac assumption still valid? Alternative proppant stimulation mechanisms may better describe the process, including squeezing or forcing by viscous fingering of the high-permeability proppant slurry into the formation. In this scenario, traditional fracturing design parameters such as pad volume, pump rate, proppant concentration and especially fluid viscosity will have new and significantly different effects on the treatment outcome. This paper explores these concepts and shows how they can explain both treating behavior and production responses of so-called "frac jobs" or "sand-oil-squeezes". Alternative treatment and fluid design criteria are proposed to achieve more consistent and predictable production responses, based on field performance. Fracture propagation? The stimulation process in unconsolidated sands is not yet fully understood. What is evident is that conventional linear elastic fracture mechanics (LEFM) are not applicable and conventional models often do not adequately predict the treatment behavior. The theory of hydraulic fracturing is based on LEFM that apply to cohesive rock formations. In conventional hydraulic fracture simulations, initiation and propagation is governed by insitu stresses, mechanical and poro-elastic properties, and "fracture tip effects", such as fracture toughness, the nonwetted zone (fluid lag), tip dilatancy, and the process zone.1 Unlike competent formations, unconsolidated sand beds have little or no tensile strength or grain-to-grain cohesion, and could be defined as a high viscosity sand slurry under confinement pressure. Accordingly, the aforementioned fracture tip effects are not present in these formations. For example, the non-wetted zone does not exist, as Khodaverdian and McElfresh observed with 200-mesh sand packs in radial flow cell experiments. The measured pore pressure in the vicinity ahead of the advancing "tip" actually increased due to filtrate invasion prior to parting. A strong dependence on fluid efficiency was reported, with high leakoff fluids generating multiple, sub-parallel "fractures" (or plastic shear failure zones), and low leakoff fluids generating single, more continuous, failure zones.2 In experiments fracturing gelatin molds, Stockhausen, et. al., identified a strong correlation between fluid inertia (and hence pump rate) and fracture orientation in isotropic stress environments. Low injection rates resulted in fractures tangential to the wellbore, high rates produced radial fractures, and intermediate rates resulted in T-shaped (radial and trangential) fractures.3 In Western Canada, cold heavy oil production is routinely employed without sand exclusion techniques, resulting in massive sand production due to plastic flow of the granular, heavy oil-saturated matrix. Geilikman, et.al., developed a continuum model that treats the sand bed as viscoplastic skeleton saturated by a viscous fluid. In this model, after surpassing the yield stress, the fluid-saturated, granular, formation fabric will flow as a dense suspension, governed by its viscoplastic rheology.4 Combined stimulation/ sand control treatments, called Sand Oil Squeezes (SOS), have been employed in Venezuela and other areas for four decades.5,6,7 These treatments, which consist of an injection of a slurry of high concentrations of gravel in viscous oil into the formation prior to a gravel pack, were originally considered to be squeezes, not necessarily fracture treatments. With the advent of the frac pack technique in the early 90's, the theory behind the SOS was reworked to conform to the fracturing process. The authors contend that the original squeeze theory may more closely represent the injection process in unconsolidated sands than the frac pack theory. Note that it is commonly observed that the injected SOS slurry volume often exceeds the estimated void space behind the casing.

Injection of solids to lift coastal areas

“…The resulting features were generally sheet-like and formed normal to the least principal compression. Features with similar geometries were also formed by injecting various fluids into unconsolidated sediments (Ito et al 2008), loose sand (Khodaverdian & McElfresh 2000;Di Lullo et al 2004;de Pater & Dong 2009), poorly graded soil (Elwood 2008), clay samples (Au et al 2003;Soga et al 2004) and siliceous powder (Chang 2004;Galland et al 2006). Although the geometries of these features resemble fractures, the mechanics by which they form is likely to be different from classical fracture mechanics (Khodaverdian & McElfresh 2000;Chang et al 2003;Chang 2004;Di Lullo et al 2004).…”

“…Features with similar geometries were also formed by injecting various fluids into unconsolidated sediments (Ito et al 2008), loose sand (Khodaverdian & McElfresh 2000;Di Lullo et al 2004;de Pater & Dong 2009), poorly graded soil (Elwood 2008), clay samples (Au et al 2003;Soga et al 2004) and siliceous powder (Chang 2004;Galland et al 2006). Although the geometries of these features resemble fractures, the mechanics by which they form is likely to be different from classical fracture mechanics (Khodaverdian & McElfresh 2000;Chang et al 2003;Chang 2004;Di Lullo et al 2004). In particular, the cohesionless material must be in compression everywhere, as it cannot support the localized tension assumed to develop at the tip of a growing fracture in a material with cohesion (Chang et al 2003;Hurt et al 2005;Germanovich et al 2007).…”