RIASSUNTO
Abstract
Many studies have been performed to identify chemical additives that will aid shale stability in large volume slick water fracturing treatments. Most of the targeted shale formations have a very low permeability, do not experience conventional leakoff and do not contain high amounts of swelling clays such as smectite, leading to a perception that the shale is not water sensitive. However, recent laboratory evaluations have shown that not all shales are stable in fresh water, destabilizing with fresh water contact and releasing fines which could potentially result in formation damage and reduce net fracture pack conductivity.
Previous studies of the ability of inorganic salts, temporary clay stabilizers, and permanent polymeric based clay stabilizers show that some of the common hydraulically fractured shales encounter stability problems when contacting fresh water. The studies have revealed that cationic polymeric permanent clay stabilizers improve the stability of the water sensitive shales. However, polymeric shale stabilizers are not without potential detriments. Polymers can lead to formation damage by blocking pore throats and reducing permeability. Additionally, the use of cationic polymers can limit the use of other chemical compounds used in treating fluids that may not be compatible with the cationic charge.
This paper will compare a non-polymeric permanent clay stabilizer to conventional cationic polymers, temporary clay stabilizers, and inorganic salts and demonstrate equivalent and, sometimes, improved performance. Laboratory data from shale stability (roller oven), capillary suction time (CST), and regained permeability (core flow) studies will be presented demonstrating the efficacy of this new compound. Shales selected for the study will include standard Pierre shale and a variety of commonly hydraulically fractured shales from North America. Additionally, chemical compatibility testing will demonstrate the benefits of the new compound over conventional cationic polymeric clay stabilizers.
Introduction
Formation damage from water sensitive clays can be a significant problem in the petroleum industry. Up to 97% of hydrocarbon producing reservoirs contain clay minerals (Hill 1982, Berry 2008). Therefore, clay sensitivity can be an issue in virtually every well to a certain degree. Shales in particular are susceptible to this type of formation damage due to the significant amount of clays present, and the minimal amount of permeability in the tight shale zones, causing any formation damage to potentially be more detrimental to production. Estimates in literature have shown clay concentrations to commonly be in the range of 30%-70% in shale zones (Yaalon 1961). The mechanism of clay-induced formation damage are fines migration (clay migration is included in this category and the focus of this paper) and clay swelling. Clay migration damage is the dispersal and transport of clays that are re-deposited in the pore throats, therefore restricting permeability. Clay swelling damage can restrict permeability by plugging pores and can also lead to shale instability due to pore pressure changes (Zhang 2004, Oort 2003). Since shale formations have low permeability, water used in hydraulic fracturing treatments may not penetrate the matrix, but could destabilize the fracture face and may block induced fractures.