Fracture Stimulation by Nano-assisted Foam-based Fluids in High-Temperature Reservoirs

Abstract

Fracture stimulation, or hydraulic fracturing, has been increasingly implemented to extract and enhance oil and gas production from unconventional resources with very low permeability. In this stimulation technique, fracturing fluid is injected at very high pressure into the underground to initiate and propagate fractures at the target reservoir interval. Proppants, such as coated sands and ceramic, are mixed within the fracturing fluid and distributed inside the fractures to keep the fractures open and maintain the conductive pathways for oil and gas flows. Therefore, fracturing fluids must have sufficient stability and viscosity to suspend, transport and place proppants deep into the fracture system. Liquid foam has been an attractive alternative to conventional water-based fracturing fluids, especially in water-sensitive or under-pressured reservoirs. Implementing fracturing foams offers several practical benefits, such as low water consumption, reduced formation damage, low leak-off rate and high efficiency in transporting and distributing proppants in the fractures. However, while surfactant agents are mainly used to generate and stabilize liquid foams, they tend to degrade very quickly at high temperatures and high salinity, resulting in reduced stability and poor performance of fracturing foams at reservoir conditions. The main aim of this study is to develop an optimized foam-based fracturing fluid with sufficient stability and adequate proppant transportation capacity under harsh reservoir conditions. Furthermore, the stabilization effects of nanoparticles and surfactants on the properties of liquid foams are investigated by a wide range of surface and bulk-scale experiments and fracture simulation modelling. The experimental results show that the synergy between surfactants and silica nanoparticles (SNP) has massive impacts on the properties of fracturing foams. At ambient and elevated temperatures, the combination of SNP and ionic surfactant leads to higher foam stability and foamability, compared to that of SNP and non-ionic surfactant. At sufficient surfactant concentrations, the electrostatic attraction between SNP and cationic surfactant results in a higher half-life, higher apparent viscosity and greater proppant-carrying capacity when compared with the electrostatic repulsion of the SNP-anionic surfactant system. The aggregation behaviour of SNP is promoted by either interacting with the oppositely charged surfactants or increasing the temperature and/or salinity. It is found that the SNP aggregates can either have positive or negative influences on the foams' properties, depending on their size and location of accumulation. The simulation results show that foams' stability, rheology and proppant suspension capacity are directly proportional to the propped area, fracture conductivity and well productivity. In the simulated tight gas reservoir models, the fracturing performance of SNP-surfactant-stabilized foams is significantly greater than that of the benchmark slickwater frac case. The research presents remarkable insights into the synergistic interactions between surfactants and nanoparticles. Furthermore, it provides practical guidelines for designing an optimal nanoparticle-surfactant mixture to stabilize and enhance the properties of fracturing foams at high-temperature and high salinity reservoir conditions.