Experimental Assessment of Fracture Initiation and Wettability in Low and High Brittle Shales by CO₂ Foam Fracturing Fluids

Abstract

CO2 foam fracturing fluid has received significant attention because of its versatility in water-sensitive formations. However, the mechanisms of hydraulic fracturing of shale reservoirs by CO2 foam fracking fluid, in terms of fracture initiation and propagation remain unclear. In this paper, an experimental study was conducted to correlate the fluid interaction and fracture propagation in various shale formations having brittleness indices of 0.43, 0.50, and 0.74 to the rock-fracking fluid wettability. The shale wetting state in the presence of the CO2 foam fracturing fluid was determined from contact angle measurements through the Krüss drop shape analyzer (DSA 100), and the hydraulic fracturing was conducted via a tri-axial fracking system. A specific concentration of polyacrylamide (500 ppm) is used as a drag-reducing agent and selected for the hydraulic fracturing experiments. CO2 foam fracturing resulted in low fracture initiation pressure in the shale, having a high brittleness index of 0.74 BIm, and it remains the same at high temperatures. The length and aperture of the hydraulic fracture were then correlated with fracturing fluid–shale contact angles. The Mancos shale is sand-rich (with 21 wt % calcite and 52 wt % quartz), and it remained strongly water-wet on the interaction with the fracking fluid, and the net breakdown pressure was found to be lower in the fracturing tests of the Mancos shale. The Marcellus shale (with 31 wt % calcite and 22 wt % quartz) was intermediately wet (with a contact angle of 93.1°), whereas the Eagle Ford shale with high clay content (77 wt % calcite and 11 wt % quartz) was CO2-wet (with a contact angle of 109°) at 80 °C. Marcellus and Eagle Ford shales demonstrated higher fracture initiation pressures during the fracking experiments than the Mancos shale. The study suggests that fracking fluid–shale wettability has an essential role in the fracking of shale formations and should be considered in optimizing hydraulic fracturing fluid.

Impact of Supercritical CO2 on Shale Reservoirs and Its Implication for CO2 Sequestration

“…Again, because of the highly variable nature of shales, future studies shall focus more on the micromechanical variations of different mineral and organic matter phases within the rock using techniques such as nanoindentation, atomic force microscopy, etc …”

“…The surface wettability of shales (and any other reservoir) is another important petrophysical property that is influenced by SC-CO 2 and affects the overall performance of the reservoir, especially for sequestration. ,− The capillary forces, which are crucial for the evaluation of storage potential, are mainly controlled by surface wettability . Qin et al conducted laboratory experiments to determine the influence of SC-CO 2 on shale water wettability.…”

A Numerical Study of Nonlinear Gas Flow in Shale Anisotropic Fracture Under Effective Stress

“…The reservoirs are characterized by low porosity and low permeability, which makes it difficult to efficiently extract shale gas through conventional drilling techniques. , Therefore, it is imperative to modify shale reservoirs to increase shale gas production . Fracturing is an efficient way to modify shale reservoirs, and existing fracturing techniques include hydraulic fracturing, gas fracturing (supercritical CO 2 fracturing), liquid nitrogen fracturing, , foam fracturing, , blasting fracturing, high energy gas fracturing, , etc. The above fracturing techniques use static/dynamic impacts on shale reservoirs to create artificial fractures that communicate with existing natural fractures.…”

Application of foam assisted water-alternating-gas flooding and quantification of resistivity and water saturation by experiment and simulation to determine foam propagation in sandstone

“…Dual-energy X-ray Computed Tomography (CT) imaging is a proven method of studying three-phase flow experiments in a porous media [ 13 , 14 ]. CT imaging techniques have been applied during foam flow to monitor the fracture growth in shale and fluid saturations within the sand column and gain insight into the relationship between foam morphology and non-aqueous phase liquid (NAPL) recovery mechanisms [ 15 , 16 ].…”