Conventional water-based fracturing treatments may not work well for many shale gas reservoirs. This is due to the fact that shale gas formations are much more sensitive to water because of the significant capillary effects and the potentially high contents of swelling clay, each of which may result in the impairment of productivity. As an alternative to water-based fluids, gaseous stimulants not only avoid this potential impairment in productivity, but also conserve water as a resource and may sequester greenhouse gases underground. However, experimental observations have shown that different fracturing fluids yield variations in the induced fracture. During the hydraulic fracturing process, fracturing fluids will penetrate into the borehole wall, and the evolution of the fracture(s) then results from the coupled phenomena of fluid flow, solid deformation and damage. To represent this, coupled models of rock damage mechanics and fluid flow for both slightly compressible fluids and CO2 are presented. We investigate the fracturing processes driven by pressurization of three kinds of fluids: water, viscous oil and supercritical CO2. Simulation results indicate that SC-CO2-based fracturing indeed has a lower breakdown pressure, as observed in experiments, and may develop fractures with greater complexity than those developed with water-based and oil-based fracturing. We explore the relation between the breakdown pressure to both the dynamic viscosity and the interfacial tension of the fracturing fluids. Modeling demonstrates an increase in the breakdown pressure with an increase both in the dynamic viscosity and in the interfacial tension, consistent with experimental observations.

The Influence of Fracturing Fluids on Fracturing Processes: A Comparison Between Water, Oil and SC-CO 2

Surface characteristics and permeability enhancement of shale fractures due to water and supercritical carbon dioxide fracturing

Experimental study on the growth behavior of supercritical CO 2 -induced fractures in a layered tight sandstone formation

CH4 CO2 gas exchange and CO2 based hydraulic fracturing are common enhancement techniques adopted in coal-bed methane (CBM) extraction industry, with promising results. This review provides a comprehensive overview of the CH4 CO2 gas exchange method at macro and microscopic level, and the CO2-based hydraulic fracturing. The process of CH4 replacement by CO2 is comprehensively discussed considering two possible CBM storage mechanisms; 1) by adsorption and; 2) at hydrate state. The CH4 CO2 gas exchange by sorption/diffusion process has been proven to be kinetically and thermodynamically viable as CO2 can easily penetrate through ultra-micro-pores region and adsorb into the coal pores due to its smaller kinetic diameter, linear shape and higher affinity. The gas exchange occurs in the hydrate phase at special reservoir conditions has also been shown to be feasible kinetically, chemically and thermodynamically, given the fact that the reverse reaction (i.e. CO2 replaced by CH4) is different and rather inefficient. Therefore CBM extraction using CO2 replacement is confirmed to be an effective extraction technique. The use of CO2, particularly in its super-critical state, as a fracturing fluid has a number of advantages. Owing to its gas-like viscosity and compressibility, super-critical CO2 (S-CO2) easily infiltrates through tiny defects in rock formations, inducing thinner and more three-dimensionally extended cracks, while maintaining a low break-down pressure. On the other hand, the liquid-like density of S-CO2 exerts more pressure on the rock, so that it can easily exceed the minimum principal stress and rock tensile strength, resulting in easy crack initiation. However, such CO2 utilization methods, particularly those based on super-critical CO2 are still novel to the CBM extraction industry and should therefore be subjected to careful investigation prior to implementation.

CH4–CO2 gas exchange and supercritical CO2 based hydraulic fracturing as CBM production-accelerating techniques: A review

Exploring the influence of rock inherent heterogeneity and grain size on hydraulic fracturing using discrete element modeling

We conducted hydraulic fracturing (HF) experiments on 170 mm cubic granite specimens with a 20 mm diameter central hole to investigate how fluid viscosity affects HF process and crack properties. In experiments using supercritical carbon dioxide (SC-CO2), liquid carbon dioxide (L-CO2), water, and viscous oil with viscosity of 0.051–336.6 mPa · s, we compared the results for breakdown pressure, the distribution and fracturing mechanism of acoustic emission (AE), and the microstructure of induced cracks revealed by using an acrylic resin containing a fluorescent compound. Fracturing with low-viscosity fluid induced three-dimensionally sinuous cracks with many secondary branches, which seem to be desirable pathways for enhanced geothermal system (EGS), shale gas recovery and other processes.

https://agupubs.onlinelibrary.wiley.com/doi/pdf/10.1002/2016JB013365

Features of CO2 fracturing deduced from acoustic emission and microscopy in laboratory experiments

https://repository.kulib.kyoto-u.ac.jp/dspace/bitstream/2433/234999/1/j.proeng.2017.05.206.pdf

Shuhei Inui

Papers

Features of CO2 fracturing deduced from acoustic emission and microscopy in laboratory experiments

Injection of Supercritical Carbon Dioxide into Granitic Rock and its Acoustic Emission Monitoring