Numerical simulation of hydraulic fracturing with liquid CO2 is discussed in this paper. Field experience indicates that CO2 is a preferred fluid in sensitive reservoirs where there is a risk of formation damage with conventional treatments. Simulation of the process, which is characterized by low viscosity and temperature effects on fluid PVT requires consideration of turbulence and its effect on fracture geometry, leak-off, and proppant transport. The new model for low-viscosity fluids described here was successfully used to match CO2 frac field data with very short closure times. Simulation results indicate effective propping of the fracture.
This paper presents engineering analysis of the CO2 fracturing process using numerical simulation. and the application of the model developed for field cases.
To date, over 450 wells have been fractured with liquid CO2, Field experience indicates that liquid CO2 is the preferred fracturing fluid in formations where other fracturing fluids result in formation damage due to clay sensitivity, emulsions, relative permeability effects or gel residues. CO2 as a frac fluid is usually non-damaging to the formation and, in oil reservoirs. may have additional benefit of dissolving in the oil and further improving the well clean-up. On the other hand, the CO2 fluid is limited in achieving fracture width and therefore the potential for fracture conductivity.
Another concern often raised with the CO2 process is the excessive settlement and poor propping efficiency. However, we will show here that this concern results from the use of the conventional fracturing model with the physics for viscous fluids which is not applicable here.
Conventional fracturing fluids rely on high viscosity for proppant transport and creation of large fracture width to maximize propped conductivity Consequently, the laminar flow concepts are used for pressure drop as well as proppant transport calculations. In contrast, CO2 viscosity during pumping is less than one centipoise, and Reynolds numbers of 20,000 are typical. To account for the turbulence, concepts of equilibrium velocity and lateral slip velocity must be incorporated in the proppant transport model. Calculation of turbulent pressure drop in the fracture is required to obtain realistic fracture geometry. Also, the model must account for CO2 thermal expansion during pumping and phase change to gas during closure.
Several case histories were investigated to determine the deficiencies of the conventional approach and to validate the new features of the model developed here. Results of two of these are described in the paper.
Host of the research in modelling of hydraulic fracturing was directed towards the typical conditions of high viscosity fluids. Consequently, the use of CO2conventional models to analyze CO2 the treatments can lead to incorrect conclusions. Field experience (Ref. 1) shows the following major differences compared to conventional treatments:
Fracture width is relatively small; any size of sand is possible but 20/40 mesh sand is limited in application to approximately 2000 meter depth, except at high rates.
CO2 is a liquid at low temperature as it is pumped downhole.
