With the growing interest in low-permeability gas plays, foam fracturing fluids are now well established as a viable alternative to traditional fracturing fluids. Present practices in energized fracturing treatments remain nonetheless rudimentary in comparison to other fracturing fluid technologies because of our limited understanding of multi-phase fluid-loss and phase behavior occurring in these complex fluids. This report assesses the fluid-loss benefits introduced by energizing the fracturing fluid. A new laboratory apparatus has been specifically designed and built for measuring the leak-off rates for both gas and liquid phases under dynamic fluid-loss conditions. This report provides experimental leak-off results for linear guar gels and for N2-guar foam-based fracturing fluids under a wide range of fracturing conditions. In particular, the effects of the rock permeability, the foam quality, and the pressure drop are investigated. Analysis of dynamic leak-off data provide an understanding of the complex mechanisms of viscous invasion and filter-cake formation occurring at the pore-scale. This study presents data supporting the superior fluid-loss behavior of foams, which exhibit minor liquid invasion and limited damage. It also shows direct measurements of the ability of the gas component to leak-off into the invaded zone, thereby increasing the gas saturation around the fracture and enhancing the gas productivity during flowback. Our conclusions not only confirm, but add to the findings of McGowen and Vitthal (1996) for linear gels, and the findings of Harris (1985) for nitrogen foams. / text

Hydraulic fracturing is essential for producing gas and oil at an economic rate from low permeability sands. Most fracturing treatments use water and polymers with a gelling agent as a fracturing fluid. The water is held in the small pore spaces by capillary pressure and is not recovered when drawdown pressures are low. The un-recovered water leaves a water saturated zone around the fracture face that stops the flow of gas into the fracture. This is a particularly acute problem in low permeability formations where capillary pressures are high. Depletion (lower reservoir pressures) causes a limitation on the drawdown pressure that can be applied. A hydraulic fracturing process can be energized by the addition of a compressible, sometimes soluble, gas phase into the treatment fluid. When the well is produced, the energized fluid expands and gas comes out of solution. Energizing the fluid creates high gas saturation in the invaded zone, thereby facilitating gas flowback. A new compositional hydraulic fracturing model has been created (EFRAC). This is the first model to include changes in composition, temperature, and phase behavior of the fluid inside the fracture. An equation of state is used to evaluate the phase behavior of the fluid. These compositional effects are coupled with the fluid rheology, proppant transport, and mechanics of fracture growth to create a general model for fracture creation when energized fluids are used. In addition to the fracture propagation model, we have also introduced another new model for hydraulically fractured well productivity. This is the first and only model that takes into account both finite fracture conductivity and damage in the invaded zone in a simple analytical way. EFRAC was successfully used to simulate several fracture treatments in a gas field in South Texas. Based on production estimates, energized fluids may be required when drawdown pressures are smaller than the capillary forces in the formation. For this field, the minimum CO2 gas quality (volume % of gas) recommended is 30% for moderate differences between fracture and reservoir pressures (2900 psi reservoir, 5300 psi fracture). The minimum quality is reduced to 20% when the difference between pressures is larger, resulting in additional gas expansion in the invaded zone. Inlet fluid temperature, flowrate, and base viscosity did not have a large impact on fracture production. Finally, every stage of the fracturing treatment should be energized with a gas component to ensure high gas saturation in the invaded zone. A second, more general, sensitivity study was conducted. Simulations show that CO2 outperforms N2 as a fluid component because it has higher solubility in water at fracturing temperatures and pressures. In fact, all gas components with higher solubility in water will increase the fluid’s ability to reduce damage in the invaded zone. Adding methanol to the fracturing solution can increase the solubility of CO2. N2 should only be used if the gas leaks-off either during the creation of the fracture or during closure, resulting in gas going into the invaded zone. Experimental data is needed to determine if the gas phase leaks-off during the creation of the fracture. Simulations show that the bubbles in a fluid traveling across the face of a porous medium are not likely to attach to the surface of the rock, the filter cake, or penetrate far into the porous medium. In summary, this research has created the first compositional fracturing simulator, a useful tool to aid in energized fracture design. We have made several important and original conclusions about the best practices when using energized fluids in tight gas sands. The models and tools presented here may be used in the future to predict behavior of any multi-phase or multi-component fracturing fluid system. / text