No abstract

Summary 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 multiphase fluid-loss and phase behavior occurring in these complex fluids. This paper assesses the fluid-loss benefits introduced by energizing the fracturing fluid. A new laboratory apparatus has been specifically designed and built for measuring the leakoff rates for both gas and liquid phases under dynamic fluid-loss conditions. This paper provides experimental leakoff 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 leakoff data provides 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 leakoff 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 (1996a, b) for linear gels and the findings of Harris (1985) for nitrogen foams.

As the development of unconventional (e.g., tight gas, shales, coalbed methane) and under-pressured reservoirs has increased, so has the demand for innovative hydraulic fracture designs. The use of gases and foams has experienced a significant resurgence in popularity with the development of unconventional reservoirs and with the growing limitations on water supply in some areas. Until recently, the tools available for fracture design were not capable of modeling hydraulic fracturing with compressible fluids and non-isothermal treatments. Ribeiro and Sharma (2012b) presented a model that was capable of simulating hydraulic fracturing treatments with multi-phase, compressible fracturing fluids with changing temperature, phase behavior, and multi-phase leak-off during the treatment. The main objective of this paper is to show how such a model can be used for screening fracturing fluid candidates and for optimizing energized fracture treatments. In conducting this study, we have combined this 3-D compositional fracturing model with a multi-phase well-productivity model for hydraulically fractured wells. This paper presents results for slick water, linear gel, gelled CO2, gelled LPG, N2 foams and CO2 foams in a low permeability reservoir. The simulations showed that good proppant placement and high fracture conductivities can be achieved with foams and gelled fluid formulations. LPG, CO2, and high-quality foams prevent water invasion so they do not impede gas recovery because of water blocking or gel induced damage. In addition, several reservoir parameters appear to control well productivity and therefore fluid selection: (1) relative permeability curves, (2) initial gas saturation, (3) reservoir pressure, and (4) sensitivity to water. The benefits and disadvantages that must be considered when selecting a fracturing fluid are highlighted in this paper and a methodology is proposed to quantify these pros and cons.

While several three-dimensional (3D) fracturing models exist for incompressible water-based fluids, none are able to capture the thermal and compositional effects that are important when using energized fluids. This paper introduces a new 3D, compositional, non-isothermal, fracturing model designed for compressible fracturing fluids. The new model predicts changes in temperature and fluid density. These changes are treated on a firm theoretical basis by using an energy balance equation and an equation of state, both in the fracture and in the wellbore. The model is capable of handling any multicomponent mixture of fluids and chemicals. Changes in phase behavior with temperature, pressure, and composition can be modeled. A new simulator has been developed based on the compositional model presented in this paper. The simulator is validated for traditional fluid formulations against known analytical solutions and against a well-established commercial fracturing simulator. Results from the new simulator are then presented for energized fluids such as CO2 and LPG. This tool is specifically suited for fracture design in formations in which energized fluids constitute a viable alternative to traditional fracturing fluids. This is notably the case in reservoirs that are depleted, under-saturated, or water-sensitive.

This paper introduces an innovative CO 2 -hybrid-fracturing-fluid design that intends to improve production from ultratight reservoirs and reduces freshwater usage. The design consists of injecting pure CO 2 as the pad fluid to generate a complex fracture network and injecting a gelled slurry (water-or foam-based) to generate near-wellbore conductivity. The motivation behind this design is that while current aqueous fluids provide sufficient primary hydraulic-fracture conductivity back to the wellbore, they understimulate the reservoir and leave behind damaged stimulated regions deeper in the fracture network. Much of that (unpropped) stimulated area is ineffective for production because of interfacial-tension effects, fines generation, and/or polymer damage. We present simulation work that demonstrates how CO 2 , with its low viscosity, can extend the bottomhole treating pressure deeper into the reservoir and generate a larger producible surface area. We also present experimental evidence that CO 2 leaves behind higher unpropped-fracture conductivities than slickwater. This paper does not address the many operational and logistical challenges of using CO 2 as a fracturing fluid. Rather, it intends to demonstrate the production-uplift potential of the proposed design, which seems particularly attractive in reservoirs capable of sustaining production from unpropped fractures (e.g., reservoirs with low horizontal-stress anisotropy, high Young's modulus, and a pervasive set of natural fractures).