CO2 miscible hydrocarbon fracturing fluids have proven to be a very effective gas well stimulation tool in Canada and the United States. A key reason for their success has been that they circumvent phase trapping associated with aqueous fluids and achieve rapid fracturing fluid recovery through a methane-drive mechanism.
This technology is taking on new economic significance because of increased unconventional gas development and sustained higher energy prices. Reservoirs including tight gas, shale gas, and coalbed methane are becoming a critically important component of current and future gas supply. These reservoirs often present unique stimulation challenges. The use of water-based fracturing fluids in low-permeability reservoirs may result in loss of effective fracture half-length caused by phase-trapping effects associated with the retention of a large portion of the introduced water-based fluid in the formation.
SPE 75666,1 presented in 2002, described the theoretical basis of CO2 miscible hydrocarbon fracturing fluids in this technology and provided a step-by-step application process. The paper was based on work published by Gruber and Anderson in CIM 95-45. 2 Improved methods of application have been arrived at through field application of this technology in conjunction with additional lab studies. The objective of this paper is to present the findings in the form of one optimized system applicable to all gas-well stimulation applications. Supporting data including viscosity curves and friction data based on actual ISIP measurements is included. The paper also discusses selection of tubulars and flowback procedures in detail.
It should be possible to successfully apply the technology to low permeability gas reservoirs through application of the methods described in this paper. This could potentially include some shale gas developments in the future, an area of rapidly growing focus in Canada.
Unconventional gas reservoirs including tight gas, shale gas, and coalbed methane are becoming a critically important component of current and future gas supply. These reservoirs often present unique stimulation challenges. The use of waterbased fracturing fluids in low-permeability reservoirs may result in loss of effective frac half-length caused by phase trapping associated with the retention of the introduced water-based fluid into the formation. This problem is increased by the water-wet nature of most tight gas reservoirs (where no initial liquid hydrocarbon saturation is or ever has been present) because of the strong spreading coefficient of water in such a situation.
The retention of this increased water saturation in the pore system can restrict the flow of produced gaseous hydrocarbons such as methane. Capillary pressures of several thousand psi can be present in low-permeability formations at low watersaturation levels. The inability to generate sufficient capillary drawdown force using the natural reservoir drawdown pressure can result in extended fluid-recovery times, or permanent loss of effective fracture half-length. Furthermore, use of water in subnormally saturated reservoirs may also reduce permeability and associated gas flow through a permanent increase in water saturation of the reservoir. Secondary costs such as rig time for swabbing can add to the negative economic impact.
