Montney Fracturing-Fluid Considerations

Abstract

Summary The Montney gas reservoir has become a critically important component of current western Canadian gas supply and offers exciting future potential. However, this reservoir often presents variable and unique stimulation challenges. Unlike reservoirs that display little water sensitivity, such as the U.S. Barnett Shale and possibly the Muskwa in the Northeastern British Columbia Horn River Basin, recovery of water-based fluids in the Montney can be a key consideration in achieving economic production rates. The use of water-based fracturing fluids in low-permeability reservoirs can result in loss of effective frac half-length caused by phase trapping associated with the retention of the introduced water-based fluid to 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 increased water saturation (Sw) in the pore system after the injection of water-based completion fluids can restrict the flow of produced gaseous hydrocarbons, such as methane. Capillary pressures of 10 MPa-20 MPa, or much higher, can be present in low-permeability formations at low-water saturation levels. 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, where much of the connate water has been removed by long-term evaporation effects associated with gas migration, might also reduce permeability and associated gas flow through a permanent increase in Sw of the reservoir. Secondary costs, such as rig time for swabbing, can add to the negative economic impact. The Montney is found to be a dry-gas reservoir in some areas, transitioning to an oil reservoir in other areas. Because of this, it would not be surprising to encounter retrograde condensate production through transition areas. In such a case, if sufficient drawdown pressure is applied to reduce reservoir pressure below the dewpoint, liquid hydrocarbons might condense from the produced gas phase, resulting in two-phase flow and potential trapping of the hydrocarbon liquid phase. Also, some areas of the upper Montney exhibit reservoir pressures in the 30 MPa range, whereas other areas exhibit lower pressures in the 17 MPa-21MPa range. The same drawdown on a lower-pressured reservoir could therefore result in condensate condensing from the gas phase, where it would not have in the higher-pressured reservoir. If a third aqueous fracturing fluid is introduced, three-phase flow might occur. The resulting reduced relative permeability to gas might drastically reduce production rates. Also, emulsion-formation potential exists, which could present an additional reduction in fluid flow and recovery. Choice of fracturing fluid must be carefully determined for each area of the Montney, balancing economics with production. It is important to always keep in mind that key reservoir properties can vary dramatically in the Montney, as a function of both geographic location and depth. This paper presents laboratory test results of regained methane permeability vs. drawdown pressure and contact time with Montney core under representative reservoir conditions. Water, foamed water and hydrocarbon-based fracturing fluid systems are evaluated. The testing was funded by and arranged for by operators in preparation for actual fracturing treatments in two different fields. Core plugs, time and funding were limited; therefore, only tests deemed necessary for decision-making were run.  Limited repeat testing was therefore possible.