Energized Fracturing Fluids for Liquids-Rich Organic Shale Reservoirs
The majority of liquids rich play fracs employ either slick water, linear gels, or crosslinked gels. In this paper we will discuss potential productivity improvements from the use of energized fluids in these plays. Energized fluids also reduce water consumption and disposal requirements. Slick water has low viscosity and does not provide effective transport of proppant into the fracture when pay zones are thicker than the limited propped bed height. Vertical well 3D frac model simulations in organic shale plays indicate little variation in propped height with job volume, suggesting that a limit is approached. With gelled fluids, the propped heights typically improve. However, gel damage can negate the improved vertical coverage in low water saturation reservoirs. Energized fluids can provide increased effective viscosity for improved proppant transport. They also significantly reduce gel volumes (or even completely eliminate them if a gel-free foam is used) and capillary phase trapping. In current practice, energized frac fluids are generally employed in underpressured dry gas reservoirs. This is based on the understanding that water can easily enter reservoir pores, and will be held there by capillary forces that the low pressure natural gas of the reservoir cannot overcome alone. Due to N2 or CO2 present in an energized fluid, once pressure is released the fluid will rapidly come to the surface regardless of reservoir pressure. On the other hand, in normally and overpressured reservoirs, and especially in liquids-rich reservoirs, energized fluids are infrequently used vs slickwater and gel fracs. This approach is based on the ability of oil-wet surfaces to resist the entry of water into pores, and of normally or overpressured reservoir hydrocarbons to drive water out. However, there are limitations that can reduce productivity: (1) A large fraction of reservoir porosity may not be oil-wet and will take up water. For example, in the Marcellus shale slickwater load recovery is often 20% or less. (2) If fracturing pressures are sufficiently high, water may be driven into pores where it is too strongly held to be driven out by reservoir pressure. The complex stress regime in horizontal well fracs results in fracture pumping pressures that may exceed twice the reservoir pressure. When reservoir permeabilities are in the microdarcy to nanodarcy range, capillary pressures may easily reach several thousand psi (GPa range). The threshold is low enough to allow entry of high pressure frac fluid into the small pore throats but too high to allow significant flowback from these pore throats with the lower pressure from the reservoir. In this paper our main focus will be on the use of energized fluid fracs provide a higher viscosity system for improved proppant transport. This aspect is particularly relevant for liquids-rich reservoirs and has not been extensively discussed previously. Rock properties and net pay profiles have been developed for several major liquids rich shale reservoirs in the US to estimate proppant placement relative to the net pay using 3D hydraulic fracture simulators. A comparison will be made among the main fluid options for several liquids rich shales in North America to demonstrate the benefits of energized fluids.
AAPG Datapages/Search and Discovery Article #90189 © 2014 AAPG Annual Convention and Exhibition, Houston, Texas, USA, April 6–9, 2014