Cleanup of Water Blocks in Depleted Low-Permeability Reservoirs

Abstract

Abstract Poor gas inflow performance is observed in some depleted, low permeability, reservoirs after completion and workover operations. The use of aqueous treatment fluids often results in a ‘water block’ due to poor recovery of the fluids that have leaked-off. This curtails well deliverability due to reduced relative permeability to gas/oil in the invaded region. This study analyzes the effect of various factors governing the cleanup of water blocks in fractured and un-fractured wells for both gas and oil reservoirs. The effects of drawdown, capillary pressure, relative permeability, and heterogeneity as well as the influence of fracture geometry on well deliverability following some well operations, such as fracturing, have been examined by detailed simulations. Drawdown, fracture length and shapes of relative permeability curves strongly affect the recovery in productivity. On the other hand, end point relative permeabilities and horizontal well length have an insignificant impact on cleanup. Higher vertical permeabilities favor early recovery of well productivity in ‘high perm’ layers and delay cleanup of water blocks in ‘low perm‘ layers. The results suggest the need to lower capillary pressure by reducing interfacial tension and/or altering wettability of the rock surface from strongly water-wet to intermediate-wet. With the correct selection of treatment fluids, proper design of fracture geometry and optimum drawdown applied it is possible to cleanup water blocks more rapidly in depleted low-permeability reservoirs. Introduction Loss of water-based fluids commonly occurs in drilling, completion and fracturing operations. These fluids are quickly recovered during flowback when the drawdown is much larger than the capillary forces holding the water in the pore space. However, in heterogeneous formations or depleted low-permeability reservoirs, drawdowns are often of the same order of magnitude as the capillary forces. In such cases well inflow performance is found to be poor following some well operations such as fracturing. This is due to an extended period of cleanup or incomplete cleaning of injected fluids. Leak off of aqueous fluids creates a zone of high water saturation around the wellbore and along the fractures. This reduces the relative permeability to hydrocarbons in the invaded region. This phenomenon is referred to as a "water block". Experiments and numerical studies have been carried out in the past to study the problem of "water blocks". Holditch1 accounted for capillary pressure and relative permeability in his numerical study of formation damage around a hydraulic fracture in a tight gas reservoir. Results presented in the study show that reservoir properties such as capillary pressure and relative permeability in low-permeability reservoirs are important in determining the behavior of a fractured well during cleanup. He also observed that the damaged zone permeability must be reduced by several orders of magnitude before a serious water block to gas flow will occur. Even if the reservoir rock permeability is not reduced, gas production can be severely curtailed if the pressure drawdown does not exceed the formation capillary pressure. Penny et al2 found in laboratory as well as in field studies that the judicious alteration of wettability to control capillary pressure and/or relative permeability can promote a rapid and thorough cleanup of injected water. Increasing fracture conductivity can further enhance gas well cleanup. They claim that "oil-wetting" (reducing water wetting in a gas-water system) the rock surface would lower the capillary pressure sufficiently to reduce water blocks. Abrams and Vinegar3 used CAT Scans to measure brine saturations and image the fluid flow in microdarcy gas sand cores under stress conditions that simulate a hydraulic fracture. The lab results suggest that water blocks are not important when drawdown pressures at the fracture face exceed the capillary entry pressure by several hundred psi. The addition of alcohol or an alcohol/surfactant package did not significantly improve the gas flow in these cores. On the other hand, McLeod4,5 noted that alcohol causes a quick recovery of stimulation fluids and a rapid return of gas production in sandstone formations by lowering surface tension and thus reducing capillary forces. Methanol also facilitates faster vaporization, which lowers the liquid saturation in the invaded zone, thereby, increasing the gas productivity.