Temperature is an important yet often ignored variable in translating laboratory measurement of oil and gas recovery related operations to reservoir conditions. The present study addresses the variation of formation damage potential of a reservoir with temperature. A strategy for obtaining the temperature sensitivity of various model parameters determining the formation damage potential of a reservoir rock is presented.
Rock-fluid interactions in petroleum reservoirs frequently lead to the impairment of permeability of the porous medium, commonly referred to as the formation damage problem. Such interactions effect the efficiency of recovery in oil and gas production operations. Although most reservoirs are at higher temperatures and most recovery processes involve temperature shocks, formation damage studies are usually performed at constant, ambient temperatures in the laboratory. In a thermal recovery process, a reservoir is subjected to a rapid temperature rise as shown in Fig. 1, whereas, in a water flooding process, a reservoir is subjected to a rapid temperature drop as shown in Fig. 2. The temperature shock can cause formation damage in a manner analogous to salinity shock. Colloidal processes such as fines release, migration and trapping and related phenomena such as thin film stability and wettability are controlled by interaction between the particles, fluids, and pore surface minerals. These interactions depend on the reservoir temperature. For instance, electrostatic forces are controlled by the ionic activity of the brine, the charge density and the electrical potential of the surface of particles and pore walls, which vary with temperature changes. Hydrodynamic forces which often play a critical role in determining the release, migration, and retention rate of fines in reservoir rocks are dependent on fluid viscosity, which is very sensitive to temperature.
In many cases, the oil and gas production from reservoirs involves multiple fluid phases in the reservoir. One or more of these fluids may be mobile depending on the reservoir characteristics. In such situations, the mobilization of fines depends on their wettability and on the mobility of the wetting phase. The particle wettability and the relative mobility of the wetting and non-wetting phases vary when temperature changes from ambient to reservoir conditions. The overall formation damage potential of reservoirs is then changed due to the alteration of the absolute reservoir permeability, and the relative permeability and capillary pressure curves. For a given combination of reservoir rock matrix, brine, and crude oil, the formation damage potential of a reservoir is governed by the parameters of various formation damage mechanisms which are highly sensitive to temperature.