Understanding Formation Damage Processes: An Essential Ingredient For Improved Measurement And Interpretation Of Relative Permeability Data

Abstract

Abstract Anomalous trends have been observed in laboratory-derived relative permeability data especially in rock samples that contain mobile (siliceous/micaceous/kaolinitic) fines and/or water sensitive clays. Water-oil relative permeability data determined for such rocks by the unsteady-state technique have at times exhibited the following characteristics:Non-monotonic trends with saturationSlightly S-shaped relative water permeability with a 'bend-over' at high water saturationsRebound in relative water permeability at residual oil saturation with reversal in flow directionThese characteristics are indicative of adverse physico-chemical interactions between the flowing phases and the rock, which invalidate the relative permeability concept. This paper presents the results of laboratory studies conducted to elucidate the role of formation damage processes in the determination of relative permeability data. Experimental data generated on rocks with fine particulates, indicate that mechanically induced damage can occur if the displacing fluid velocity, increased to overcome capillary end effect, exceeds the critical velocity for mobilization of resident mineral fines. Chemically induced damage was found to accompany the mechanical damage if the injected brine was not in ionic equilibrium with the rock. Most friable samples containing micas, feldspars and illite/kaolinite, which have potassium ions in their interlayer sites, were damaged by the flow of sodium and/or calcium chloride brines during brine permeability tests. Critical velocities for entrainment of fines were determined to be higher for KCl brines than for NaCl/CaCl2 brines in water- wet Berea samples. Laboratory protocols which eliminate formation damage processes during relative permeability measurement have been developed and are presented in this paper. These include:use of velocities less than critical for floods on butted cores with lengths sufficient to reduce capillary end effects,addition of trace ions such as K+ ions in simulated formation brines,equilibration of the fluids with the rock and the use of aged fluids for dynamic displacement. Unsteady-state imbibition tests performed on short core plugs at flowrates greater than critical for fines mobilization, are discouraged. Rather, low rate floods should be conducted and the data analyzed by numerical techniques which include the capillary pressure term in deriving relative permeability curves. Introduction Major oil-bearing sands and sandstones of the world, such as the Ivishak Formation, Prudhoe Bay Field; Franskiy Formation, Volga Ural Region; Brent and Rotliegendes, North Sea; Cold Lake and Peace River Formations, Canada; Agbada Formation, Meren Field, Nigeria; Morrow Formation, Texas County, Oklahoma; and most unconsolidated sands offshore Southern California) contain minerals (kaolinite, illite, feldspars, micas, and cherts), which are potential sources of mobile fines. From petrographic data, Kersey noted that all clastic reservoir rocks containing more than 10 percent clays; all bioturbated rocks containing detrital clays; and all rocks containing authigenic, pore filling minerals are sensitive to fines migration problems. Pore filling and pore lining minerals are readily contacted by any fluids which come in contact with the formation. The surface area exposed to flow controls the rate of physico-chemical interactions within the pore structure. This is true for most fines bearing minerals, particularly clays with high surface area to volume ratios. Loosely attached fine particulates can be detached from their substrates and transported by flowing fluids to certain pore throats in the reservoir rock. The particulates become trapped at the pore throats, reducing effective hydraulic radius and leading to permeability impairment.