Shale-Fluid Interactions Measured Under Simulated Downhole Conditions

Abstract

Abstract Preserved shale samples, from four different shale cores, were exposed to various fluids while under simulated downhole stress conditions. Prior to fluid exposure, the samples were not contacted by any aqueous fluid, including simulated pore fluid. Time-dependent measurements of pore pressure, swelling and acoustic velocities were made. Pore pressures both less than and greater than the applied fluid pressure were observed, and apparent osmotic membrane efficiencies are calculated. Swelling was found to depend not only on the shale type and the fluid, but also on the level of confining stress. Swelling anisotropy was observed. Acoustic velocities were found to change as a result of fluid exposure, and the amount of change is dependent on the fluid type and on the existence of swelling. Introduction Shales are responsible for most occurrences of wellbore instability. One reason is that shales are relatively weak rocks. The other reason is that shales contain significant amounts of clays. When in contact with a water-base fluid, shales can hydrate, swell and weaken. Difficult shales are often drilled using oil-base or synthetic (non-aqueous) base fluids in order to promote wellbore stability. However, the use of oil-base and synthetic-base fluids is becoming more expensive and restricted worldwide. The petroleum industry is very interested in developing environmentally-friendly water-base drilling fluids that stabilize shales as effectively as oil or synthetic base fluids. Developing such fluids, however, is difficult. As explained in the next section, water-base fluids interact with shales in several ways. To control these interactions, we must first understand and quantify them. The work described in this paper is an attempt to directly measure some of these interactions, determine their effect on wellbore stability, and determine if shale-fluid interactions might be detectable in real-time with wellbore acoustic tools. Concepts and Prior Work When drilling through a shale formation with a water-base fluid, several different interactions can occur between the fluid and the shale1,2. The first, and least complex, of these interactions is Darcy flow from the wellbore into the shale, if the wellbore pressure is greater than the shale pore pressure. A filter cake does not form on a non-fractured shale, because the shale permeability is several orders of magnitude less than the permeability of the filter cake. Convective flow into the shale slowly occurs, impeded only by the low permeability of the shale itself. The second important interaction is the diffusive movement of water molecules and ions, driven by osmotic forces and concentration gradients. These movements can be either into or out of the shale. They are governed by the activity of the drilling fluid relative to the shale activity (affects H2O movement), the relative concentrations of the various ionic species (affects ion movement), interactions between the clays and H2O/ions, and restrictions to H2O/ion movement. If the shale were to act as a perfect semi-permeable membrane, then only water molecules would move into or out of the shale. The convective (hydraulically driven) and diffusive (chemically driven) movements of water and ions into a shale can have several effects. One effect is swelling, and another possible effect is strength loss. An additional important effect on wellbore stability is the change in near-wellbore pore pressure. Any elevation in pore pressure leads to a direct reduction in hole stability by effectively weakening the rock, because the shear strength is reduced due to the reduction in mean effective stress. The studies reported here were prompted by the recognition that we must be able to predict the near-wellbore pore pressure with any water-base fluid. Furthermore, we must quantify the combined effects of both hydraulic and chemical forces, not only on pore pressure but also on swelling.