Flow Rate Behavior and Imbibition in Shale

Abstract

Abstract Shale is an important source of oil and gas in North America. Most shale reservoirs have a low porosity and ultra low permeability with naturally fractures. Shale formations have long been considered important source rocks, capable of producing oil at economic rates when completed by hydraulically fractured horizontal wells. As part of our investigations of a new chemical imbibition idea (using surfactant or brine formulations) to stimulate oil recovery from shale, accurate determination of shale permeability and porosity is needed to assess potential recovery rates. Our interest in this study is in oil flow through shale, especially relevant to the Bakken formation oil. Our first studies in this area focused on an outcrop shale, specifically the Odanah member of Pierre Shale in North Dakota. As part of an effort to assess the potential for imbibition to recovery oil from shale, we studied porosity, permeability to oil, permeability to water, and imbibition for the Pierre shale. We found that porosities for Pierre shale cores were relatively high—from 25% to 35%. Bakken oil imbibed into dry Pierre shale cores (up to 5-mm in thickness) to the same extent as could be achieved by forced injection of oil (i.e., achieving the same oil saturations for both processes). Permeability to a clean mineral oil (Soltrol 130) was higher than for Bakken oil—apparently because of deposition of wax/asphaltenes/particulates on the core faces when injecting Bakken oil. Permeability to oil for Pierre shale cores (with no water present) ranged from 3x10-5 to 5x10-4 md when injecting Bakken oil and from 2x10-4 to 1.3x10-3 md when injecting Soltrol 130. For both oils in cores with thicknesses ranging from 0.65 to 5 mm, permeabilities were basically independent of flow rate, in agreement with expectations from the Darcy equation. A saline brine imbibed effectively into oil-saturated Pierre cores, yielding recovery values up to 41% OOIP. During exposure to brine, our results indicated an increase in permeability—presumably by mineral dissolution during forced brine injection and by cracking (possibly due to clay swelling) during spontaneous imbibition. This result is encouraging for the application of imbibition to enhance oil recovery from shale. Prior to these studies, we feared that exposure to brine might reduce shale permeability because of clay swelling. The laboratory results will help during a current study of surfactant and brine imbibition in Bakken shale.