Flow-Rate Behavior and Imbibition in Shale
- Dongmei Wang (University of North Dakota) | Raymond Butler (University of North Dakota) | Hong Liu (University of North Dakota) | Salowa Ahmed (University of North Dakota)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- August 2011
- Document Type
- Journal Paper
- 485 - 492
- 2011. Society of Petroleum Engineers
- 5.2.1 Phase Behavior and PVT Measurements, 2.5.2 Fracturing Materials (Fluids, Proppant), 1.6.9 Coring, Fishing, 4.3.3 Aspaltenes
- Flow Behavior, Shale, EOR, Imbibtion
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As part of our investigations of a new chemical imbibition idea (using surfactant or brine formulations) to stimulate oil recovery from shale, we are studying oil flow through and, especially, brine intake into shale to displace oil. Our first studies in this area focused on an outcrop shale, specifically the Odanah member of Pierre shale in North Dakota, USA. We studied porosity, permeability to oil, permeability to water, and spontaneous brine intake for the Pierre shale. We found that porosities for Pierre shale cores were relatively high--from 25 to 35%. Porosities for our measurements of Bakken cores averaged less than 3%. 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 130TM) was higher than for Bakken oil--apparently because of deposition of wax/asphaltenes/particulates on the Pierre core faces when injecting Bakken oil. Permeability to oil for Pierre shale cores (with no water present) ranged from 3.32×10-5 to 2.19×10-4 md when injecting Bakken oil and from 4.85×10-4 to 2.34×10-3 md when injecting Soltrol 130. Permeability to Bakken oil for a Bakken core (with no water present) averaged 4.84×10-4 md. In Pierre shale and Bakken 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. Saline brine spontaneously entered into oil-saturated Pierre cores, yielding recovery values up to 41% of original oil in place (OOIP). During exposure to brine, our results indicated an increase in permeability--presumably by mineral dissolution during forced brine injection and by cracking (possibly caused by clay swelling) during spontaneous brine intake. This result is encouraging for the application of imbibition to enhance oil recovery from shale. Before 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 the Bakken formation.
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