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Fluid Interaction with Tight Rocks to Induce Energy Recovery | OMICS International | Abstract
ISSN 2472-0518

Oil & Gas Research
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Research Article

Fluid Interaction with Tight Rocks to Induce Energy Recovery

Wang Dongmei*, Zhang Jin, Raymond Butler, Adam Clark , Dave Koskella and Racheal Rabun

School of Geology & Geological Engineering, University of North Dakota, USA

*Corresponding Author:
Wang Dongmei
School of Geology & Geological Engineering
University of North Dakota, USA
Tel: +1 701-777-6143
E-mail: [email protected]

Received Date: March 12, 2017; Accepted Date: March 18, 2017; Published Date: March 25, 2017

Citation: Dongmei W, Jin Z, Butler R (2017) Fluid Interaction with Tight Rocks to Induce Energy Recovery. Oil Gas Res 3: 134. doi: 10.4172/2472-0518.1000134

Copyright: © 2017 Dongmei W, et al. This is an open-access article distributed under the terms of the Creative Commons Attribution License, which permits unrestricted use, distribution, and reproduction in any medium, provided the original author and source are credited.

Abstract

The research using aqueous surfactant fluid to interact with tight rocks to increase petroleum production was conducted from our group in 2009. As part of our effort to assess the potential for imbibition to recovery oil from shale, we studied the porosity, permeability to oil, permeability to waters (brine water, and surfactants), and spontaneous surfactant intake for Bakken and Niobrara rocks. We observed that porosities for Niobrara cores were generally higher than those from Bakken cores. Consistent with the Darcy equation, rate-independent water and oil permeability was noted. Cores from the Niobrara and Bakken formations exhibited a broad range of permeability, ranging from 0.11 to 26 microdarcys (μD). In the Niobrara formation, permeability was least in marl (0.1-4 μD), larger in chalk (1-15 μD), and greatest in sandstone (8-26 μD). Although variations occurred, the absolute permeability to water, permeability to oil, and permeability to surfactant formulations were all comparable. The surfactant formulations tested exhibited a favorable potential for fluid flowing in both formations by spontaneous imbibition. The average oil recovery by spontaneous imbibition of the selected surfactants was ranged from 13 to 57% OOIP at optimal salinity, at least 5 percentage incremental in oil recovery over brine water imbibition.

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