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Water Imbibition and Salt Diffusion in Gas Shales: A Field and Laboratory Study Open Access


Other title
Salt Diffusion
Type of item
Degree grantor
University of Alberta
Author or creator
Ghanbari, Ebrahim
Supervisor and department
Dehghanpour, Hassan (Civil and Environmental Engineering)
Examining committee member and department
Leung, Juliana (Civil and Environmental Engineering)
Potter, David (Earth and Atmospheric Sciences)
Department of Civil and Environmental Engineering
Petroleum Engineering
Date accepted
Graduation date
Master of Science
Degree level
Hydraulic fracturing treatment has been increasingly applied to stimulate shale gas reservoirs. During hydraulic fracturing, a large amount of fracturing water is injected into the target formation. However, only a small fraction of injected fluid, typically 10 to 20 %, can be recovered during clean-up phase. The fate of non-recovered fracturing water is still poorly understood. Further, the injected water interacts with reservoir system and therefore, the produced water contains valuable information about the nature of the stimulated reservoir. In this thesis, we analyze flowback field data, conduct simulation studies and perform a series of imbibition/diffusion experiments to (1) investigate the reasons behind low water recovery, (2) characterize the created fracture network and (3) identify dominant parameters and mechanisms that control ion diffusion and liquid imbibition rates. The volumetric and chemical analysis of flowback data suggests that the geometry of the created fracture network has a significant effect on early time fluid production and salinity profile of flowback water. Wells with simple fracture network have a high water recovery and low gas production. The salinity profile of these wells gradually increases and then reaches a plateau. On the other hand, wells with complex fracture network have a low water recovery and high gas production. The salinity profile of these wells keeps increasing even at the end of flowback process. The imbibition experiments show that, fracturing water imbibition into shale matrix can partially explain low water recovery after fracturing treatment. It is also found that, in addition to capillary pressure, intrinsic rock properties such as depositional lamination, organic material distribution and clay content, control the liquid imbibition rates in gas shale. The diffusion experiments indicate that shale sample properties such as porosity, permeability, clay content and depositional lamination have a significant effect on salt diffusion rate. Simulation studies show that the counter current imbibition of fracturing water during the shut-in time can result in a significant gas build-up in the fractures and therefore increases early time gas production rate. Furthermore, increasing the complexity of fracture network increases the gas production and decreases the water recovery.
Permission is hereby granted to the University of Alberta Libraries to reproduce single copies of this thesis and to lend or sell such copies for private, scholarly or scientific research purposes only. Where the thesis is converted to, or otherwise made available in digital form, the University of Alberta will advise potential users of the thesis of these terms. The author reserves all other publication and other rights in association with the copyright in the thesis and, except as herein before provided, neither the thesis nor any substantial portion thereof may be printed or otherwise reproduced in any material form whatsoever without the author's prior written permission.
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