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Permanent link (DOI): https://doi.org/10.7939/R3KD4S
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Water Imbibition and Salt Diffusion in Gas Shales: A Field and Laboratory Study Open Access
- Other title
- Type of item
- Degree grantor
University of Alberta
- Author or creator
- 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
- 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.
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