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During the development of shale gas reservoir, large amount of hydraulic fracturing fluid are forcibly injected into the reservoir to create complex fracture networks. However, field data indicate that only a small fraction of the injected fluid can be recovered during the clean-up period. Except the mostly discussed reasons including capillary force, osmotic-force, and clay hydration, the liquid (fracturing fluid) slip effect in the nanopores of shale matrix might be responsible for this phenomenon as well.
Firstly, the apparent liquid permeability (ALP) model in a single nanopore is established on the basis of Wu’s model (Wettability effect on nanoconfined water flow, PNAS, 2017), and the model considers the wettability and pore size related liquid slip effect. Then, the model is incorporated into the global lattice Boltzmann method (GLBM) to be scaled up into nanoporous shale. Next, we validated the proposed model by simulating liquid flow in a classical case. Finally, the proposed GLBM is employed to simulate threes cases including fracturing fluid flow in a homogeneous shale matrix, a reconstructed shale matrix based on a real SEM image, and a shale matrix in presence of micro-fractures to understand the transport behavior of the fluid in nanopores dominated shale matrix.
The flow capability of fracturing fluid in the organic/hydrophobic nanopores of shale matrix is significantly improved due to the huge wall-fluid effect, especially when the radius of the pore is smaller than 100 nm and the contact angle is higher than 120 degrees. After considering the slip effect, the flow field (magnitudes and preferred pathway) of the shale matrix can be significantly changed, and the velocity magnitudes of the region occupied by the organic matter (OM) can even exceed that of the inorganic matter (IOM), although the pores size in the OM is universally smaller than that in the IOM. When the shale matrix contains micro-fractures, the liquid slip effect still has a great impact on the flow enhancement, contributing a lot for the huge fracturing fluid loss in the field.
The transport behavior of fracturing fluid in nanopores dominated shale matrix is revealed, and the results implicit that, especially in the organic-rich shale gas reservoir, the fracturing fluid can be infiltrated into the ultra-tight shale formation easier than commonly expected during the hydraulic fracturing operation. This work demonstrates a new insight into the problem of huge fluid-loss reported from the field, providing a theoretical support for development of gas-shale reservoirs.
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