Modelling shale spontaneous water intake using semi‐analytical and numerical approaches

Abstract

Shale matrix water intake during hydraulic fracturing is considered undesirable due to the high volume of unrestrained water loss; however, it is also rewarding because it can reduce the possibility of groundwater contamination. The water intake also plays a dual role in changing the shale production performance; water imbibition into matrix pores can dramatically reduce the effective permeability and, at the same time, might enhance hydrocarbon production by creating adsorption-induced micro-fractures. Quantifying the formation intake capacity and its breadth is the key to optimizing fracturing operation, flowback, and production strategy. This work entails complementary semi-analytical and numerical analyses and investigates the effects of basic rock and fluid properties, wettability heterogeneity, and pore space connectivity on the shale imbibition characteristics. We consider a semi-analytical formulation of the spontaneous water imbibition, together with model results and validations, and try to provide a framework to link the capillary imbibition capacity/rate to lab-scale observations. The core-scale measurements provide input for a sensitivity study on the matrix imbibition capacity in six shale plays in North America. The results suggest that rock permeability, hydraulic tortuosity, and initial and residual hydrocarbon saturations are among the most influential factors on the spontaneous water intake during shut-in periods. Direct quasi-static simulations are then conducted through a submicron tomography image of the Eagle Ford shale, and two-phase pore-level fluid occupancies are reconstructed during spontaneous and forced imbibition processes. According to the numerical results, the presence of continuous organic matter laminae can lower the destructive effects of water imbibition on the hydrocarbon permeability.

The role of supercritical carbon dioxide for recovery of shale gas and sequestration in gas shale reservoirs

“…Because of the capillary force, water will stay in the fractures or pores which narrows or even block the gas flow pathways. 101 Therefore, the permeability of shale will decrease after water imbibition. [102][103][104] The reduction of shale permeability will increase with the increase of water saturation.…”

Effects of Temperature and Pressure on Spontaneous Counter-Current Imbibition in Unsaturated Porous Media

“…It should be noted that both our computational approach and collected experimental data focus on the imbibition stage before the point that the water front reaches the other end of the samples. For core-scale experiments, the typical imbibition curves always show several regions, i.e., the initial linear capillary imbibition, transition region, diffusion region, and stable region. , Actually, due to the small sample length, the transition region is easily observed once the water front approaches the boundary. However, at the reservoir scale, the matrix is large enough to postpone the transition time notably and keep the imbibition rate unchanged.…”