This study presents both experimental
and theoretical investigations
about gas transport in shales. Gas apparent permeability coefficients
and Klinkenberg slippage factors were determined on Longmaxi shales
using He, Ar, N2, CH4, and CO2. Then,
a model was developed to interpret the experimentally determined gas
slippage factor, considering the effects of intrinsic permeability,
porosity, tortuosity, and gas physical properties. The proposed model
is verified by correlating Klinkenberg-corrected permeabilities and
gas slippage factors of shales probed by He, Ar, N2, CH4, and CO2 at different confining pressures. The
model can quantitatively describe the gas dependence of slippage factors
(He > Ar > N2 > CH4 > CO2). According
to the model presented, the slippage factor increases proportionally
to the ratio of the characteristic gas parameter (C
) to tortuosity. The
model also leads to
a practicable approach to determine the effective tortuosity of tight
rocks at in situ reservoir stress state. Effective tortuosity of shales
determined using helium slippage measurements are far larger than
the generally assumed values. Another advantage of the model is its
ability to quantitatively account for the variation in permeability
values at similar gas slippage and the counterintuitive reduction
in gas slippage during compaction observed in previous experiments.
The proposed model correctly matches a set of gas slippage measurements
and provides insight into gas transport in tight porous medium.
Understanding
the penetration and retention of fracturing water
in geological systems is important for hydrocarbon extraction and
fluid disposal during hydraulic fracturing. This paper explores the
imbibition of fracturing water and its penetration profiles on shales
from Sichuan Basin, China. Water imbibition experiments were performed
on the collected shales with a variety of mineralogical compositions
and pore structure characteristics. Sorptivity, quantitatively characterizing
water imbibition capacity, was evaluated and its dependence on rock
fabric and mineralogical compositions was examined. Then, a nonlinear
diffusion model is presented to simulate the capillary flow during
the water imbibition process according to the unsaturated flow theory.
The solution of this model offers quantitative information about water
penetration and distribution in shales. The water sorptivity of shales
ranges from 0.1 to 1.8 × 10–6 m/s0.5. Water imbibed by shales is mainly along the shale lamination and
bedding. The strong mineral alignment also contributes to sorptivity
because of the preferential transport pathways. Shales with developed
microfracture networks have higher sorptivity. Nevertheless, water
penetration into shales is commonly less than 5 cm during the typical
shut-in period after fracturing operations. The fracturing fluid loss
is related to the development of microfracture networks and the fracture
width. The complex fracture networks with a small fracture width result
in low water recovery.
The
occurrence and distribution of hydrocarbons exert fundamental
control on the mobility and “sweet spot” identification
of shale oil systems. Here, we report both quantitative and visual
qualitative analyses of shale oil occurrence assisted by petrophysical
and geochemical approaches. Oil-bearing shales were extracted using
a ternary azeotropic solvent extraction system and then were characterized
for pore structure, fractal characteristics, and chemical compositions.
The results found that soluble organic matter is mainly controlled
by clay minerals because of the strong interaction between the interparticle
pores of clays and the extracted hydrocarbons. After solvent extraction,
the pore volume, specific surface area, and heterogeneity of shales
are all significantly enhanced. The light and heavy hydrocarbons of
the extracted soluble organic matter reside in pores with different
scales. The light hydrocarbons (aliphatic and aromatic hydrocarbons)
are mainly stored in fine mesopores with pore diameters less than
20 nm, while the heavy hydrocarbons (resins and asphaltenes) reside
in macropores. New evidence from field emission scanning electron
microscopy images shows that native hydrocarbons are expulsed from
kerogen–clay aggregates and provide rare in situ information
about the microscopic distribution of moveable hydrocarbons in shale
oil systems. This study improves the understanding of the occurrence
of hydrocarbons in shale oil.
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