To investigate the characteristics of oil distribution in porous media systems during a high water cut stage, sandstones with different permeability scales of 53.63 × 10−3 μm2 and 108.11 × 10−3 μm2 were imaged under a resolution of 4.12 μm during a water flooding process using X-ray tomography. Based on the cluster-size distribution of oil segmented from the tomography images and through classification using the shape factor and Euler number, the transformation of the oil distribution pattern in different injection stages was studied for samples with different pore structures. In general, the distribution patterns of an oil cluster continuously change during water injection. Large connected oil clusters break off into smaller segments. The sandstone with a higher permeability (108.11 × 10−3 μm2) shows the larger change in distribution pattern, and the remaining oil is trapped in the pores with a radius of approximately 7–12 μm. Meanwhile, some disconnected clusters merge together and lead to a re-connection during the high water cut period. However, the pore structure becomes compact and complex, the residual nonwetting phase becomes static and is difficult to move; and thus, all distribution patterns coexist during the entire displacement process and mainly distribute in pores with a radius of 8–12 μm. For the pore-scale entrapment characteristics of the oil phase during a high water cut period, different enhance oil recovery (EOR) methods should be considered in sandstones correspondent to each permeability scale.
Oil–brine
interfaces play an important role in oil recovery and oil–brine
separation, in which the effects of salinity on interfacial tension
(IFT) have been much of debate in the past in experiments and modeling
studies owing to complex oil compositions. In this work, we use molecular
dynamics (MD) simulations to study the oil–brine interfacial
properties by designing seven systems containing different oil compositions
(decane with/without polar compounds) and the salinity in brine of
up to ∼14 wt %. We carefully investigate the salinity and polar
component effects by analyzing IFTs, density profiles, orientation
parameters, hydrogen bond densities, and charge density profiles.
The results indicate that O-bearing compounds (phenol and decanoic
acid) can significantly reduce the oil–brine IFT and exhibit
the highest Gibbs surface excess relative to water, while the others,
including N-bearing compounds (pyridine and quinoline) and S-bearing
compounds (thiophene and benzothiophene), only slightly decrease the
oil–brine IFTs and show a relatively small Gibbs surface excess.
Increasing salinity can slightly increase the oil–brine IFT
except in the system containing phenol, which shows a decrease. Phenol
and decanoic acid incline to be perpendicular to the interface and
generate numerous hydrogen bonds with water in the interfacial region,
while others prefer to be parallel to the interface with much fewer
hydrogen bonds with water. On the other hand, salinity has an insignificant
effect on the orientation of polar molecules and hydrogen bond density
in the interfacial region. The charges at the interfaces on the brine
and oil sides are negative and positive, respectively, and the polar
compounds disturb the arrangement of water molecules in the interfacial
regions, while the addition of salt ions result in the higher peak
values of charges in terms of water and system. Our study should provide
new insights into the oil–brine interfacial issues and clarify
some unsettled disputes.
CO2 huff-n-puff has been proven to be the most effective
enhanced oil recovery (EOR) method in shale oil reservoirs. The injected
CO2 will replenish reservoir energy and penetrate the reservoir
matrix to extract oil. However, the CO2 sweep volume during
the huff-n-puff process has not been accurately evaluated by existing
studies. In this paper, the CO2 sweep volume was investigated
through experimental and numerical simulation methods. In the experimental
study, the CO2 sweep areas were depicted by X-ray computed
tomography scan technology. The results indicated that the ratio of
the CO2 sweep area was 78.63% in the seventh huff-n-puff
cycle, leading to a total oil recovery of 56.80%. The numerical simulation
considered the mechanisms of molecular diffusion and nanopore confinement.
The results showed that in the first huff-n-puff cycle, the gas sweep
volume percentage was 9.47% after 100 days of huff period. In the
gas swept volume, oil viscosity was reduced by 25.9% to 68.2%. After
three cycles of CO2 injection, the oil recovery manifested
a 1.5% increase compared to the case without huff-n-puff. The contributions
of different parameters on gas sweep volume and cumulative oil recovery
were investigated. The results illustrated that the nanopore confinement
effect and molecular diffusion had significant impacts on the gas
sweep volume and cumulative oil recovery. Higher injection pressure,
longer huff time, and more huff-n-puff cycles lead to larger gas sweep
volume, as well as cumulative oil recovery. A suitable primary depletion
period and a huff-n-puff schedule should be determined based on the
requirements of field production. The investigations in this study
provide insights into better understanding of the EOR mechanisms and
optimizing the design of CO2 huff-n-puff operations in
shale oil reservoirs.
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