Summary
In this study, the effects of viscosity-reducer (VR) concentration, salinity, water/oil ratio (WOR), and temperature on the performance of emulsions are examined on the basis of the selected VR. Different VR-injection scenarios, including single-VR injection and coinjection of steam and VR, are conducted after steamflooding by use of single-sandpack models. The results show that high VR concentration, high WOR, and low salinity are beneficial to form stable oil/water emulsions. The oil recoveries of steamflooding for bitumen and heavy oil are approximately 31 and 52%, respectively. The subsequent VR flooding gives an incremental oil recovery of 5.2 and 6.4% for bitumen and heavy oil, respectively. Flooding by steam/VR induces an additional oil recovery of 8.4–11.0% for bitumen and 12.1% for heavy oil. High-temperature steam favors the peeling off of oil and improving its fluidity, as well as the in-situ emulsions. VR solution is beneficial for the oil dispersion and further viscosity reduction. The coinjection of high-temperature steam and VR is much more effective for additional oil production in viscous-oil reservoirs.
This study presents
a study of nanoclay-surfactant-stabilized foam
to improve the oil recovery of steam flooding in offshore heavy oil
reservoirs. The foam stability and thermal resistance studies were
first performed to investigate the influence of nanoclay on the stability
and thermal resistance properties of the foam system. Then, the sandpack
flooding tests were conducted for investigating the resistance factor
and displacement abilities by nanoclay-surfactant-stabilized foam.
The results showed that the nanoclay-surfactant-stabilized foam has
excellent foaming ability and foam stability at 300 °C, which
can be used in steam flooding for offshore heavy oil reservoirs. The
resistance factor is greater than 30 at 300 °C when the gas–liquid
ratio ranges from 1 to 3, which indicated that the nanoclay-surfactant-stabilized
foam has good performance of thermal resistance and plugging effect.
The heterogeneous sandpack flooding test showed that the nanoclay-surfactant-stabilized
foam can effectively divert the steam into the low-permeability area
and improve the sweep efficiency, thus improving heavy oil recovery
of steam flooding. Therefore, the nanoclay-surfactant-stabilized foam
flooding has a great potential for improving oil recovery of steam
flooding in offshore heavy oil reservoirs.
In the process of the tight oilfields development, it is difficult to establish an effective system of injection-production displacement because of the high seepage resistance. The seepage does not follow the linear Darcy's law. However, the reservoir simulation software has not considered this phenomenon, which leads to the numerical simulation prediction results better than actual production data. Therefore, it is necessary to establish an effective method to calculate the low velocity non-Darcy flow in tight sandstone oil reservoirs numerical simulation.
This paper introduced a factor called starting pressure gradient (SPG), which can be used to describe non-Darcy seepage phenomenon. First of all, laboratory experiments of differential pressure flow method were carried out to get the relationship between core permeability and the SPG. In addition, according to the reservoir heterogeneity and exploitation degree, three methods were put forward for characterization the SPG in tight sandstone oil reservoirs numerical simulation. Finally, this numerical simulation method was used in the X tight sandstone oil reservoir history matching process to verify its accuracy.
The results of the laboratory experiments showed that, SPG exists in tight sandstone oil reservoirs. Liquid starts to flow when the production pressure gradient is greater than the SPG. SPG is an additional pressure resistance for each flow unit, the existence of SPG has intensified the degree of pressure drop. Analysis of the experimental data gave a power series relationship between the SPG and the permeability. And the SPG increases with the decreases of core permeability.
Reservoir heterogeneity criterion was established by introducing R and C factors. The greater R value and C values are, the higher the heterogeneity is. When the reservoir heterogeneity is weak (0< R≤0.3), we set SPG for each layer. When the reservoir heterogeneity is strong (0.3 < R≤ 1 or 0 < C≤1), we set SPG for each rock type. When the reservoir with intense heterogeneity (1<C<2), we set SPG for each gird.
After considering SPG, single well history matching coincidence rate improves from 64% to 87%, and every layer oil production prediction has high coincidence with the actual production data. Therefore, SPG cannot be ignored in tight sandstone oil reservoirs numerical simulation.
This paper provides a new method to describe the low velocity non-Darcy flow in tight sandstone oil reservoirs numerical simulation, and can guide the tight sandstone oil reservoirs development effectively. This method can also be applied in heavy oil reservoirs and tight gas reservoirs numerical simulation.
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