Gas flow behavior in porous media with micro- and nanoscale pores has always been attracted great attention. Gas transport mechanism in such pores is a complex problem, which includes continuous flow, slip flow and transition flow. In this study, the microtubes of quartz microcapillary and nanopores alumina membrane were used, and the gas flow measurements through the microtubes and nanopores with the diameters ranging from 6.42 μm to 12.5 nm were conducted. The experimental results show that the gas flow characteristics are in rough agreement with the Hagen-Poiseuille (H-P) equation in microscale. However, the flux of gas flow through the nanopores is larger than the H-P equation by more than an order of magnitude, and thus the H-P equation considerably underestimates gas flux. The Knudsen diffusion and slip flow coexist in the nanoscale pores and their contributions to the gas flux increase as the diameter decreases. The slip flow increases with the decrease in diameter, and the slip length decreases with the increase in driving pressure. Furthermore, the experimental gas flow resistance is less than the theoretical value in the nanopores and the flow resistance decreases along with the decrease in diameter, which explains the phenomenon of flux increase and the occurrence of a considerable slip length in nanoscale. These results can provide insights into a better understanding of gas flow in micro- and nanoscale pores and enable us to exactly predict and actively control gas slip.
Microbial enhanced oil recovery (MEOR) depends on the in situ microbial activity to release trapped oil in reservoirs. In practice, undesired consumption is a universal phenomenon but cannot be observed effectively in small-scale physical simulations due to the scale effect. The present paper investigates the dynamics of oil recovery, biomass and nutrient consumption in a series of flooding experiments in a dedicated large-scale sand-pack column. First, control experiments of nutrient transportation with and without microbial consumption were conducted, which characterized the nutrient loss during transportation. Then, a standard microbial flooding experiment was performed recovering additional oil (4.9 % Original Oil in Place, OOIP), during which microbial activity mostly occurred upstream, where oil saturation declined earlier and steeper than downstream in the column. Subsequently, more oil remained downstream due to nutrient shortage. Finally, further research was conducted to enhance the ultimate recovery by optimizing the injection strategy. An extra 3.5 % OOIP was recovered when the nutrients were injected in the middle of the column, and another additional 11.9 % OOIP were recovered by altering the timing of nutrient injection.
An experimental investigation of existing conditions of the threshold pressure gradient (TPG) for gas flow in waterbearing tight gas reservoirs was made and discussed, using cores at different water saturations prepared from the Sichuan gas field in China. The existence of TPG was proven, and the relationship between TPG and water saturation and absolute permeability were obtained by laboratory tests. TPG increases with higher water saturation and lower absolute permeability. Consequently, a mathematical model of low-velocity non-Darcy gas flow was established on the basis of conservation of mass and momentum equations. According to the analytical solution of non-Darcy radial flow derived here, an easy and accurate calculation method of the control radius is presented, which is most popular with reservoir engineers. Factors, such as TPG and isothermal compressibility, on effective deployment were also discussed. The analysis of calculation results demonstrates that peripheral reserves of the wellbore are difficult to deploy and formation energy is used mainly near the wellbore because of the existence of TPG, unlike in Darcy flow. The quantification of effective deployment of water-bearing tight gas reservoirs provides a theoretical foundation for reservoir evaluation and development design.
Microbial enhanced oil recovery (MEOR) is being used more widely, and the biological contributions involved in MEOR need to be identified and quantified for the improvement of field applications. Owing to the excellent interfacial activity and the wide distribution of producing strains in oil reservoirs, lipopeptides have proved to be an essential part of the complex mechanisms in MEOR. In this study, crude lipopeptides were produced by a strain isolated from an indigenous community in an oil reservoir. It was found that crude lipopeptides can effectively reduce the IFT (interfacial tension) to 10(-1)~10(-2) mN/m under high salinity without forming stable emulsions, and the wettability of natural sandstone can be enhanced (Amott index, from 0.36 to 0.48). The results of core flooding experiments indicate that an additional 5.2% of original oil in place can be recovered with a 9.5% reduction of injection pressure. After the shut-in period, the wettability of the core, the reduction of injection pressure, and the oil recovery can be improved to 0.63, 16.2% and 9.6%, respectively. In the microscopic flooding experiments, the crude oil in membrane, cluster, and throat states contribute nearly 90% in total of the additional oil recovery, and the recovery of membranestate oil was significantly enhanced by 93.3% after shut in. Based on the results in macro and pore scale, the IFT reduction and the wettability alteration are considered primary contributors to oil recovery, while the latter was more dominant after one shut-in period.
To understand the
pore-scale processes of asphaltene deposition
during heavy oil recovery by CO2 flooding, a series of
microscopic flooding experiments were conducted in two-dimensional
models under high-temperature (80 °C) and high-pressure (2, 6,
and 10 MPa) conditions. Two different heavy oils, AZ-4 and KD-9 (with
viscosities of 7754 and 19 290 mPa·s, respectively, at
80 °C), were used. In these samples, up to 95% and 85% of oil
viscosity reduction, respectively, could be achieved by CO2 dissolution. During CO2 flooding in the microscopic models,
with increasing fluid pressure (6 and 10 MPa) and CO2 concentrations
(60–80 mol %), both the covered area (17–38%) and the
sizes of the deposited particles (up to 200 μm) became larger.
At 6 MPa, a dynamic between between dissolution and precipitation
was observed in large pores (with diameters of >350 μm).
According
to the solvent dissolution test (heptane and toluene), the deposited
solids comprise both asphaltene and alkane components. Between AZ-4
and KD-9, higher resin/asphaltene ratios tend to reduce asphaltene
deposition during the dissolution of CO2 by stabilizing
the solubility of asphaltene in crude oil. In addition, although permeability
decreased (up to 15%) with increasing pressure (2–10 MPa) and
CO2 concentrations (25–70 mol %), the oil recovery
mostly increased (up to 88.6% with AZ-4). The only decrease in oil
recovery occurred with KD-9, which decreased from 64.7% (6 MPa, with
a CO2 concentration of 69.7%) to 56.1% under 10 MPa and
considerably high CO2 concentrations (79.7 mol %). Compared
with the light oil system, the tested heavy oil shows considerably
improved recovery and less asphaltene deposition during high-concentration
CO2 flooding. Therefore, although CO2 miscibility
can hardly be achieved in heavy oil reservoirs, CO2 is
of great interest due to its high solubility in heavy oil and significant
oil viscosity reduction.
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