Pore-scale modeling of a water/oil two-phase flow in hot water flooding for enhanced oil recovery

RSC Advances ◽  
2015 ◽  
Vol 5 (104) ◽  
pp. 85373-85382 ◽  
Author(s):  
Mingming Lv ◽  
Shuzhong Wang
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Hot Water ◽  
Water Flooding ◽  
Phase Flow ◽  
Pore Scale ◽  
Water Displacement ◽  
Pore Throat ◽  
Two Phase ◽  
Scale Modeling

The pore-scale behaviors of hot water displacement in a pore–throat microchannel were revealed by simulations for different wettability systems.

scholarly journals Experimental Investigation on Oil Enhancement Mechanism of Hot Water Injection in tight reservoirs

Open Physics ◽  
2016 ◽  
Vol 14 (1) ◽  
pp. 703-713 ◽  
Author(s):  
Hao Yongmao ◽  
Lu Mingjing ◽  
Dong Chengshun ◽  
Jia Jianpeng ◽  
Su Yuliang ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Water Saturation ◽  
Water Injection ◽  
Hot Water ◽  
Water Flooding ◽  
Water Displacement ◽  
Pore Characteristics ◽  
Irreducible Water Saturation ◽  
Tight Reservoirs ◽  
Oil Water

AbstractAimed at enhancing the oil recovery of tight reservoirs, the mechanism of hot water flooding was studied in this paper. Experiments were conducted to investigate the influence of hot water injection on oil properties, and the interaction between rock and fluid, petrophysical property of the reservoirs. Results show that with the injected water temperature increasing, the oil/water viscosity ratio falls slightly in a tight reservoir which has little effect on oil recovery. Further it shows that the volume factor of oil increases significantly which can increase the formation energy and thus raise the formation pressure. At the same time, oil/water interfacial tension decreases slightly which has a positive effect on production though the reduction is not obvious. Meanwhile, the irreducible water saturation and the residual oil saturation are both reduced, the common percolation area of two phases is widened and the general shape of the curve improves. The threshold pressure gradient that crude oil starts to flow also decreases. It relates the power function to the temperature, which means it will be easier for oil production and water injection. Further the pore characteristics of reservoir rocks improves which leads to better water displacement. Based on the experimental results and influence of temperature on different aspects of hot water injection, the flow velocity expression of two-phase of oil and water after hot water injection in tight reservoirs is obtained.

scholarly journals Experimental study and numerical modeling for enhancing oil recovery from carbonate reservoirs by nanoparticle flooding

2019 ◽  
Vol 74 ◽  
pp. 5 ◽  
Author(s):  
Mehrdad Sepehri ◽  
Babak Moradi ◽  
Abolghasem Emamzadeh ◽  
Amir H. Mohammadi
Keyword(s):  
Numerical Modeling ◽  
Porous Media ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Recovery Process ◽  
Water Flooding ◽  
Wettability Alteration ◽  
Sensitivity Analyses ◽  
Two Phase ◽  
Fluid Properties

Nowadays, nanotechnology has become a very attractive subject in Enhanced Oil Recovery (EOR) researches. In the current study, a carbonate system has been selected and first the effects of nanoparticles on the rock and fluid properties have been experimentally investigated and then the simulation and numerical modeling of the nanofluid injection for enhanced oil recovery process have been studied. After nanofluid treatment, experimental results have shown wettability alteration. A two-phase flow mathematical model and a numerical simulator considering wettability alteration have been developed. The numerical simulation results show that wettability alteration from oil-wet to water-wet due to presence of nanoparticles can lead to 8–10% increase in recovery factor in comparison with normal water flooding. Different sensitivity analyses and injection scenarios have been considered and assessed. Using numerical modeling, wettability alteration process and formation damage caused by entrainment and entrapment of nanoparticles in porous media have been proved. Finally, the net rate of nanoparticles’ loss in porous media has been investigated.

Machine Learning Approach to Predict the Flow Rate for an Immiscible Two-Phase Flow at Pore Scale for Enhanced Oil Recovery Application

2018 ◽  
Author(s):  
Arturo Rodriguez ◽  
V. M. Krushnarao Kotteda ◽  
Luis F. Rodriguez ◽  
Vinod Kumar ◽  
Arturo Schiaffino ◽  
...  
Keyword(s):  
Machine Learning ◽  
Surface Tension ◽  
Pressure Drop ◽  
Flow Rate ◽  
Oil Recovery ◽  
Two Phase Flow ◽  
Machine Learning Algorithms ◽  
Phase Flow ◽  
Pore Scale ◽  
Two Phase

Due to global demand for energy, there is a need to maximize oil extraction from wet reservoir sedimentary formations, which implies the efficient extraction of oil at the pore scale. The approach involves pressurizing water into the wetting oil pore of the rock for displacing and extracting the oil. The two-phase flow is complicated because of the behavior of the fluid flow at the pore scale, and capillary quantities such as surface tension, viscosities, pressure drop, radius of the medium, and contact angle become important. In the present work, we use machine learning algorithms in TensorFlow to predict the volumetric flow rate for a given pressure drop, surface tension, viscosity and geometry of the pores. The TensorFlow software library was developed by the Google Brain team and is one of the most powerful tools for developing machine learning workflows. Machine learning models can be trained on data and then these models are used to make predictions. In this paper, the predicted values for a two-phase flow of various pore sizes and liquids are validated against the numerical and experimental results in the literature.

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