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Fluid flow in porous media is extensively associated with Darcy's law. Deviations from Darcy's law and its limitations result in modifications known as non-Darcy flow at high velocity and Pre-Darcy flow at low velocity. In this paper, experiments were conducted to explore significance of departure from linearity at low fluid velocity (Pre-Darcy flow) in porous media. Effect of different liquid and gas types on the onset of Pre-Darcy flow were studied for water, condensate, n-hexane and n-heptane as liquid phase and CH4, CO2 and N2 as gas phase. Superficial velocity versus pressure gradient was measured and different onset values were reported. The minimum observed Darcy velocity was 0.189 × 10−05 m/s, below which Pre-Darcy flow prevails. Analysis was performed in terms of friction factor and Reynolds number for different particle size of 0.15, 0.25 and 0.3 mm. Pre-Darcy, Darcy and Non-Darcy flow regimes were observed and characterized in terms of R e √ k , Red and Rep. The range of Reynolds number were reported for different flow regimes, different particle sizes and different types of liquids. For the case of condensate in 0.15 mm sand pack, Pre-Darcy flow was observed in the range of R e √ k

Simulation of near-well flow around a single well in reservoirs is normally studied using radial logarithmic grids. A promising method for more complicated, multi-well cases is a combined approach of using a Cartesian and a radial grid. In this paper, a new method of overlapping grids is introduced in which a radial grid is overlapped on a coarse Cartesian grid in the area around a well. Connectivity between the two grids is established using an appropriate boundary condition. Five different algorithms of grids connectivity with internal boundary conditions are presented in which the data are transferred between the grids by interpolation pressure and saturations in each grid. This method is implemented in the open-source Matlab Reservoir Simulation Toolbox (MRST) using the modified black-oil model. The proposed approach is validated by simulation of a reference fine radial grid model on a gas-condensate reservoir. Comparing the results with the reference model indicates that the proposed Double-Scale method using a 21 × 21 coarse Cartesian grid is as accurate as a 1001 × 1001 simple Cartesian fine grid model. Then, a double-layer numerical problem with two production wells was simulated and sensitivity analysis was conducted to investigate the effect of critical condensate saturation and vertical permeability. Finally, the second SPE comparative solution project was simulated to compare the performance of the proposed method with the use of the perpendicular bisector (PEBI) grids around the well. Results showed that the accuracy of the PEBI grid and Double-Scale method are comparable. However, the proposed Double-Scale method is almost 2 times faster in this specific problem.

Gravity is one of the major driving forces for fluid flow in naturally fractured reservoirs. Gravity drainage appears to be a vital recovery mechanism over the oil production process in a majority of fractured reserves. In this paper, free-fall gravity drainage (FFGD) and forced gravity drainage (FGD) production approaches are investigated through employing a new fractured sand pack with a rectangular geometry. Distilled water and condensate are used as the wetting phase. Nitrogen, carbon dioxide, and air are also utilized as the non-wetting phase. A systematic sensitivity analysis is conducted to find the effects of the key factors such as fracture blockage, injection rate, dip angle, and type of wetting phase and injection fluid on the performance of FFGD and FGD processes. Also, a numerical simulation is performed to simulate the experiments. Results reveal that the FGD has a better performance under controlled process conditions, compared to the FFGD so that gas injection with a controlled rate improves the recovery. Moreover, it was found that increasing the gas injection rate improves the recovery factor (RF) of wetting-phase when the up and bottom sides of the fractures are blocked; the RF is decreased in the case with open fracture sides. The recovery of the wetting phase decreases in both FFGD and FGD modes when the porous system has a deviation from the vertical orientation. According to the study outcomes, the immiscible gas-assisted gravity drainage offers a higher condensate recovery, compared to water recovery, due to lower viscosity and interfacial tension (IFT) of the condensate phase. The comparison of the experimental data and simulation results implies that the simulation approach can satisfactorily predict the performance of the FGD process. Based on the error analysis, there is a good match between the simulation results and the experimental measurements; the fluid pair of CO2-condensate exhibits the highest accuracy with an R-squared of 0.9961 and an average relative error (ARE) of 0.0054.

Altering the wettability of a gas-liquid system from liquid-wetting to intermediate gas-wetting is a novel strategy for removing condensate from gas condensate reservoirs. In this paper, the role of a silica nanofluid modified by fluorine groups in the wettability alteration of seven carbonate samples was investigated. An acid test and Energy Dispersive X-ray Spectroscopy analysis were carried out to identify the levels of calcite and dolomite as dominant carbonate minerals and evaluate the coating ability of the proposed chemical used on carbonate surfaces. Contact angle measurements and spontaneous imbibition experiments were conducted before and after wettability alteration. In addition, gas flooding experiments were conducted on three permeable core samples to investigate the effect of the nanofluid on the fluid flow at the core scale. Contact angle measurements demonstrated that the wetting tendency of core samples altered from liquid-wetting into gas-wetting after surface treatment, and a higher contact angle was achieved for carbonate cores with less dolomite than calcite. EDX analysis showed more fluorine and silica adsorption on calcite, compared to dolomite cores. After surface modification, the brine imbibed into carbonate core samples 1 to 7 decreased by 0.104, 0.174, 0.0016, 0.773, 0.355, 0.056, and 0.279, respectively. Core flooding results demonstrated that the recovery factor of three permeable core samples increased from 56.52%, 49.69%, and 65.33%–69.34%, 56.75%, and 76.72%, respectively.