Smart water flooding as a developing technique utilizes modified water chemistry in terms of salinity and composition to prepare the best-suited brine composition for a specific brine/oil/rock system to obtain higher oil recovery efficiency. Huge amount of unrecovered oil is expected to be remained in carbonate reservoirs; however, few research works on incremental oil recovery during smart water injection in carbonate cores at reservoir condition are reported. Several core flooding tests using one of the Iranian carbonate reservoir rock are conducted to check the effectiveness of smart water injection for more oil recovery efficiency. The results reaffirm the positive effect of sulfate ions to play a key role for better smart water performance. Moreover, it was concluded that the calcium ion concentration is not as effective as magnesium ion for the tests performed at reservoir condition. Synthetic sea water (high-salinity) flooding was considered as the base scenario which results in almost 63% oil recovery efficiency for secondary recovery scenario. Formation of micro-emulsions was found to be the main reason of additional pressure drop during low-salinity water flooding. This clearly showed that the diluted smart water injecting increases the ultimate oil recovery up to 4-12% for already water-flooded carbonate reservoirs.
Microbial enhanced oil recovery (MEOR) is a useful technique to improve oil recovery from depleted oil reservoirs beyond primary and secondary recovery operations using bacteria and their metabolites. In the present study, the biosurfactant production potential of Bacillus licheniformis microorganisms that were isolated from oil samples of Zilaei reservoir in the southwest of Iran was explored under extreme conditions. Growth media with different temperatures of 40, 50, 60, and 70°C; salinities of 1, 3, 5, and 7 wt%; and yeast extract concentrations of 0.5, 1, 1.5, and 2 g/L were used to find the optimum growth conditions. The results demonstrated that bacteria grown in a mineral salt solution with temperature of 50°C, salinity of 1 wt% and yeast extract concentration of 1 g/L has the highest growth rate and therefore, these conditions are the optimum conditions for growing the introduced bacterium. This isolate was selected as the higher biosurfactant producer. The obtained biosurfactants by bacteria isolated in a medium with these conditions could reduce the interfacial tension of crude oil/water system from 36.8 to 0.93 mN/m and surface tension of water from 72 to 23.8 mN/m. The results of the core flooding tests showed that the tertiary oil recovery efficiency due to the injection of microorganisms was 13.7% of original oil in place and bacteria could reduce the oil viscosity by 41.242% at optimum conditions. Based on these results, the isolated microorganism is a promising candidate for the development of microbial oil recovery processes.
Summary Free-fall gravity drainage (FFGD) is the main production mechanism in the gas-invaded zone of fractured reservoirs. The gravity and capillary forces are two major forces that control the production performance of a fractured system under an FFGD mechanism. Gravity force acts as a driving force to remove oil from the matrix block whereas the resistive capillary force tends to keep oil inside the matrix. In this study, a series of experiments was performed to study the effects of the geometrical characteristics of the fracture and matrix on the oil-production rate under an FFGD mechanism by use of a glass micromodel. The oil-recovery factor (RF) was also obtained for a single matrix block by use of different patterns. Results from the experiments show that different flow regimes occur during the production life of a single matrix block under a FFGD mechanism. The fluid flow is controlled by the capillary-dominated regime at the early stage and late time of production life, whereas it shows a stabilized bulk flow under a gravity-dominated regime is exhibited at other times. Experimental results revealed that for a narrow fracture opening, fracture capillary pressure has a form similar to that of the matrix block. Also, it was observed that the oil-production rate and RF of the matrix block decreased as the permeability ratio between two media (matrix block and fracture) increased. Lower production rate is achieved in larger-fracture-spacing micromodels. In addition, wider vertical fractures lead to an early breakthrough of gas in bottom horizontal fracture that makes up the main portion of oil traps in the matrix block, and this reduces the RF. Results from this study show that in a heterogeneous layered matrix block, both the drainage rate and RF decrease in comparison with a homogeneous matrix block. Finally, a multiple linear-regression analysis was performed to understand the dimensionless groups affecting the RF of the FFGD process. It was found that the Bond number cannot truly describe the process and other parameters such as the fracture-/matrix-permeability ratio; fracture spacing and fracture opening should also be considered.
The Brooks-Corey power-law capillary pressure model is commonly imposed on core analysis data without verifying the validity of its underlying assumptions. The Brooks-Corey model, originally developed to model the pressure head during the drainage of soil, is only valid at low wetting phase saturations. However, such models are often applied in petroleum production simulations and may lead to erroneous recovery factors when the saturation range of interest is far from the end points. We demonstrate that exponential models work much better for capillary pressure compared to the Brooks-Corey model over a wide saturation range. Mercury injection porosimetry, petrographic image analysis, and magnetic resonance studies suggest that the pore and throat size distribution in many rocks are log-normally distributed. This fact was previously employed to calculate the capillary pressure function as a function of saturation for pore size distributions described by atruncated log-normal distribution. Employing a Taylor series expansion, we simplify the random fractal capillary pressure model of Hunt to Pc = exp(a − bS), where S is the wetting phase saturation, and a and b characteristic of the porous medium. An extensive dataset of seventeen centrifuge capillary pressure measurements were used in this research to demonstrate the merit of the new method. For both sandstones and carbonates, the logarithm of capillary pressure showed a linear relationship with saturation as observed by magnetic resonance imaging centrifuge capillary pressure measurements over a wide saturation range. This work demonstrates that: (a) in semi-log plots of capillary pressure as a function of saturation, capillary pressurewill vary linearly over a wide saturation range, (b) such a plot as described in (a) will show the uni-or bimodal pore size distribution of the rock, (c) the exponential capillary pressure function simplifies analytical modelsthat use the capillary pressure function, for example oil recovery models for fractured reservoirs.
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