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Asphaltene deposition in porous media has a destructive effect on well productivity during primary and secondary oil recovery. Previous research studies have presented models for permeability reduction due to particle deposition in porous media. In this study, a semi-experimental model was modified and a new model was introduced to predict permeability changes due to asphaltene retention in early times of precipitation. The modified model unlike common models considers the size of asphaltene particles, porous media grain size, fluid flow properties and precipitation in pore throat. A set of experiments are done to obtain the parameters needed for modeling and check the validity of model. Crude oil is used as fluid sample and a sand pack filled with glass beads is used as an artificial porous media in flood tests. To identify the size of asphaltene particles, microscopic technique is used. The results of experiments are used to investigate asphaltene deposition in porous media and evaluate model prediction. A new procedure based on the modified model is applied to obtain model parameters and simplify the calculations. The new model can eliminate the deficiencies in previous models for prediction of asphaltene deposition in early stages of particle retention. The model also is validated by experimental results that were reported in the literature before. The results show rational accommodation with experimental data. • Classifying models of permeability damage due to asphaltene deposition and explaining the necessity of proposing a new model. • Modifying a new model to predict the permeability reduction of porous media due to asphaltene damage. • Investigating and evaluating model prediction using experimental data. • Investigating the role of blocking function by appling three different blocking functions in proposed model. • Comparing model prediction with previous experimental results that were reported in the literature before. [ABSTRACT FROM AUTHOR]

Successful implementation of nanofluid-assisted enhanced oil recovery (EOR) operation mainly depends on proper determination of the main factors that control both transport and retention of nano-sized particles in porous media. In this study, a new transport scheme using the kinetic Langmuir model was first developed and validated by some experimental data from the literature. This model was then used to investigate the effect of reservoir rock type, clay content, grain size, brine type, and reservoir temperature on distribution of nanoparticles on the rock surface and in the injected fluid in relation to EOR methods. Moreover, a two-phase approach was derived to simulate the effect of these parameters on both wettability alteration and mobility control. Results confirmed that the deposition tendency of silica nanoparticles on limestone is higher than that on sandstone. By increasing clay content, both surface area and deposition sites increases and consequently more nanoparticles were found to retain. In the case of polyethylene glycol (PEG) stabilized silica nanoparticles, the amount of oil recovery increased by increasing the salinity of brine. Increasing the salinity of brine resulted in considerable deposition of silica nanoparticles on the rock surface and made them more water wet. These phenomena eventually increased the final recovery factor from 62% to 79%. Since the temperature simultaneously affects the deposition and detachment kinetics of nanoparticles and the reservoir fluid properties, its effect on oil recovery in nanoassisted-EOR technique cannot be generalized. • A new mathematical scheme was developed for NP transport using the kinetic Langmuir model. • Transport and retention of nanoparticles determine the performance of EOR processes. • Temperature, salinity and rock properties affect the amount of NPs deposition on rock surface. • The degree of wettability alteration is related to the concentration of NPs on the rock surface. [ABSTRACT FROM AUTHOR]