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A nanometer (10-9m) structured particle material, generally so defined that the diameter of the particle is no more than 100nm, has some special physical efficacy in its surface, small size and other properties. One kind of polysilicon with sizes ranging from 10~500nm, and considered as nanometer or sub nanometer sized powder, was used in oilfields to enhance water injection by changing wettability of porous media. The mechanism of enhancing water injection is through improving relative permeability of the water-phase by changing wettability induced by adsorption of polysilicon on the porous surface of sandstone. On the other hand, the adsorption on the porous surface and plugging at the small pore throats of the polysilicon may lead to reduction in porosity and absolute permeability (K) of porous media for pore sizes from 100 to 1000,000nm. Thus the degree of success in well treatment is determined by the improvement of effective permeability of the water-phase. In this paper a mathematical model, which was combined with the study of experiments in the laboratory, is presented and a simulator is developed to simulate water injection dynamics under the conditions of polysilicon injection. The simulator can accurately simulate the process of migration and adsorption in the pore bodies and blocking at the pore throat of the polysilicon in the sandstone. A series of numerical simulation runs was conducted to study the effect of a wide range of parameters, such as the sandstone with different permeabilities, concentration of the polysilicon, injection volumes, and others. The effective permeabilities of the water-phase measured by a number of core flooding experiments are matched well by the numerical results. Since April 2000, nine well treatments with solvent slugs of suspended polysilicon particles in several oilfields in China was shown to be successful and the average injection rate increased 5 times after treatments. Introduction A nanometer particle, generally defined as its size from 1 to 100nm and invisible with the naked eyes or ordinary microscope, is referred to as a nanometer scaled ultra fine particle in its size which is larger than an atom cluster and smaller than ordinary micro-powder. Nanometer technology originated at the end of the 1980's and is developed into a new high technology, by which new materials can be formed by rearranging atoms or molecules. A nanometer structured particle material has some special physical effects in its surface, small size, quantum size and macro-quantum tunnel1. Nanometer particle material has a large specific surface area, which increases rapidly with the decrease in diameter of particle. The large surface area leads to an increase in the proportion of atoms on the surface of the particle, which results in an increase in surface energy. The deficiency of atomic coordination and high surface energy leads to the unsteady, high activity of atoms on the particle, the increase in tendency of combination with other atoms, and the appearance of active cores. Non-chemical equilibrium and coordination of non-integer numbers lead to considerable difference in chemical properties and chemical equilibrium systems for nanometer powder. Analogously, sand rock, which is composed of grains with different sizes, is porous media deposited under the combination of consolidation and compaction throughout a long geological period, and also has large specific surface area. Since the property of the surface of minerals determines the wettablity of porous walls, and the wettability of reservoir rock governs, to a great extent, the location, flow, and distribution of oil, water, and gas in a reservoir, the distributive characteristics, relative permeability of water and oil and flow dynamics of fluids in porous media can be changed by modifying the wettability of porous walls. Accordingly, the process of development of a reservoir can be improved by wettability modification.

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractA nanometer (10 -9 m) structured particle material, generally so defined that the diameter of the particle is no more than 100nm, has some special physical efficacy in its surface, small size and other properties. One kind of polysilicon with sizes ranging from 10~500nm, and considered as nanometer or sub nanometer sized powder, was used in oilfields to enhance water injection by changing wettability of porous media. The mechanism of enhancing water injection is through improving relative permeability of the water-phase by changing wettability induced by adsorption of polysilicon on the porous surface of sandstone. On the other hand, the adsorption on the porous surface and plugging at the small pore throats of the polysilicon may lead to reduction in porosity and absolute permeability (K) of porous media for pore sizes from 100 to 1000,000nm. Thus the degree of success in well treatment is determined by the improvement of effective permeability of the water-phase.In this paper a mathematical model, which was combined with the study of experiments in the laboratory, is presented and a simulator is developed to simulate water injection dynamics under the conditions of polysilicon injection. The simulator can accurately simulate the process of migration and adsorption in the pore bodies and blocking at the pore throat of the polysilicon in the sandstone. A series of numerical simulation runs was conducted to study the effect of a wide range of parameters, such as the sandstone with different permeabilities, concentration of the polysilicon, injection volumes, and others. The effective permeabilities of the waterphase measured by a number of core flooding experiments are matched well by the numerical results. Since April 2000, nine well treatments with solvent slugs of suspended polysilicon particles in several oilfields in China was shown to be successful and the average injection rate increased 5 times after treatments. chemical properties and chemical equilibrium systems for nanometer powder.Analogously, sand rock, which is composed of grains with different sizes, is porous media deposited under the combination of consolidation and compaction throughout a long geological period, and also has large specific surface area. Since the property of the surface of minerals determines the wettablity of porous walls, and the wettability of reservoir rock governs, to a great extent, the location, flow, and distribution of oil, water, and gas in a reservoir, the distributive characteristics, relative permeability of water and oil and flow dynamics of fluids in porous media can be changed by modifying the wettability of porous walls. Accordingly, the process of development of a reservoir can be improved by wettability modification.

Carbon dioxide (CO2) flooding is an efficacious method of EOR and it is a very complicated process, involving phase behavior. To master the performance of CO2 flooding and provide accurate data for designing oil development, a comprehensive investigation of CO2 flooding phase behavior and mechanism based on laboratory study was conducted. In order to get representative fluid samples of a reservoir, it was necessary that the right operation of mixing the separator oil and gas samples to match the bubble point pressure be carried out. The result from PVT experiments shows that for a certain reservoir, through a slight manipulation of the measured PVT properties including bubble point pressure, volume factor, swelling factor, solubility of CO2 and viscosity, it is possible to obtain regression curves, which can be used to estimated the PVT behavior for any hydrocarbon fluid-CO2 mixture of this reservoir. The result of slim tubule tests indicates that it is more appropriate to determine the minimum miscibility pressure of the reservoir fluid-CO2 mixture by the position of inflexion on the curve of oil recovery with flooding pressure than by reaching a special oil recovery point. Introduction Carbon dioxide flooding is an effective enhanced oil recovery process. It appeared in 1930's and had a great development in 1970's. Over 30 years' production practice, CO2 flooding has become the leading enhanced oil recovery technique for light and medium oils1–4. It can prolong the production lives of light or medium oil fields nearing depletion under waterflood by 15 to 20 years, and may recover 15% to 25% of the original oil in place1. CO2 flooding process involves very complicated phase behavior, which depends on the temperature, pressure and fluids properties of a certain reservoir. Many factors have been found contributing to the oil recovery in CO2 flooding. These mainly include5–11:low interface tensions;viscosity reduction;oil swelling;formation permeability improvement;solution gas flooding;density change of oil and water. R.K Srivastava et al6 took a laboratory study of Weyburn CO2 miscible flooding. From the PVT data generated from the three Weyburn reservoir fluid-CO2 mixtures it was showed that viscosity reduction and oil swelling by CO2 contributed to oil recovery. The viscosity showed an almost linear decrease with CO2 concentration. A slight manipulation of the measured PVT properties of the mixtures made it possible to obtain single property curves for the three Weyburn oils. This feature can be used to estimate the PVT behaviour for any Weyburn oil from the reservoir.

Fines release and migration is a universal problem in the production of oil from poorly consolidated sandstone reservoirs. This problem can result in the changes of porosity and permeability. It may not only damage a production facility, but it can also have a profound effect on oil recovery, resulting from the change in heterogeneity of the oil formation. Based on the macroscopic continuous porous media, continuity equations for multiphase flow in oil formations, and the theories of fines release and migration, a three-dimensional (3D) field scale mathematical model describing migration of fines in porous media is developed. The model is solved by a finite-difference method and the line successive over relaxation (LSOR) technique. A numerical simulator is written in Fortran 90 and it can be used to predict (1) the ratio of fines to production liquid volume, (2) the permeability change caused by colloidal and hydrodynamic forces resulting from fines release and migration, and (3) production performance. The numerical results of the one-dimensional model were verified by the data obtained by core displacement experiments. The sensitivity of numerical results with grid block size was studied by coarse grids, moderate grids, and fine grids. In addition, an oil field example with five-spot patterns was made on the numerical simulator. The results show that fines migration in an oil formation can accelerate the development of heterogeneity of the reservoir rock, and has an obvious influence on production performance, i.e., water drive front, water-cut trends, and oil recovery. 266 Binshan Ju et al. Nomenclature B Volume factor of fluid C lij Volume concentration of composition j of particles in {the} phase l. C si Mass concentration of salt ions for composition i (kg/m 3 ) D Diffusivity of particle composition i (m 2 /s) D s Diffusivity of salt, ions, (m 2 /s) fFlow efficiency factor k Transient absolute permeability of a porous media (m 2 ) k r Relative permeability of a porous media p Pressure (Pa) q Production/injection rate (m 3 /s) R Net particle change rate on the pore surfaces or at pore throats (1/s) R s Solution gas-oil ratioDistance from reference level (m) α c Release rate of fines by colloidal forces (s −1 ) α d Rate constant for the deposition of particles on pore surfaces (m −1 ) α f Coefficient of flow efficiency α h Release rate of fines by hydrodynamic forces (m −1 ) α p Capture rate constant of particles at pore throats (m −1 ) δ lij Volume of particles deposited on the pore surfaces per unit bulk volume φ Porosity of the porous media δ * lij

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