فهرست مطالب hessam aloki bakhtiari

The simultaneous flow of oil and water in porous media is described by relative permeability curves, mainly derived from laboratory experiments. Relative permeability is of paramount importance in predicting reservoir production performance and drive mechanisms and its value depends largely on the volume fraction of fluids present in the test samples. Nowadays X-ray scanners are one of the most accurate tools for non-destructive measurement of in-situ saturation. The mail purpose of this paper is to describe two-phase immiscible fluid flow behavior of low viscosity ratio oil/water through water-wet porous media interpreted by in-situ saturation profile data. Both steady state (SS) and unsteady state (USS) relative permeability measurement methods were applied and compared. The measured in-situ saturation profiles can confirm wettability character of studied rock samples and the yielded data are in good qualitative agreement with wettability characteristics of water-wet reservoir cores. In the USS experiments the saturation profile shapes characterize mainly production of oil before breakthrough and display front position. The flooding-rate dependency of the USS experiments was observed. In the SS experiments by imbibition process, water saturation in the samples was increased significantly even with flow of a very small fraction of water at the beginning of the test

In this paper, the role of molecular diffusion in mobilization of waterflood residual oil is examined. A moving mesh method is applied to solve the moving interface problem of residual oil blobs swelling by Co2 diffusion through a blocking water phase. The results of this modeling are compared with experimental results of a 2D glass micromodel experiment. Although, the solution method is applied for a 1D system, a good agreement between numerical and experimental results validates the solution method. In this method a fixed time step is proposed. Furthermore, the results of this method have been compared with the results of the Grogan’s finite difference method. This supposed that, the mesh network is fixed and time step increasing will be continued until the oil-swelling equal to one spatial step size.

Pore volume compressibility, which is the reverse of bulk modulus, is one of the most important and effective parameters of mechanical, seismic and reservoir properties of hydrocarbon reservoirs. The investigation of elastic modulus is essential for using geophysical data in reservoir production and EOR. In order to determine the pore compressibility of Asmari carbonate reservoir rocks, a total of 90 samples from different types of carbonate rocks were selected from oil reservoir for this study. Petrographical analyses were conducted to determine the effect of textures; type and value of porosity on pore compressibility, and then the effect of net confining pressure and pore compressibility on the Archie cementation coefficient was studied. To achieve this purpose, after geological examinations and grouping the samples based on type of textures and pores, the relationships between cementation coefficient and pore compressibility were calculated. Pore compressibility experiments as well as the determination of the cementation factor were performed using the “Overburden FRF Rig” apparatus. Hydrostatic pressure up to 10000 psi may be applied to samples via this apparatus. The sample that is fully reservoir brine saturated is located in a rubber sleeve of hydrostatic core holder and surrounded by two rings. After purging the system, the confining pressure was increased from 435 psi up to 4000 psi. The increase of pressure on rocks causes pore compaction and expels the fluid from the sample. The volume of fluid expelled from the samples shows the volume of pore volume reduction due to the increase of pressure. Pore compressibility was determined by derivation of each pressure point by plotting the logarithm of variation of pore volume reduction vs. effective confining pressure. In order to study pore compressibility under hydrostatic pressure, five steps of increasing the net pressure, which were 435, 1000, 2000, 3000 and 4000 psi, were selected. Pore compressibility is a function of porosity and it increases as porosity decreases. The power function, expressed as Cp = a(P)b, usually shows the best fit for the compressibility and net pressure relationship. The results of this study show that for almost all of the selected samples, the cementation factor increases when the pressure is increased. The compaction of rocks causes changes in the structure of the pores and grain shapes, and reduces the pore volumes. In a few of the samples, increasing the pressure caused a reduction in the cementation factor. The main reason for this reduction could be due to damage to the structure of the rocks. Two main differences were observed between the changes in compressibility and cementation factor: (1) by increasing compressibility, the reduction of the cementation factor is accelerated in samples with a higher cementation factor and (2) changes of pore compressibility are higher for samples with a lower cementation factor. Isolated porosity and separated vug porosity are closed by a slight increase of pressure in comparison with connected porosity, and therefore reduction in cementation factor is correlated with low pore compressibility. An increase of dolomitization in the samples from packestone to dolopackestone and dolostone causes better connections among pores and the effect of pore compressibility is more pronounced. A summary of results is as follows: 1) The slope of curve increased in a cross plot of the measures of cementation coefficient vs. compressibility due to a change in texture from packestone to dolopackstone and dolostone. 2) Increasing the net confining pressure increases cementation factor. 3) Variation of pore compressibility is higher in the samples with lower a cementation factor. 4) The cementation factor is reduced by an increase of pore compressibility, and reduction of cementation factor occurred faster in the samples with a higher cementation factor. 5) In the investigated formation, the value of pore compressibility is dependent on the texture, type and value of porosity. 6) Pore compressibility is higher in sandy dolostone with porosity measuring less than 15 percent compared to other carbonate textures, and it decreases with change in texture from sandy dolostone to mudstone. A power function in the form of Cp = a(P)b usually shows the best fit for compressibility and the net confining pressure relationship.