Permeability Of Oil Phase Research Articles

The mobilization mechanism of low oil saturation reservoirs

After fracturing with a guar fluid system in Chang 8 oil reservoir, some wells have high oil production, and some have low production and even only produce water. Therefore, a comparative study is carried out in oil-producing and water-producing wells. The results show that: ① Organic wax adsorbed in oil-producing and water-producing well core pores accounts for 95.39% and 56.67%, respectively, making wells strong oil-wet. A certain proportion of inorganic salts and some other oil-wet organic compounds exist in water-producing wells. ② Under the reservoir conditions, the oil wettability of the water-producing well core is strong, and its original formation wettability is also oil-wet. The original wettability of the oil-producing well formation is water-wet, with oil production capacity. ③ The core residual oil saturation using the guar fluid is 24.7%–29.87%. This results in no oil phase permeability or difficulty to mobilize oil in most oil reservoirs. ④ Forced displacement can mobilize oil in large pores and has a significant effect in producing well, with mobilization efficiency of 53.49%. This article elucidates the wettability formation and crude oil mobilization mechanism of two types of wells, providing direction for the development of this type of reservoir.

Modeling of oil phase displacement processes in heterogeneous anisotropic reservoirs

Methods of computer modeling of slightly permeable anisotropic oil-bearing layers are needed nowadays because they give us a possibility to obtain a concept on filtration processes near producing and forcing wells in different practical situations and in this way to raise the level of exploitation of such layers significantly. On the other hand, they allow evaluation and taking into account some uncertainties which appear as a result of inefficient information on the structure and properties of the layer outside the wells. In order to investigate the practical aspects of supporting efficiency of oil production in anisotropic heterogeneous low permeable reservoirs on the base of combined finite-element-difference method for solving the non-stationary anisotropic piezoconductivity problem, modeling of distribution of layer pressure was carried out in the vicinity of the production and forcing wells taking into account the anisotropy of the permeability and conditions of the oil phase infiltration on the margins of the examined layer. It has been found that the intensity of filtration process between producing and forcing wells depends essentially on their spacing in both shear-isotropic and anisotropic oil-bearing layers. In addition the effect of oil phase permeability in shear direction dominates over the effect of permeability in axes directions. Starting from the obtained information for the effective exploitation of anisotropic slightly permeable layers we need to locate producing and forcing wells in the areas with relatively low permeability of the layer and especially to avoid the places with presence of shear permeability. It is important to locate the wells in such a way that blocking the oil in the direction of reduced permeability and fast depletion of the layer in the direction of increased permeability would not happen as well as mutual exchange between producing and forcing wells would not stop. While locating the system of specified wells within anisotropic layers of oil deposit it is necessary to conduct a systemic analysis of environmental anisotropy of layers aimed at such a location of these wells which would guarantee the effective dynamics of filtration processes around them. Application of quadratic isoparametric approximation of finite-elemental net of examined area of oil-bearing layer and implicit differential time approximation brings to increase of precision and stability of numerical solution of the problem.

Investigation into the effect of polymer microspheres (PMs) on oil-water relative permeability and oil-in-water emulsion stability for enhanced oil recovery

A new gel particle named pore-scale polymer microspheres (PMs) has been considered as an effective chemical enhanced oil recovery (EOR) agent used for conformance control. But how to achieve deep profile control of PMs remains some problems. This work aimed at investigating the effect of PMs on oil-water relative permeability and oil-in-water emulsion stability. The results indicated that as PMs diameter matched well with pore-throats size, the PMs could exhibit a superior dynamic migration and plugging performance in the core; in this scenario, in the course of PMs flooding and subsequent water flooding, water phase permeability fluctuated obviously, and oil phase permeability increased and then decreased. Additionally, it was observed that the PMs could reduce the negative influence of elevated mobility ratio caused by the increment in oil viscosity to promote oil seepage. The zeta potential results indicated that the PMs facilitated enhancing oil-in-water emulsion stability, predominantly as a result of the increase of electrostatic repulsion between oil droplets, and deceleration of floating and convergence of oil droplets.

Laboratory Studies of High-Temperature-Compound Steam Drive on Heavy Oil

This paper presents experimental work on the research of the mechanism of oil displacement of steam drive and high-temperature-compound steam drive, which in order to improve the conventional steam drive technology and increase the recovery of heavy oil. Many experiments were done with the sand-packed model under the formation condition. The results show that: (a) the high-temperature-compound steam drive could extend the water breakthrough time, increase the permeability of oil phase, reduce the residual oil saturation; (b) reducing the viscosity by CO2 dissolution, maintaining the pressure, improving the oil flow ratio, dissolved gas drive，Improving oil displacement efficiency，all of above were the increase production mechanism of high- temperature-compound steam drive.

Prediction of Relative Permeability Characteristics Of Intergranular Reservoir Rocks from Electrical Resistivity Measurements

Abstract More than a decade ago some theoretically derived relationships were proposed that permitted the prediction of the relative ability of reservoir fluids (oil, gas, water) to flow simultaneously within the porous structure of rocks. While many successful predictions of fluid-flow ratios from wells have been made from electric logs, the theoretical deductions have not been subjected to laboratory verifications. For the relative permeability to liquid and gas, simultaneous flow of water and air was used, employing the familiar external-gas-drive technique. While in the process of water desaturation, the resistivities of the test cores (Woodbine sand) were measured. Their permeabilities varied from 10 to 280 md. The laboratory results indicated the need for changing the values of exponents in the theoretically derived formulas, whereas the form of the functions of resistivities and saturations remained as derived by theory. For the relative permeability to oil and water, the three-core dynamic technique was used on six cores. In this case it was found that the formulas were valid with but slight modification as derived by theory, to a sufficient degree of accuracy for engineering use and for well productivity prediction from electric logs. Introduction Conventional quantitative well log interpretation generally stops after reasonable values for formation porosities and water saturations have been established. Yet such information is insufficient to predict either the outcome or the desirability of well tests and completion, let alone the economic aspect of producing oil- and gas-bearing sections which might have been established by conventional log analysis. To give an engineering answer to such questions, it is necessary to predict the expected fluid flow ratios, the productivity index and the ultimate recovery from potentially productive wells. This problem requires in part for its solution a determination of the relative permeability characteristics of the potentially producing formations, both to oil (or water) and gas, and to oil and water. GAS LIQUID RELATIVE PERMEABILITIES Few methods for determining or calculating relative permeability values, other than from flow tests on reservoir cores, have been proposed. Corey proposed a method of calculation derived from capillary pressure concepts, using the observation that for certain cases, 1/pc is approximately a linear function of the effective saturation. The Corey equations are ........................(1) ..........(2) These equations check out very well in the laboratory and are accurate for somewhat more than the limited range of conditions they were derived for. This is due to the smoothing effect of the derivation method. Corey measured the gas permeability and calculated from this the value of So* and the oil phase permeability. Corey's formulas, however, were derived for the drainage process only. Torcaso and Wyllie modified Corey's equations and used them to define a kg/ko ratio: (3) For low values of irreducible water saturation (i.e., for relatively permeable and porous rocks), the curve agrees closely with field correlation. From petrophysical considerations, Pirson derived equations for the wetting and non-wetting phase relative permeabilities for both imbibition and drainage processes. These equations are: (4) (5) (6) JPT P. 564ˆ