The Analysis Of Laboratory Fluid/Flow Displacement Data To Obtain Relative Permeability Curves

1988 ◽  
Author(s):  
D.W. Ruth ◽  
B. Nikakhtar ◽  
S. Wong ◽  
B.T. Mitchell ◽  
G. Mcleod
Keyword(s):  
Fluid Flow ◽  
Relative Permeability ◽  
Flow Displacement ◽  
Relative Permeability Curves

Effects of Vaporization and Temperature in Gas/Liquid Relative Permeability Experiments

1982 ◽  
Vol 22 (01) ◽  
pp. 108-116 ◽  
Author(s):  
John R. Counsil ◽  
Henry J. Ramey
Keyword(s):  
Fluid Flow ◽  
Relative Permeability ◽  
Elevated Temperatures ◽  
Gas Mixture ◽  
Relative Permeabilities ◽  
Temperature Dependent ◽  
Liquid Saturation ◽  
Mixture Volume ◽  
Relative Permeability Curves ◽  
Gas Drive

Abstract Liquid vaporization can influence the results of unsteady, external gas-drive relative permeability experiments. At elevated temperatures, liquid vaporization may affectdisplacing gas mixture volume,displacing gas mixture viscosity, andvolumetric liquid saturation calculated from a material balance. Approximate methods are presented to correct laboratory displacement data for the effect of liquid vaporization on displacing gas mixture volume and viscosity. An approximate method also is presented to evaluate the magnitude of liquid saturation reduction caused by liquid vaporization. By use of a modified Jones and Roszelle calculation procedure, equations are developed to describe the dynamic displacement of liquid water by nitrogen gas at elevated temperatures. A conventional analysis of three displacement experiments demonstrated the apparent temperature dependence of gas relative permeability. Use of the proposed method indicated that corrected gas and water relative permeability curves are not strongly temperature dependent for the artificially consolidated sandstone cores used in this study. Introduction Relative permeability curves are required for numerical modelling of multiphase fluid flow through porous media. Although natural reservoir heterogeneity often reduces the utility of laboratory-derived relative permeabilities, laboratory studies are still required to understand basic fluid flow processes. Welge first modified the Buckley-Leverett theory and presented the equations for calculating (relative) permeability ratios from linear displacement data. Johnson et al. later extended this theory, to allow the calculation of individual relative permeabilities. The base permeability was the predrive, displacing-fluid effective permeability at the initial wetting, phase saturation. Jones and Roszelle then presented a simplified graphical technique that yielded individual relative permeabilities with the absolute (brine)permeability as a base. Osoba et al., Geffen et al., Welge, Rapoport and Leas, Stewart et al., Owens et al., Corey and Rathjens. Estes and Fulton. Richardson and Perkins, Craig et al., and others demonstrated the importance of end effects, flow rate, pressure gradient, drainage imbibition hysteresis, viscosity ratio, interfacial tension, contact angle, critical scaling factor, core heterogeneity, gas slippage, and other factors. In addition, temperature-dependent permeability effects were observed by Davidson, Poston et al., Weinbrandt et al., Casse and Ramey, and others. The reasons for the temperature effects were never fully understood or explained. This paper presents a method of eliminating some of the "apparent" gas relative-permeability temperature dependence by correcting approximately for the temperature- and pressure-dependent vapor/liquid phase behavior. Experimental Process and Apparatus The calculation procedure developed in this study models an isothermal, unsteady, linear gas drive. SPEJ P. 108^

scholarly journals Variations in Permeability and Porosity of Synthetic Oil Reservoir Rock-Methods of Control

1965 ◽  
Vol 5 (04) ◽  
pp. 329-332 ◽  
Author(s):  
Larman J. Heath
Keyword(s):  
Porous Media ◽  
Relative Permeability ◽  
Reservoir Rock ◽  
Oil Reservoir ◽  
Natural Reservoir ◽  
Natural Rock ◽  
Unconsolidated Sand ◽  
Synthetic Rock ◽  
Porosity And Permeability ◽  
Relative Permeability Curves

Abstract Synthetic rock with predictable porosity and permeability bas been prepared from mixtures of sand, cement and water. Three series of mixes were investigated primarily for the relation between porosity and permeability for certain grain sizes and proportions. Synthetic rock prepared of 65 per cent large grains, 27 per cent small grains and 8 per cent Portland cement, gave measurable results ranging in porosity from 22.5 to 40 per cent and in permeability from 0.1 darcies to 6 darcies. This variation in porosity and permeability was caused by varying the amount of blending water. Drainage- cycle relative permeability characteristics of the synthetic rock were similar to those of natural reservoir rock. Introduction The fundamental behavior characteristics of fluids flowing through porous media have been described in the literature. Practical application of these flow characteristics to field conditions is too complicated except where assumptions are overly simplified. The use of dimensionally scaled models to simulate oil reservoirs has been described in the literature. These and other papers have presented the theoretical and experimental justification for model design. Others have presented elements of model construction and their operation. In most investigations the porous media have consisted of either unconsolidated sand, glass beads, broken glass or plastic-impregnated granular substances-materials in which the flow behavior is not identical to that in natural reservoir rock. The relative permeability curves for unconsolidated sands differ from those for consolidated sandstone. The effect of saturation history on relative permeability measurements A discussed by Geffen, et al. Wygal has shown quite conclusively that a process of artificial cementation can be used to render unconsolidated packs into synthetic sandstones having properties similar to those of natural rock. Many theoretical and experimental studies have been made in attempts to determine the structure and properties of unconsolidated sand, the most notable being by Naar and Wygal. Others have theorized and experimented with the fundamental characteristics of reservoir rocks. This study was conducted to determine if some general relationship could be established between the size of sand grains and the porosity and permeability in consolidated binary packs. This paper presents the results obtained by changing some of the factors which affect the porosity and permeability of synthetically prepared sandstone. In addition, drainage relative permeability curves are presented. EXPERIMENTAL PROCEDURE Mixtures of Portland cement with water and aggregate generally are designed to have certain characteristics, but essentially all are planned to be impervious to water or other liquids. Synthetic sandstone simulating oil reservoir rock, however, must be designed to have a given permeability (sometimes several darcies), a porosity which is primarily the effective porosity but quantitatively similar to natural rock, and other characteristics comparable to reservoir rock, such as wettability, pore geometry, tortuosity, etc. Unconsolidated ternary mixtures of spheres gave both a theoretically computed and an experimentally observed minimum porosity of about 25 per cent. By using a particle-distribution system, one-size particle packs had reproducible porosities in the reproducible range of 35 to 37 per cent. For model reservoir studies of the prototype system, a synthetic rock having a porosity of 25 per cent or less and a permeability of 2 darcies was required. The rock bad to be uniform and competent enough to handle. Synthetic sandstone cores mere prepared utilizing the technique developed by Wygal. Some tight variations in the procedure were incorporated. The sand was sieved through U.S. Standard sieves. SPEJ P. 329ˆ

Analytical Solutions and Derivation of Relative Permeabilities for Water-Heavy Oil Displacement and Gas-Heavy Oil Gravity Drainage Under Non-Isothermal Conditions

2016 ◽  
Vol 19 (01) ◽  
pp. 181-191 ◽  
Author(s):  
F. J. Argüelles-Vivas ◽  
T.. Babadagli
Keyword(s):  
Temperature Gradient ◽  
Relative Permeability ◽  
Heavy Oil ◽  
Variable Temperature ◽  
Spontaneous Imbibition ◽  
Analytical Models ◽  
Gravity Drainage ◽  
Positive Temperature ◽  
Relative Permeability Curves ◽  
Isothermal Gas

Summary Analytical models were developed for non-isothermal gas/heavy-oil gravity drainage and water-heavy oil displacements in round capillary tubes including the effects of a temperature gradient throughout the system. By use of the model solution for a bundle of capillaries, relative permeability curves were generated at different temperature conditions. The results showed that water/gas-heavy oil interface location, oil-drainage velocity, and production rate depend on the change of oil properties with temperature. The displacement of heavy oil by water or gas was accelerated under a positive temperature gradient, including the spontaneous imbibition of water. Relative permeability curves were greatly affected by temperature gradient and showed significant changes compared with the curves at constant temperature. Clarifications were made as to the effect of variable temperature compared with the constant (but high) temperatures throughout the bundle of capillaries.

A Machine Learning Methodology for Rock-Typing Using Relative Permeability Curves

2021 ◽  
Author(s):  
Carlos Esteban Alfonso ◽  
Frédérique Fournier ◽  
Victor Alcobia
Keyword(s):  
Machine Learning ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Fractional Flow ◽  
Flow Curves ◽  
Rock Types ◽  
Rock Typing ◽  
Relative Permeability Curves ◽  
Permeability Data

Abstract The determination of the petrophysical rock-types often lacks the inclusion of measured multiphase flow properties as the relative permeability curves. This is either the consequence of a limited number of SCAL relative permeability experiments, or due to the difficulty of linking the relative permeability characteristics to standard rock-types stemming from porosity, permeability and capillary pressure. However, as soon as the number of relative permeability curves is significant, they can be processed under the machine learning methodology stated by this paper. The process leads to an automatic definition of relative permeability based rock-types, from a precise and objective characterization of the curve shapes, which would not be achieved with a manual process. It improves the characterization of petrophysical rock-types, prior to their use in static and dynamic modeling. The machine learning approach analyzes the shapes of curves for their automatic classification. It develops a pattern recognition process combining the use of principal component analysis with a non-supervised clustering scheme. Before this, the set of relative permeability curves are pre-processed (normalization with the integration of irreducible water and residual oil saturations for the SCAL relative permeability samples from an imbibition experiment) and integrated under fractional flow curves. Fractional flow curves proved to be an effective way to unify the relative permeability of the two fluid phases, in a unique curve that characterizes the specific poral efficiency displacement of this rock sample. The methodology has been tested in a real data set from a carbonate reservoir having a significant number of relative permeability curves available for the study, in addition to capillary pressure, porosity and permeability data. The results evidenced the successful grouping of the relative permeability samples, according to their fractional flow curves, which allowed the classification of the rocks from poor to best displacement efficiency. This demonstrates the feasibility of the machine learning process for defining automatically rock-types from relative permeability data. The fractional flow rock-types were compared to rock-types obtained from capillary pressure analysis. The results indicated a lack of correspondence between the two series of rock-types, which testifies the additional information brought by the relative permeability data in a rock-typing study. Our results also expose the importance of having good quality SCAL experiments, with an accurate characterization of the saturation end-points, which are used for the normalization of the curves, and a consistent sampling for both capillary pressure and relative permeability measurements.

scholarly journals In-House Developed Kr Estimator: Implemented to Analyze the Sensitivity of Relative Permeability Data to Variations in Wetting Phase Saturation

2011 ◽  
Vol 29 (6) ◽  
pp. 817-825 ◽  
Author(s):  
Muhammad Khurram Zahoor
Keyword(s):  
Porous Medium ◽  
Pore Size Distribution ◽  
Pore Size ◽  
Relative Permeability ◽  
State Of The Art ◽  
Data Generation ◽  
Phase Saturation ◽  
Complex Models ◽  
Relative Permeability Curves ◽  
Very High

Reservoir surveillance always requires fast, unproblematic access and solution to different relative permeability models which have been developed from time to time. In addition, complex models sometimes require in-depth knowledge of mathematics for solution prior to use them for data generation. For this purpose, in-house software has been designed to generate rigorous relative permeability curves, with a provision to include users own relative permeability models, a part from built-in various relative permeability correlations. The developed software with state-of-the-art algorithms has been used to analyze the effect of variations in residual and maximum wetting phase saturation on relative permeability curves for a porous medium having very high non-uniformity in pore size distribution. To further increase the spectrum of the study, two relative permeability models, i.e., Pirson's correlation and Brooks and Corey model has been used and the obtained results show that the later model is more sensitive to such variations.

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