Optimization of the Numerical Simulation in a Giant Oil Field by Upscaling of Relative Permeability Curves

1995 ◽  
Author(s):  
Stefano Giliberti ◽  
Mario Erba ◽  
Maurizio Rampoldi ◽  
Ali Said
Keyword(s):  
Numerical Simulation ◽  
Relative Permeability ◽  
Oil Field ◽  
Relative Permeability Curves

An Inversion Method of Relative Permeability Curves in Polymer Flooding Considering Physical Properties of Polymer

SPE Journal ◽  
2018 ◽  
Vol 23 (05) ◽  
pp. 1929-1943 ◽  
Author(s):  
Yongge Liu ◽  
Jian Hou ◽  
Lingling Liu ◽  
Kang Zhou ◽  
Yanhui Zhang ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Simulation Model ◽  
Relative Permeability ◽  
Polymer Flooding ◽  
Inversion Method ◽  
Residual Resistance ◽  
Relative Permeability Curve ◽  
Nonsteady State ◽  
State Method ◽  
Relative Permeability Curves

Summary Reliable relative permeability curves of polymer flooding are of great importance to the history matching, production prediction, and design of the injection and production plan. Currently, the relative permeability curves of polymer flooding are obtained mainly by the steady-state, nonsteady-state, and pore-network methods. However, the steady-state method is extremely time-consuming and sometimes produces huge errors, while the nonsteady-state method suffers from its excessive assumptions and is incapable of capturing the effects of diffusion and adsorption. As for the pore-network method, its scale is very small, which leads to great size differences with the real core sample or the field. In this paper, an inversion method of relative permeability curves in polymer flooding is proposed by combining the polymer-flooding numerical-simulation model and the Levenberg-Marquardt (LM) algorithm. Because the polymer-flooding numerical-simulation model by far offers the most-complete characterization of the flowing mechanisms of polymer, the proposed method is able to capture the effects of polymer viscosity, residual resistance, diffusion, and adsorption on the relative permeability. The inversion method was then validated and applied to calculate the relative permeability curve from the experimental data of polymer flooding. Finally, the effects of the influencing factors on the inversion error were analyzed, through which the inversion-error-prediction model of the relative permeability curve was built by means of multivariable nonlinear regression. The results show that the water relative permeability in polymer flooding is still far less than that in waterflooding, although the residual resistance of the polymer has been considered in the numerical-simulation model. Moreover, the accuracy of the polymer parameters has great effect on that of the inversed relative permeability curve, and errors do occur in the inversed water relative permeability curve—the measurements of the polymer solution viscosity, residual resistance factor, inaccessible pore-volume (PV) fraction, or maximum adsorption concentration have errors.

scholarly journals EVALUATION OF CAPILLARY END EFFECT IN WATER-OIL PERMEABILITY TESTS USING MULTIPLE FLOW RATES TECHNIQUE

2021 ◽  
Vol 14 (04) ◽  
pp. 259-267
Author(s):  
I. C. A. B. A. Santos ◽  
F. M. Eler ◽  
D. S. S. Nunes ◽  
P. Couto
Keyword(s):  
Relative Permeability ◽  
Flow Rate ◽  
Optimization Problem ◽  
Oil Field ◽  
End Effect ◽  
Flow Rates ◽  
Experimental Procedure ◽  
Injection Methods ◽  
Relative Permeability Curves ◽  
Capillary End Effect

Relative permeability curves obtained in laboratory are used in reservoir simulators to predict production and establish the best strategies for an oil field. Therefore, researchers study several procedures to obtain relative permeability curves. Among these procedures are the multiple flow rates injection methods. Thus, this work proposes to develop an experimental procedure with multiple increasing flows. To make this feasible, simulations were initially carried out at CYDAR, aiming to establish flow rates and time necessary to achieve system stabilization, within the limits of the equipment. After that, tests were carried out establishing the minimum time of 5 hours to stabilize the oil production, and the differential pressure at each flow rate. The accounting and minimization of the capillary end effect in these tests were also evaluated. Capillary pressure constraints contributed to minimize the number of possible solutions to the optimization problem improving the fit of solutions for a specific case.

Numerical Investigation of the Effects of Core Heterogeneities on Waterflood Relative Permeabilities

1970 ◽  
Vol 10 (04) ◽  
pp. 381-392 ◽  
Author(s):  
John D. Huppler
Keyword(s):  
Numerical Simulation ◽  
Porous Medium ◽  
Pressure Drop ◽  
Difference Equation ◽  
Relative Permeability ◽  
Phase Difference ◽  
Two Dimensional ◽  
Relative Permeabilities ◽  
Two Phase ◽  
Relative Permeability Curves

Abstract Numerical simulation techniques were used to investigate the effects of common core heterogeneities upon apparent waterflood relative-permeability results. Effects of parallel and series stratification, distributed high and low permeability lenses, and vugs were considered. permeability lenses, and vugs were considered. Well distributed heterogeneities have little effect on waterflood results, but as the heterogeneities become channel-like, their influence on flooding behavior becomes pronounced. Waterflooding tests at different injection rates are suggested as the best means of assessing whether heterogeneities are important. Techniques for testing stratified or lensed cores are recommended. Introduction Since best results from waterflood tests performed on core plugs are obtained with homogeneous cores, plugs selected for testing are chosen for their plugs selected for testing are chosen for their apparent uniformity. We know, however, that uniform appearance can be misleading. For example, flushing concentrated hydrochloric acid through an apparently homogeneous core plug often produces "wormholes" in higher permeability regions. Also, we sometimes find that all core plugs from a region of interest have obvious heterogeneities, so any flooding tests must be run on nonhomogeneous core plugs. plugs. Nevertheless, relative permeabilities, as obtained routinely from core waterflood data, are calculated using the assumption that the core is a homogeneous porous medium. While it is obvious that porous medium. While it is obvious that heterogeneties mill affect these apparent relative permeabilities, there appear to be no experimental permeabilities, there appear to be no experimental results reported in the literature to indicate just how serious the problem is. Accordingly, a computer simulation study of core waterfloods was conducted to systematically examine the effects of different sizes and types of core heterogeneities on flood results. The study was performed by numerical simulation using two-dimensional, two-phase difference equation approximations to describe the immiscible water-oil displacement. For each simulation the permeability and porosity distribution of the heterogeneous core to be studied was specified; fluid flow characteristics of the system, including a single set of input relative-permeabilities curves, were stipulated The system was set in capillary pressure equilibrium at the reducible water saturation. Then a waterflood simulation was performed. From the resulting fluid production and pressure-drop data a set of production and pressure-drop data a set of relative-permeability curves was calculated using the standard computational procedure applicable to homogeneous cores. In this paper these calculated relative-permeability curves are denoted as "waterflood" curves to distinguish them from the specified input curves. The waterflood relative-permeability curves should closely match the input curves for homogeneous systems. Since the same set of input relative-permeability curves was used for all rock sections, deviations of the waterflood from the input relative-permeability curves gave an indication of the effects of heterogeneities. When the system was heterogeneous and there was good agreement between waterflood and input relative-permeability curves, then the heterogeneities did not strongly influence the flow behavior and the system responded homogeneously. MATHEMATICAL MODEL AND METHOD The waterflood simulations were carried out using two-dimensional, two-phase difference equation approximations to the incompressible-flow differential equations:* .....................(1) ....................(2) SPEJ P. 381

scholarly journals Evaluation of Relative Permeability Tests One-Step with Bump Flow and Multi-Step

2021 ◽  
Vol 5 (1) ◽  
Keyword(s):  
Relative Permeability ◽  
Optimization Problem ◽  
Oil Field ◽  
End Effect ◽  
Flow Rates ◽  
Experimental Procedure ◽  
One Step ◽  
Injection Methods ◽  
Relative Permeability Curves ◽  
Capillary End Effect

The relative permeability curves obtained in the laboratory are used in reservoir simulators to predict production and decide the best strategies for an oil field. Therefore, researchers are studying several procedures to obtain relative permeability curves, among them the multiple flow rates injection methods. Thus, this work proposes to develop an experimental procedure with multiple increasing flows (multi-step). To make this feasible, simulations were initially carried out at CYDAR, aiming to establish the flow rates and necessary the time to system stabilization, within the limits of the equipment. After that, the tests were carried out and the results obtained were the minimum time of 5 hours to stabilize the oil production and the differential pressure at each flow rate. The accounting and minimization of the capillary end effect in these tests were also evaluated. And the capillary pressure constraints contributed to minimize the number of possible solutions of the optimization problem improving the uniqueness of solution.

Experimental studies on influence of temperature on relative permeability curves in sandstone reservoirs

2021 ◽  
pp. 014459872110408
Author(s):  
Zhiwei Zhai ◽  
Kunchao Li ◽  
Xing Bao ◽  
Jing Tong ◽  
Hongmei Yang ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Relative Permeability ◽  
Experimental Studies ◽  
Influence Of Temperature ◽  
Relative Permeability Curve ◽  
Temperature Range ◽  
Irreducible Water Saturation ◽  
Influence Of Temperature On ◽  
Sandstone Reservoirs ◽  
Relative Permeability Curves

It is crucial to obtain the representative relative permeability curves for related numerical simulation and oilfield development. The influence of temperature on the relative permeability curve remains unclear. An unsteady method was adopted to investigate the influence of temperature (range from 25–130 °C) on the oil–water relative permeability curve of sandstone reservoirs in different blocks. Then, the experimental data was analyzed by using an improved Johnson–Bossler–Naumann method. Results reveal that with the increase in temperature within a certain temperature range: (1) the relative permeability of the oil and water phases increases; (2) the irreducible water saturation increases linearly, whereas the residual oil saturation decreases nonlinearly, and the oil recovery factor increases; and (3) the saturation of two equal permeability points moves to the right, and hydrophilicity becomes stronger. The findings will aid future numerical simulation studies, thus leading to the improvement of oil displacement efficiency.

scholarly journals About Identifiability of Oil and Water Relative Permeability Curves and Reservoir Heterogeneity through Integrated Well Test Study

2021 ◽  
Vol 1730 (1) ◽  
pp. 012105
Author(s):  
E S Zakirov ◽  
D P Anikeev ◽  
I M Indrupskiy ◽  
T N Tsagan-Mandzhiev ◽  
Yu V Alekseeva
Keyword(s):  
Relative Permeability ◽  
Well Test ◽  
Reservoir Heterogeneity ◽  
Test Study ◽  
Relative Permeability Curves

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

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