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.

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.

Use of Transient Data To Calculate Absolute Permeability and Average Fluid Saturations

2010 ◽  
Vol 13 (02) ◽  
pp. 306-312 ◽  
Author(s):  
Medhat M. Kamal ◽  
Yan Pan
Keyword(s):  
Relative Permeability ◽  
Reservoir Simulation ◽  
Surface Flow ◽  
Absolute Permeability ◽  
Phase Flow ◽  
Simulation Studies ◽  
Flow Rates ◽  
Reservoir Performance ◽  
Transient Data ◽  
Relative Permeability Curves

Summary A new well-testing-analysis method is presented. The method allows for calculating the absolute permeability of the formation in the area influenced by the test and the average saturations in this area. Traditional pressure-transient-analysis methods have been developed and are completely adequate for single-phase flow in the reservoir. The proposed method is not intended for these conditions. The method applies to two-phase flow in the reservoir (oil and water or oil and gas). Future expansion to three-phase flow is possible. Current analysis methods yield only the effective permeability for the dominant flowing phase and the "total mobility" of all phases. The new method uses the surface-flow rates and fluid properties of the flowing phases and the same relative permeability relations used in characterizing the reservoir and predicting its future performance. The method has been verified by comparing the results from analyzing several synthetic tests that were produced by a numerical simulator with the input values. Use of the method with field data is also described. The new method could be applied wherever values of absolute permeability or fluid saturations are used in predicting well and reservoir performance. Probably, the major impact would be in reservoir simulation studies in which the need to transform welltesting permeability to simulator input values is eliminated and additional parameters (fluids saturations) become available to help history match the reservoir performance. This work will also help in predicting well flow rates and in situations in which absolute permeability changes with time (e.g., from compaction). Results showed that the values of absolute permeability in water/oil cases could be reproduced within 3% of the correct values and within 5% of the correct values in gas/oil cases. Errors in calculating the fluid saturations were even lower. One of the main advantages of this method is that the relative permeability curves used in calculating the absolute permeability and average saturations, and later on in numerical reservoir simulation studies, are the same, ensuring a consistent process. The proposed method does not address the question of which set of relative permeability curves should be used. This question should be answered by the engineer performing the reservoir engineering/simulation study. The proposed method mainly is meant to provide consistent results for predicting the reservoir performance using whatever relative permeability relations that are being used in the reservoir simulation model. The method does not induce any additional errors in determining the average saturation or absolute permeability over what may result from using these specific relative permeability curves in the reservoir simulation study. The impact of this study will be to expand the use of information already contained in transient data and surface flow rates of all phases. The results will provide engineers with additional parameters to improve and speed up history matching and the prediction of well and reservoir performances in just about all studies.

Multiphase Flow Under Heterogeneous Wettability Conditions Studied by Special Core Analysis and Pore-Scale Imaging

SPE Journal ◽  
2019 ◽  
Vol 24 (03) ◽  
pp. 1234-1247 ◽  
Author(s):  
Shuangmei Zou ◽  
Ryan T. Armstrong
Keyword(s):  
Multiphase Flow ◽  
Relative Permeability ◽  
Flow Regimes ◽  
Wettability Alteration ◽  
Core Analysis ◽  
Pore Scale ◽  
End Effect ◽  
The Impact ◽  
Capillary End Effect ◽  
Special Core Analysis

Summary Wettability is a major factor that influences multiphase flow in porous media. Numerous experimental studies have reported wettability effects on relative permeability. Laboratory determination for the impact of wettability on relative permeability continues to be a challenge because of difficulties with quantifying wettability alteration, correcting for capillary-end effect, and observing pore-scale flow regimes during core-scale experiments. Herein, we studied the impact of wettability alteration on relative permeability by integrating laboratory steady-state experiments with in-situ high-resolution imaging. We characterized wettability alteration at the core scale by conventional laboratory methods and used history matching for relative permeability determination to account for capillary-end effect. We found that because of wettability alteration from water-wet to mixed-wet conditions, oil relative permeability decreased while water relative permeability slightly increased. For the mixed-wet condition, the pore-scale data demonstrated that the interaction of viscous and capillary forces resulted in viscous-dominated flow, whereby nonwetting phase was able to flow through the smaller regions of the pore space. Overall, this study demonstrates how special-core-analysis (SCAL) techniques can be coupled with pore-scale imaging to provide further insights on pore-scale flow regimes during dynamic coreflooding experiments.

scholarly journals Research on the Correction Method of the Capillary End Effect of the Relative Permeability Curve of the Steady State

Energies ◽  
2021 ◽  
Vol 14 (15) ◽  
pp. 4528
Author(s):  
Yanyan Li ◽  
Shuoliang Wang ◽  
Zhihong Kang ◽  
Qinghong Yuan ◽  
Xiaoqiang Xue ◽  
...  
Keyword(s):  
Steady State ◽  
Pressure Drop ◽  
Relative Permeability ◽  
Stability Factor ◽  
End Effect ◽  
Relative Permeability Curve ◽  
Steady State Method ◽  
State Method ◽  
The Impact ◽  
Capillary End Effect

Relative permeability curve is a key factor in describing the characteristics of multiphase flow in porous media. The steady-state method is an effective method to measure the relative permeability curve of oil and water. The capillary discontinuity at the end of the samples will cause the capillary end effect. The capillary end effect (CEE) affects the flow and retention of the fluid. If the experimental design and data interpretation fail to eliminate the impact of capillary end effects, the relative permeability curve may be wrong. This paper proposes a new stability factor method, which can quickly and accurately correct the relative permeability measured by the steady-state method. This method requires two steady-state experiments at the same proportion of injected liquid (wetting phase and non-wetting phase), and two groups of flow rates and pressure drop data are obtained. The pressure drop is corrected according to the new relationship between the pressure drop and the core length. This new relationship is summarized as a stability factor. Then the true relative permeability curve that is not affected by the capillary end effect can be obtained. The validity of the proposed method is verified against a wide range of experimental results. The results emphasize that the proposed method is effective, reliable, and accurate. The operation steps of the proposed method are simple and easy to apply.

Intercept Method—A Novel Technique To Correct Steady-State Relative Permeability Data for Capillary End Effects

2015 ◽  
Vol 19 (02) ◽  
pp. 316-330 ◽  
Author(s):  
Robin Gupta ◽  
Daniel R. Maloney
Keyword(s):  
Steady State ◽  
Relative Permeability ◽  
Data Interpretation ◽  
End Effect ◽  
Fractional Flow ◽  
End Effects ◽  
Flow Rates ◽  
Pressure Drops ◽  
State Tests ◽  
State Measurement

Summary In laboratory measurements of relative permeability, capillary discontinuities at sample ends give rise to capillary end effects (CEEs). End effects affect fluid flow and retention. If end-effect artifacts are not minimized by test design and data interpretation, relative permeability results may be significantly erroneous. This is a well-known issue in unsteady-state tests, but even steady-state relative permeability results are influenced by end-effect artifacts. This work describes the intercept method, a novel modified steady-state approach in which corrections for end-effect artifacts are applied as data are measured. The intercept method requires running a steady-state relative permeability test with several different flow rates for each fractional flow. Obtaining multiple (three or four) sets of rates (Q), pressure drops (ΔP), and saturation data allows for assessment of CEE artifacts. With Darcy flow, a plot of pressure drop vs. total flow rate is typically linear. A nonzero intercept or offset is an end-effect artifact. To correct for the effect, the offset is subtracted from measured pressure drops. Corrected pressure drops are used in permeability calculations. The set of saturations from measurements at the target fractional flow is used to calculate a corrected final saturation. Because corrections for end effects are made during the test rather than after the test is complete, any discrepancies can be resolved by additional measurements before moving on to the next fractional flow. Rates are then adjusted to yield the next target fractional-flow condition, and the same protocol is repeated for each subsequent steady-state measurement. The method is validated by theory and is easy to apply.

Sign in / Sign up

Export Citation Format

Share Document