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.

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.

Simultaneous Measuring Method for Both Volumetric Flow Rates of Air-Water Mixture Using a Turbine Flowmeter

1996 ◽  
Vol 118 (1) ◽  
pp. 29-35 ◽  
Author(s):  
K. Minemura ◽  
K. Egashira ◽  
K. Ihara ◽  
H. Furuta ◽  
K. Yamamoto
Keyword(s):  
Pressure Drop ◽  
Flow Rate ◽  
Volumetric Flow Rate ◽  
Oil Field ◽  
Liquid Density ◽  
Water Mixture ◽  
Rotor Speed ◽  
Flow Rates ◽  
Field Development ◽  
Turbine Flowmeter

A turbine flowmeter is employed in this study in connection with offshore oil field development, in order to measure simultaneously both the volumetric flow rates of air-water two-phase mixture. Though a conventional turbine flowmeter is generally used to measure the single-phase volumetric flow rate by obtaining the rotational rotor speed, the method proposed additionally reads the pressure drop across the meter. After the pressure drop and rotor speed measured are correlated as functions of the volumetric flow ratio of the air to the whole fluid and the total volumetric flow rate, both the flow rates are iteratively evaluated with the functions on the premise that the liquid density is known. The evaluated flow rates are confirmed to have adequate accuracy, and thus the applicability of the method to oil fields.

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.

Work With Chemical Additives Advances Understanding of Relative Permeability Shifts

2021 ◽  
Vol 73 (09) ◽  
pp. 37-38
Author(s):  
Chris Carpenter
Keyword(s):  
Steady State ◽  
Relative Permeability ◽  
Flow Rate ◽  
Pressure Difference ◽  
Effective Permeability ◽  
Constant Flow ◽  
Chemical Additives ◽  
Flow Rates ◽  
Steady State Method ◽  
Tight Rocks

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201520, “Advances in Understanding Relative Permeability Shifts by Imbibition of Surfactant Solutions Into Tight Plugs,” by Mohammad Yousefi, Lin Yuan, and Hassan Dehghanpour, SPE, University of Alberta, prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5–7 October. The paper has not been peer reviewed. Various chemical additives have been proposed recently to enhance imbibition oil recovery from tight formations during shut-in periods after hydraulic fracturing operations. In the complete paper, the authors develop and apply a laboratory protocol mimicking leakoff, shut-in, and flowback processes to evaluate the effects of fracturing-fluid additives on oil regained permeability. A conventional coreflooding apparatus is modified to measure oil effective permeability (koeff) before and after the surfactant-imbibition experiments. Methodology Proposed Technique for Measuring Oil Effective Permeability. Despite the simplicity of the steady-state method, measuring permeability of tight rocks with this technique is challenging because of its time-consuming nature and the fact that accurate measurement is necessary of extremely low flow rates corresponding to low injectivity of tight rocks. The authors use a pair of plugs from a well drilled in the Montney formation that is a stratigraphic unit of the Lower Triassic age in the western Canadian sedimentary basin located in British Columbia and Alberta. It is mainly a low-permeability siltstone reservoir. In the modified coreflooding apparatus, the authors reduce the effect of compressibility in order to reduce the duration of the transient period by approximately one order of magnitude. Because monitoring changes in pressure is much easier and more accurate than monitoring flow-rate changes, a constant flow-rate mode is used and pressure is recorded with time. Oil is injected at different constant flow rates (qo), and the inlet pressure is monitored. The stable pressure difference across the plug is recorded for each flow rate. After steady-state conditions are reached based on the pressure profile, the qo is increased. This process is repeated until four stable pressure differences corresponding to four different qo are obtained. After the highest qo is reached, it is decreased in similar steps to check the repeatability of each data point. The permeability is calculated with the Darcy equation and slope of the qo vs. stable pressure difference across the plug.

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.

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