Application of X-ray Scanner in Measurement of Gas Condensate Relative Permeability Using Steady-State Method

Abstract High pressure core flood experiments using gas condensate fluids in long sandstone cores have been conducted. Steady-state relative permeability points were measured over a wide range of condensate to gas ratio's (CGR), with the velocity and interfacial tension (IFT) being varied between tests in order to observe the effect on relative permeability. The experimental procedures ensured that the fluid distribution in the cores was representative of gas condensate reservoirs. Hysteresis between drainage and imbibition during the steady-state measurements was also investigated, as was the repeatability of the data. A relative permeability rate effect for both gas and condensate phases was observed, with the relative permeability of both phases increasing with an increase in flow rate. The relative permeability rate effect was still evident as the IFT increased by an order of magnitude, with the relative permeability of the gas phase reducing more than the condensate phase. The influence of end effects was shown to be negligible at the IFT conditions used in the tests, with the Reynolds number indicating that flow was well within the so called laminar regime at all test conditions. The observed rate effect was contrary to that of the conventional non-Darcy flow where the effective permeability should decrease with increasing flow rate. A generalised correlation between relative permeability, velocity and IFT has been proposed, which should be more appropriate for condensing fluids than the conventional correlation. The results highlight the need for appropriate experimental methods and relative permeability relations where the distribution of the phases are representative of those in gas condensate reservoirs. This study will be particularly applicable to the vicinity of producing wells, where the rate effect on gas relative permeability can significantly affect well productivity. The findings provide previously unreported data on relative permeability and recovery of gas condensate fluids at realistic conditions. Introduction During the production of gas condensate reservoirs, the reservoir pressure will be gradually reduced to below the dew-point, giving rise to retrograde condensation. In the vicinity of producing wells where the rate of pressure reduction is greatest, the increase in the condensate saturation from zero is accompanied by a reduction in relative permeability of gas, due to the loss of pore space available to gas flow. It is the perceived effect of this local condensate accumulation on the near wellbore gas and condensate mobility that is one of the main areas of interest for reservoir engineers. The availability of accurate relative permeability data applicable to flow in the wellbore region impacts the management of gas condensate reservoirs.

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An Experimental Investigation of High and Low Salinity Waterflood Displacement Under the Steady-State Condition

10.2118/207339-ms ◽

2021 ◽

Author(s):

Abdulla Aljaberi ◽

Seyed Amir Farzaneh ◽

Shokoufeh Aghabozorgi ◽

Mohammad Saeid Ataei ◽

Mehran Sohrabi

Keyword(s):

Steady State ◽

Numerical Simulations ◽

Relative Permeability ◽

High Salinity ◽

Unsteady State ◽

Dispersion Effect ◽

Low Salinity ◽

Steady State Method ◽

State Method ◽

Relative Permeability Curves

Abstract Oil recovery by low salinity waterflood is significantly affected by fluid-fluid interaction through the micro-dispersion effect. This interaction influences rock wettability and relative permeability functions. Therefore, to gain a better insight into multiphase flow in porous media and perform numerical simulations, reliable relative permeability data is crucial. Unsteady-state or steady-state displacement methods are commonly used in the laboratory to measure water-oil relative permeability curves of a core sample. Experimentally, the unsteady-state core flood technique is more straightforward and less time-consuming compared to the steady-state method. However, the obtained data is limited to a small saturation range, and the associated uncertainty is not negligible. On the other hand, the steady-state method provides a more accurate dataset of two-phase relative permeability needed in the reservoir simulator for a reliable prediction of the high salinity and low salinity waterflood displacement performance. Considering the limitations of the unsteady state method, steady-state high salinity and low salinity brine experiments waterflood experiments were performed to compare the obtained relative permeability curves. The experiments were performed on a carbonate reservoir sample using a live reservoir crude oil under reservoir conditions. The test was designed so that the production and pressure drop curve covers a wider saturation range and provides enough data for analysis. Consequently, reliable relative permeability functions were obtained, initially, for a better comparison and prediction of the high salinity and the low salinity waterflood injections and then, to quantify the effect of low salinity waterflood under steady-state conditions. The results confirm the difference in relative permeability curves between high salinity and low salinity injections due to the micro-dispersion effect, which caused a decrease in water relative permeability and an increase in the oil relative permeability. These results also proved that low salinity brine can change the rock wettability from oil-wet or mixed-wet to more water-wet conditions. Furthermore, the obtained relative permeability curves extend across a substantial saturation range, making it valuable information required for numerical simulations. To the best of our knowledge, the reported data in this work is a pioneer in quantifying the impact of low salinity waterflood at steady-state conditions using a reservoir crude oil and reservoir rock, which is of utmost importance for the oil and gas industry.

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Compressibility corrections to relative permeability from the non-uniform steady-state method

Chemical Engineering Science ◽

10.1016/j.ces.2013.03.009 ◽

2013 ◽

Vol 95 ◽

pp. 73-77 ◽

Cited By ~ 3

Author(s):

T.S. Ramakrishnan ◽

N.V. Chugunov

Keyword(s):

Steady State ◽

Relative Permeability ◽

Steady State Method ◽

Uniform Steady State ◽

State Method

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

Energies ◽

10.3390/en14154528 ◽

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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A relative permeability model for CBM reservoir

Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles ◽

10.2516/ogst/2019068 ◽

2020 ◽

Vol 75 ◽

pp. 2 ◽

Cited By ~ 1

Author(s):

Zeyang Peng ◽

Xiangfang Li ◽

Zheng Sun

Keyword(s):

Steady State ◽

Relative Permeability ◽

Coalbed Methane ◽

Gas Diffusion ◽

Flow Channel ◽

Flow In Porous Media ◽

Permeability Model ◽

Coalbed Gas ◽

Steady State Method ◽

State Method

Relative permeability is an effective tool for studying multiphase fluid flow in porous media. For conventional reservoirs, a relatively reliable relative permeability curve can be obtained by laboratory core test. But because of the coalbed gas reservoir permeability is low, the stable steady state method will take a very long time, and the operation is relatively complex. For the non-steady state method, the coalbed gas reservoirs are rich in micro nano pore, which causes the strong heterogeneity and gas is easy to break in through the cracks, it makes non-steady displacement experiment very difficult. Also, the experimental results are greatly affected by human factors and computational methods. Therefore, based on the ideal pore structure and the consideration of different displacement mechanisms, the analytical method not only helps to understand the mechanism of gas water two-phase flow, but also is a convenient and practical method. Coalbed methane reservoirs are rich of nano pores, and the percolation process is more complicated due to the water. Consider of the nano pore of the coal, the capillary force’s effect will be more important. The different pressure will cause different flow channel, which will change the permeability. In this paper, the relative permeability model of coalbed methane reservoir has been built which considers the gas diffusion and slippage effect, pore throat structure parameter, water saturation distribution, and gas water interface pressure drop. It can describe the difference flow channel between different pressure.

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Steady State Measurement of Oxygenation Capacity

Water Science & Technology ◽

10.2166/wst.1985.0139 ◽

1985 ◽

Vol 17 (2-3) ◽

pp. 303-311

Author(s):

Kees de Korte ◽

Peter Smits

Keyword(s):

Steady State ◽

Activated Sludge ◽

Plug Flow ◽

Usual Method ◽

Steady State Method ◽

State Measurement ◽

Flow Systems ◽

Air System ◽

State Method ◽

Steady State Measurement

The usual method for OC measurement is the non-steady state method (reaeration) in tapwater or, sometimes, in activated sludge. Both methods are more or less difficult and expensive. The steady state method with activated sludge is presented. Fundamentals are discussed. For complete mixed aeration tanks, plug flow systems with diffused air aeration and carousels the method is described more in detail and the results of measurements are presented. The results of the steady state measurements of the diffused air system are compared with those of the reaeration method in tapwater. The accuracy of the measurements in the 3 systems is discussed. Measurements in other aeration systems are described briefly. It is concluded that the steady state OC measurement offers advantages in comparison with the non-steady state method and is useful for most purposes.

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