Effect of Interfacial Tension on Water/Oil Relative Permeability on the Basis of History Matching to Coreflood Data

2014 ◽  
Vol 17 (01) ◽  
pp. 37-48 ◽  
Author(s):  
Edwin Andrew Chukwudeme ◽  
Ingebret Fjelde ◽  
Kumuduni Abeysinghe ◽  
Arild Lohne
Keyword(s):  
Interfacial Tension ◽  
Relative Permeability ◽  
Capillary Number ◽  
History Matching ◽  
Water Saturation ◽  
Residual Water ◽  
End Effects ◽  
The Core ◽  
Rate Dependent ◽  
Phase Saturation

Summary The effect of interfacial tension (IFT) on the displacement of the nonwetting and wetting phases has been investigated by the use of simulations/history matching of flooding experiments. In surfactant flooding, a conventional assumption is to neglect the effect of capillary pressure (Pc) on measured two-phase properties. The methodology applied in this paper allows improved interpretation of experimental results by correcting for the influence of capillary end effects on the measured capillary desaturation curve (CDC) and on the estimated relative permeability (kr). Three fluid systems of different IFTs were prepared by use of a solvent system (CaCl2 brine/iso-octane/isopropanol) rather than a surfactant system with the assumption that both systems have similar flood behavior at reduced IFT. Three coreflood cycles, including multirate oil injection (drainage) followed by multirate water injection (imbibition), were carried out at each IFT in water-wet Berea cores. The kr functions corrected for capillary end effects were derived by numerically history matching the experimental production and pressure-drop (PD) history. A typical CDC is observed for the nonwetting phase oil, with a roughly constant plateau in residual oil saturation (ROS), Sor, below a critical capillary number (Ncc) and a declining slope above Ncc toward zero Sor. No influence of Pc was found for the nonwetting-phase CDC. The results from the displacement of the wetting phase formed an apparent CDC with a declining slope and no Ncc. Analyzing the wetting-phase results, we find that the wetting-phase CDC is not a true CDC. First, it is a plot of the average remaining water saturation (Sw) in the core which, in all the experiments, is higher than residual water saturation, Swr, obtained from Pc measurements. Second, we find that the remaining Sw is only partly a function of Nc. At low Nc, the water production (WP) is limited by capillary end effects. Rate-dependent WP observed with the high-IFT system is fully reproduced in simulations by use of constant kr and Pc. The remaining wetting-phase saturation at a low capillary number (Nc) is a result of the core-scale balance between viscous and capillary forces and would, for example, depend on the core length. At a higher Nc, the WP is found to be limited by the low kr tail, typical for wetting phases. However, we find that the kr functions become rate dependent at a higher Nc, and we assume that this rate dependency can be modeled as a function of Nc. The remaining wetting-phase saturation at a higher Nc would then be a function of Nc and the number of pore volumes (PVs) injected. The observed Nc dependency in the flow functions indicates a potential for the accelerated production of the wetting phase by use of surfactant. Assuming that the results obtained here for the wetting phase also apply to oil in a mixed-wet system, it is strongly recommended to evaluate the effect of both Pc and Ncc when designing a surfactant model for a mixed-wet field.

scholarly journals Interpretation of Gas/Water Relative Permeability of Coal Using the Hybrid Bayesian-Assisted History Matching: New Insights

Energies ◽  
2021 ◽  
Vol 14 (3) ◽  
pp. 626
Author(s):  
Jiyuan Zhang ◽  
Bin Zhang ◽  
Shiqian Xu ◽  
Qihong Feng ◽  
Xianmin Zhang ◽  
...  
Keyword(s):  
Relative Permeability ◽  
Coalbed Methane ◽  
History Matching ◽  
Water Saturation ◽  
Unsteady State ◽  
Core Flooding ◽  
Rock Interaction ◽  
Interaction Mechanisms ◽  
True Value ◽  
Assisted History Matching

The relative permeability of coal to gas and water exerts a profound influence on fluid transport in coal seams in both primary and enhanced coalbed methane (ECBM) recovery processes where multiphase flow occurs. Unsteady-state core-flooding tests interpreted by the Johnson–Bossler–Naumann (JBN) method are commonly used to obtain the relative permeability of coal. However, the JBN method fails to capture multiple gas–water–coal interaction mechanisms, which inevitably results in inaccurate estimations of relative permeability. This paper proposes an improved assisted history matching framework using the Bayesian adaptive direct search (BADS) algorithm to interpret the relative permeability of coal from unsteady-state flooding test data. The validation results show that the BADS algorithm is significantly faster than previous algorithms in terms of convergence speed. The proposed method can accurately reproduce the true relative permeability curves without a presumption of the endpoint saturations given a small end-effect number of <0.56. As a comparison, the routine JBN method produces abnormal interpretation results (with the estimated connate water saturation ≈33% higher than and the endpoint water/gas relative permeability only ≈0.02 of the true value) under comparable conditions. The proposed framework is a promising computationally effective alternative to the JBN method to accurately derive relative permeability relations for gas–water–coal systems with multiple fluid–rock interaction mechanisms.

scholarly journals Insights, Trends and Challenges Associated with Measuring Coal Relative Permeability

2019 ◽  
Vol 89 ◽  
pp. 01004
Author(s):  
Dylan Shaw ◽  
Peyman Mostaghimi ◽  
Furqan Hussain ◽  
Ryan T. Armstrong
Keyword(s):  
Relative Permeability ◽  
Effective Stress ◽  
History Matching ◽  
Water Saturation ◽  
Laboratory Data ◽  
Stress Regime ◽  
Cross Point ◽  
Irreducible Water Saturation ◽  
Relative Permeability Curves ◽  
The Right

Due to the poroelasticity of coal, both porosity and permeability change over the life of the field as pore pressure decreases and effective stress increases. The relative permeability also changes as the effective stress regime shifts from one state to another. This paper examines coal relative permeability trends for changes in effective stress. The unsteady-state technique was used to determine experimental relativepermeability curves, which were then corrected for capillary-end effect through history matching. A modified Brooks-Corey correlation was sufficient for generating relative permeability curves and was successfully used to history match the laboratory data. Analysis of the corrected curves indicate that as effective stress increases, gas relative permeability increases, irreducible water saturation increases and the relative permeability cross-point shifts to the right.

A Water-Gas Relative Permeability Relationship for Tight Gas Sand Reservoirs

1990 ◽  
Vol 112 (4) ◽  
pp. 239-245 ◽  
Author(s):  
S. D. L. Lekia ◽  
R. D. Evans
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Water Saturation ◽  
Gas Permeability ◽  
Tight Gas ◽  
Relative Permeabilities ◽  
The North ◽  
Tight Gas Sands ◽  
Straight Line ◽  
Phase Saturation

This paper presents a new approach for the analyses of laboratory-derived capillary pressure data for tight gas sands. The method uses the fact that a log-log plot of capillary pressure against water saturation is a straight line to derive new expressions for both wetting and nonwetting phase relative permeabilities. The new relative permeability equations are explicit functions of water saturation and the slope of the log-log straight line of capillary pressure plotted against water saturation. Relative permeabilities determined with the new expressions have been successfully used in simulation studies of naturally fractured tight gas sands where those determined with Corey-type expressions which are functions of reduced water saturation have failed. A dependence trend is observed between capillary pressure and gas permeability data from some of the tight gas sands of the North American Continent. The trend suggests that the lower the gas permeability, the higher the capillary pressure values at the same wetting phase saturation—especially for saturations less than 60 percent.

scholarly journals A CUSTOMIZED QUASI THREE-PHASE DRAINAGE RELATIVE PERMEABILITY MODEL FOR SOME INDONESIAN WATER-WET SANDSTONES

2018 ◽  
Vol 41 (1) ◽  
pp. 1-15
Author(s):  
Prof. Dr. Ir. Bambang Widarsono, M.Sc.
Keyword(s):  
Relative Permeability ◽  
Water Saturation ◽  
Measurement Data ◽  
Production Performance ◽  
Permeability Model ◽  
Reservoir Rocks ◽  
Hydrocarbon Reservoir ◽  
Three Phase ◽  
Irreducible Water Saturation ◽  
Phase Saturation

Information about drainage effective two-phase i.e. quasi three-phase relative permeability characteristics of reservoir rocks is regarded as very important in hydrocarbon reservoir modeling. The data governs various processes in reservoir such as gas cap expansion, solution gas expansion, and immiscible gas drive in enhanced oil recovery (EOR). The processes are mechanisms in reservoir that in the end determines reserves and resevoir production performance. Nevertheless, the required information is often unavailable for various reasons. This study attempts to provide solution through customizing an existing drainage relative permeability model enabling it to work for Indonesian reservoir rocks. The standard and simple Corey et al. relative permeability model is used to model 32 water-wet sandstones taken from 5 oil wells. The sandstones represent three groups of conglomeratic sandstones, micaceous-argillaceous sandstones, and hard sandstones. Special correlations of permeability irreducible water saturation and permeability ratio irreducible water saturation have also been established. Model applications on the 32 sandstones have yielded specific pore size distribution index (?) and wetting phase saturation parameter (Sm) values for the three sandstone groups, and established a practical procedure for generating drainage quasi three-phase relative permeability curves in absence of laboratory direct measurement data. Other findings such as relations between ? and permeability and influence of sample size in the modeling are also made.

scholarly journals The correlation of the steady-state gas/water relative permeabilities of porous media with gas and water capillary numbers

2019 ◽  
Vol 74 ◽  
pp. 45 ◽  
Author(s):  
Christos D. Tsakiroglou
Keyword(s):  
Steady State ◽  
Relative Permeability ◽  
Capillary Number ◽  
Water Saturation ◽  
Water System ◽  
Power Functions ◽  
Relative Permeabilities ◽  
Sand Column ◽  
Oil Water ◽  
Wetting Fluid

The steady-state gas, k rg, and water, k rw, relative permeabilities are measured with experiments of the simultaneous flow, at varying flow rates, of nitrogen and brine (aqueous solution of NaCl brine) on a homogeneous sand column. Two differential pressure transducers are used to measure the pressure drop across each phase, and six ring electrodes are used to measure the electrical resistance across five segments of the sand column. The electrical resistances are converted to water saturations with the aid of the Archie equation for resistivity index. Both k rw and k rg are regarded as power functions of water, Caw, and gas, Cag, capillary numbers, the exponents of which are estimated with non-linear fitting to the experimental datasets. An analogous power law is used to express water saturation as a function of Caw, and Cag. In agreement to earlier studies, it seems that the two-phase flow regime is dominated by connected pathway flow and disconnected ganglia dynamics for the wetting fluid (brine), and only disconnected ganglia dynamics for the non-wetting fluid (gas). The water saturation is insensitive to changes of water and gas capillary numbers. Each relative permeability is affected by both water and gas capillary numbers, with the water relative permeability being a strong function of water capillary number and gas relative permeability depending strongly on the gas capillary number. The slope of the water relative permeability curve for a gas/water system is much higher than that of an oil/water system, and the slope of the gas relative permeability is lower than that of an oil/water system.

scholarly journals Wettability Effects on Capillary Pressure, Relative Permeability, and Irredcucible Saturation Using Porous Plate

2014 ◽  
Vol 2014 ◽  
pp. 1-12 ◽  
Author(s):  
Olugbenga Falode ◽  
Edo Manuel
Keyword(s):  
Porous Media ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Water Saturation ◽  
Porous Plate ◽  
Reservoir Rock ◽  
Flow In Porous Media ◽  
Wettability Alteration ◽  
Initial Water ◽  
Phase Saturation

An understanding of the mechanisms by which oil is displaced from porous media requires the knowledge of the role of wettability and capillary forces in the displacement process. The determination of representative capillary pressure (Pc) data and wettability index of a reservoir rock is needed for the prediction of the fluids distribution in the reservoir: the initial water saturation and the volume of reserves. This study shows how wettability alteration of an initially water-wet reservoir rock to oil-wet affects the properties that govern multiphase flow in porous media, that is, capillary pressure, relative permeability, and irreducible saturation. Initial water-wet reservoir core samples with porosities ranging from 23 to 33%, absolute air permeability of 50 to 233 md, and initial brine saturation of 63 to 87% were first tested as water-wet samples under air-brine system. This yielded irreducible wetting phase saturation of 19 to 21%. The samples were later tested after modifying their wettability to oil-wet using a surfactant obtained from glycerophtalic paint; and the results yielded irreducible wetting phase saturation of 25 to 34%. From the results of these experiments, changing the wettability of the samples to oil-wet improved the recovery of the wetting phase.

scholarly journals Impact of Pressure and Brine Salinity on Capillary Pressure-Water Saturation Relations in Geological CO2Sequestration

2016 ◽  
Vol 2016 ◽  
pp. 1-11 ◽  
Author(s):  
Jongwon Jung ◽  
Jong Wan Hu
Keyword(s):  
Contact Angle ◽  
Interfacial Tension ◽  
Capillary Pressure ◽  
Water Saturation ◽  
Theoretical Models ◽  
Wettability Alteration ◽  
Residual Water ◽  
Atmospheric Conditions ◽  
Pressure Water ◽  
Brine Salinity

Capillary pressure-water saturation relations are required to explore the CO2/brine flows in deep saline aquifers including storage capacity, relative permeability of CO2/brine, and change to stiffness and volume. The study on capillary pressure-water saturation curves has been conducted through experimentation and theoretical models. The results show that as the pressure increases up to 12 MPa, (1) capillary pressure-water saturation curves shift to lower values at given water saturation, (2) after the drainage process, residual water saturation decreases, and (3) after the imbibition process, capillary CO2trapping increases. Capillary pressure-water saturation curves above 12 MPa appear to be similar because of relatively constant contact angle and interfacial tension. Also, as brine salinity increases from 1 M to 3 M NaCl, (1) capillary pressure-water saturation curves shift to lower capillary pressure, (2) residual water saturation decreases, and (3) capillary CO2trapping increases. The results show that pressure and brine salinity have an influence on the capillary pressure-water saturation curves. Also, the scaled capillary CO2entry pressure considering contact angle and interfacial tension is inconsistent with atmospheric conditions due to the lack of wettability information. Better exploration of wettability alteration is required to predict capillary pressure-water saturation curves at various conditions that are relevant to geological CO2sequestration.

scholarly journals A proposed capillary number dependent model for prediction of relative permeability in gas condensate reservoirs: a robust non-linear regression analysis

2020 ◽  
Vol 75 ◽  
pp. 24
Author(s):  
Mehdi Mahdaviara ◽  
Abbas Helalizadeh
Keyword(s):  
Regression Analysis ◽  
Relative Permeability ◽  
Capillary Number ◽  
Linear Regression Analysis ◽  
Gas Condensate ◽  
Statistical Parameters ◽  
New Model ◽  
Gas Condensate Reservoirs ◽  
Phase Saturation ◽  
Liquid Condensate

Well deliverability reduction as a result of liquid (condensate) build up in near well regions is an important deal in the development of gas condensate reservoirs. The relative permeability is an imperative factor for characterization of the aforementioned problem. The dependence of relative permeability on the coupled effects of Interfacial Tension (IFT) and flow velocity (capillary number) together with phase saturation is well established in the literature. In gas condensate reservoirs, however, the influence of IFT and velocity on this parameter becomes more evident. The current paper aims to establish a new model for predicting the relative permeability of gas condensate reservoirs by employing the direct interpolation technique. To this end, the regression analysis was carried out using seven sets of literature published experimental data. The validity analysis was executed by utilizing statistical parameters integrated with graphical descriptions. Furthermore, a comparison was carried out between the proposed model and some literature published empirical models. The results of the examination demonstrated that the new model outperformed other correlations from the standpoints of accuracy and reliability.

scholarly journals Analysis of the efficiency of models of transition zones to determine oil-saturation factors and position of contact of hydrocarbons with water

2020 ◽  
pp. 67-76
Author(s):  
G. E. Stroyanetskaya
Keyword(s):  
Capillary Pressure ◽  
Transition Zone ◽  
Water Saturation ◽  
Residual Water ◽  
Oil Saturation ◽  
Transition Zones ◽  
The Core ◽  
Geophysical Parameter ◽  
Saturation Factor ◽  
Geophysical Information

The article is devoted to the usage of models of transition zones in the interpretation of geological and geophysical information. These models are graphs of the dependences of oil-saturation factors of the collectors on their height above the level with zero capillary pressure, taking into account the geological and geophysical parameter. These models are not recommended for estimating oilsaturation factors of collectors in the transition zone. The height of occurrence of the collector above the level of zero capillary pressure can be estimated from model of the transition zone that take into account the values of the coefficients of residual water saturation factor of the collectors, but only when the model of the transition zone is confirmed by data capillarimetry studies on the core.

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