Equation-of-State Approach to Model Relative Permeability Including Hysteresis and Wettability Alteration

2017 ◽  
Author(s):  
Saeid Khorsandi ◽  
Liwei Li ◽  
Russell T. Johns
Keyword(s):  
Equation Of State ◽  
Relative Permeability ◽  
Wettability Alteration

Equation of State for Relative Permeability, Including Hysteresis and Wettability Alteration

SPE Journal ◽  
2017 ◽  
Vol 22 (06) ◽  
pp. 1915-1928 ◽  
Author(s):  
Saeid Khorsandi ◽  
Liwei Li ◽  
Russell T. Johns
Keyword(s):  
Experimental Data ◽  
Equation Of State ◽  
Surface Properties ◽  
Relative Permeability ◽  
Contact Angles ◽  
Wettability Alteration ◽  
Rock Surface ◽  
Relative Permeabilities ◽  
Tuning Parameters ◽  
Rock Structure

Summary Commercial compositional simulators commonly apply correlations or empirical relations that are based on fitting experimental data to calculate phase relative permeabilities. These relations cannot adequately capture the effects of hysteresis, fluid compositional variations, and rock-wettability alteration. Furthermore, these relations require phases to be labeled, which is not accurate for complex miscible or near-miscible displacements with multiple hydrocarbon phases. Therefore, these relations can be discontinuous for compositional processes, causing inaccuracies and numerical problems in simulation. This paper develops for the first time an equation-of-state (EOS) to model robustly and continuously the relative permeability as a function of phase saturations and distributions, fluid compositions, rock-surface properties, and rock structure. Phases are not labeled; instead, the phases in each gridblock are ordered on the basis of their compositional similarity. Phase compositions and rock-surface properties are used to calculate wettability and contact angles. The model is tuned to measured two-phase relative permeability curves with very few tuning parameters and then is used to predict relative permeability away from the measured experimental data. The model is applicable to all flow in porous-media processes, but is especially important for low-salinity polymer, surfactant, miscible gas, and water-alternating-gas (WAG) flooding. The results show excellent ability to match measured data, and to predict observed trends in hysteresis and oil-saturation trapping, including those from Land's model and for a wide range in wettability. The results also show that relative permeabilities are continuous at critical points and yield a physically correct numerical solution when incorporated within a compositional simulator (PennSim 2013). The model has very few tuning parameters, and the parameters are directly related to physical properties of rock and fluid, which can be measured. The new model also offers the potential for incorporating results from computed-tomography (CT) scans and pore-network models to determine some input parameters for the new EOS.

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.

On the development of a relative permeability equation of state

2019 ◽  
Vol 24 (2) ◽  
pp. 807-818 ◽  
Author(s):  
Prakash Purswani ◽  
Miral S. Tawfik ◽  
Zuleima T. Karpyn ◽  
Russell T. Johns
Keyword(s):  
Equation Of State ◽  
Relative Permeability

scholarly journals Production improvement in gas condensate reservoirs by wettability alteration, using superamphiphobic titanium oxide nanofluid

2018 ◽  
Vol 73 ◽  
pp. 46 ◽  
Author(s):  
Pouriya Esmaeilzadeh ◽  
Mohammad Taghi Sadeghi ◽  
Alireza Bahramian
Keyword(s):  
Liquid Phase ◽  
Relative Permeability ◽  
Core Sample ◽  
Carbonate Reservoir ◽  
Gas Condensate ◽  
Reservoir Rock ◽  
Wettability Alteration ◽  
Energy Materials ◽  
Gas Condensate Reservoirs ◽  
Production Improvement

Many gas condensate reservoirs suffer a loss in productivity owing to accumulation of liquid in near-wellbore region. Wettability alteration of reservoir rock from liquid-wetting to gas-wetting appears to be a promising technique for elimination of the condensate blockage. In this paper, we report use of a superamphiphobic nanofluid containing TiO2 nanoparticles and low surface energy materials as polytetrafluoroethylene and trichloro(1H,1H,2H,2H-perfluorooctyl)silane to change the wettability of the carbonate reservoir rock to ultra gas-wetting. The utilization of nanofluid in the wettability alteration of carbonate rocks to gas-wetting in core scale has not been reported already and is still an ongoing issue. Contact angle measurements was conducted to investigate the wettability of carbonate core plugs in presence of nanofluid. It was found that the novel formulated nanofluid used in this work can remarkably change the wettability of the rock from both strongly water- and oil-wetting to highly gas-wetting condition. The adsorption of nanoparticles on the rock and formation of nano/submicron surface roughness was verified by Scanning Electron Microscope (SEM) and Stylus Profilometer (SP) analyses. Using free imbibition test, we showed that the nanofluid can imbibe interestingly into the core sample, resulting in notable ultimate gas-condensate liquid recovery. Moreover, we studied the effect of nanofluid on relative permeability and recovery performance of gas/water and gas/oil systems for a carbonate core. The result of coreflooding tests demonstrates that the relative permeability of both gas and liquid phase increased significantly as well as the liquid phase recovery enhanced greatly after the wettability alteration to gas-wetting.

scholarly journals Influence of Clay Wettability Alteration on Relative Permeability

2020 ◽  
Vol 47 (18) ◽  
Author(s):  
Ming Fan ◽  
James E. McClure ◽  
Ryan T. Armstrong ◽  
Mehdi Shabaninejad ◽  
Laura E. Dalton ◽  
...  
Keyword(s):  
Relative Permeability ◽  
Wettability Alteration

Displacement Studies in Dolomite With Wettability Control by Octanoic Acid

1973 ◽  
Vol 13 (04) ◽  
pp. 221-232 ◽  
Author(s):  
N.R. Morrow ◽  
P.J. Cram ◽  
F.G. McCaffery
Keyword(s):  
Contact Angle ◽  
Interfacial Tension ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Significant Influence ◽  
Octanoic Acid ◽  
Contact Angles ◽  
Wettability Alteration ◽  
Residual Oil ◽  
Relative Permeability Curves

Abstract Various nitrogen-, oxygen- and sulfur-containing compounds native to crude oils were screened for their effect on wettability as measured by contact angle. Solid substrates of quartz, calcite, and dolomite crystals were used to represent reservoir rock surfaces. With water and decane as liquids, contact angles were measured after a given polar compound was added to the oil phase. Contact angles measured at the two types of carbonate surfaces were generally similar. None of the nitrogen or sulfur compounds studied gave contact angles greater than 66 degrees on either quartz or carbonates. Of the oxygen-containing compounds, octanoic acid gave the widest range of contact angle - 0 degrees to 145 degrees on dolomite - over a molar concentration range up to 0.1. Capillary - pressure and relative-permeability curves were obtained for water and solutions of octanoic acid in oil, using packings of powdered dolomite as the porous medium. Because of a slow reaction between dolomite and octanoic acid, which was not revealed by standard contact angle studies, special precautions were needed to ensure satisfactory wettability control during displacement tests. Capillary-pressure drainage curves were measured at six contact angles, ranging from 0 degrees to 140 degrees. Drainage-imbibition cycles for three packings of distinctly different particle size were measured at contact angles of 0 degrees and 49 degrees. The effect of contact angle on imbibition capillary pressures was close to that found previously for porous polytetra-fluoroethylene, whereas there was comparatively polytetra-fluoroethylene, whereas there was comparatively less effect on drainage behavior-steady-state relative permeability curves exhibited distinct differences for contact angles of 15 degrees, 100 degrees and 155 degrees. Introduction Waterflooding is the most successful and widely applied improved recovery technique. Its application in Alberta has, on the average, more than doubled the recovery obtained by primary depletion. However, even after waterflooding, it is estimated that two-thirds of the discovered oil remains unrecovered. Interfacial forces acting during waterflooding lead to the entrapment of large quantities of residual oil in the swept zones. Considerable attention has been paid to recovering this oil through new recovery methods in which the interface is eliminated as in miscible processes, or the interfacial tension is drastically lowered, as in surfactant floods. Such processes involve a high initial cost for an injected solvent or surfactant bank. Recently released information on a variety of such improved recovery techniques has not been altogether encouraging with regard to developing economical processes. A distinct alternative to eliminating the interface is to understand it and learn how it can be manipulated to give increased waterflood recoveries. A prospect for improved recovery at interfacial tensions of the order normally encountered in reservoirs lies in a favorable adjustment of wettability by incorporating small amounts of low-cost additives in the floodwater. A first step in developing the technology of improved recovery by wettability alteration is to determine the effect of wettability alteration on displacement in systems of uniform wettability. It has been shown that, even in the "near miscible" surfactant processes, wettability can still have a significant influence on the extent to which interfacial tension must be lowered in order to mobilize residual oil. At the time when waterflooding first found widespread use, wettability was recognized as a variable that might well have a significant influence on recovery performance. Reservoir wettability and the role of wettability in displacement has been the subject of some 50 or so publications. Even so, many aspects of wettability are not well understood and there is no general agreement on a satisfactory method of characterizing it. Opinions as to the optimum wettability condition for recovery cover the spectrum from strongly water-wet through weakly water-wet or intermediately wet to strongly oil-wet. It has recently been suggested that a mixed wettability condition can give high ultimate recoveries. SPEJ P. 221

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.

Mitigation of Gas Condensate Banking Using Thermochemical Fluids and Gemini Surfactant: A Comparison Study

2021 ◽  
Author(s):  
Amjed Hassan ◽  
Mohamed Mahmoud ◽  
Muhammad Shahzad Kamal ◽  
Abdulaziz Al-Majed ◽  
Ayman Al-Nakhli ◽  
...  
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Gemini Surfactant ◽  
Integrated Approach ◽  
Capillary Forces ◽  
Gas Production ◽  
Wettability Alteration ◽  
Comparison Study ◽  
Multiple Fractures

Abstract Accumulation of condensate liquid around the production well can cause a significant reduction in gas production. Several methods are used to mitigate the condensate bank and maintain the gas production. The most effective approaches are altering the rock wettability or inducing multiple fractures around the wellbore. This paper presents a comparison study for two effective approaches in mitigating the condensate bank. The performance of thermochemical fluids (TCF) and gemini surfactant (GS) in removing the condensate liquid and improve the formation productivity is studied. In this work, several experiments were carried out including coreflooding, capillary pressure, and relative permeability measurements. The profiles of condensate saturations show that GS can mitigate the condensate bank by 84%, while TCF removed around 63% of the condensate liquid. Also, GS and TCF treatments can increase the relative permeability to condensate liquid by factors of 1.89 and 1.22 respectively, due to the wettability alteration mechanism. Capillary pressure calculations show that GS can reduce the capillary pressure by around 40% on average, while TCF leads to a 70% reduction in the capillary forces. Overall, injection of GS into the condensate region can lead to changing the wettability condition due to the chemical adsorption of GS on the pore surface, and thereby reduce the capillary forces and improve the condensate mobility. On the other hand, TCF injection can improve rock permeability and reduce capillary pressure. Both treatments (GS and TCF) showed very attractive performance in mitigating the condensate bank and improving the formation production for the long term. Finally, an integrated approach is presented that can mitigate the condensate damage by around 95%, utilizing the effective mechanisms of GS and TCF chemicals.

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