Dynamic viscosity estimation of hydrogen sulfide using a predictive scheme based on molecular dynamics

Galliéro, Guillaume; Boned, Christian

doi:10.1016/j.fluid.2008.04.017

Cited by 16 publications

(13 citation statements)

References 17 publications

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“…In addition, by using temperature-dependent molecular parameters, the LJ fluid model can also be used to represent molecules exhibiting a dipole moment, such as H 2 S. In previous works (Galliéro et al 2007;Galliéro and Boned 2008), we have shown that such a fluid model is able to provide results on thermophysical properties of H 2 S consistent with the scarce database and with more-complex molecular models.…”

Section: Introductionmentioning

confidence: 80%

“…In the case of H 2 S, practically no data exist because of its high toxicity. This lack of information is even more pronounced concerning transport properties, such as viscosity (Galliéro and Boned 2008;Liley et al 1988;Schmidt et al 2008), at typical petroleum-reservoir conditions (i.e., high pressures and high temperatures). A predictive, physically based model is highly required as long as high-pressure viscosity is one of the key physical properties for the design of acid-gases disposal.…”

Section: Introductionmentioning

confidence: 99%

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High-Pressure Acid-Gas Viscosity Correlation

Galliéro¹,

Boned²,

Baylaucq³

et al. 2010

SPE Journal

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International audienceAcid gases containing hydrogen sulfide (H2S) are often encountered in the petroleum industry. However, reliable experiments on their thermophysical properties in reservoir conditions, on viscosity in particular, are scarce. From a modeling point of view, H2S and carbon dioxide (CO2) are polar compounds and as such are often considered rather difficult to model accurately. In this work, we propose a correlation with a strong physical background based on a corresponding-states (CS) approach to predict the viscosity from the temperature and the density of a large variety of systems for all stable thermodynamic states (gas, liquid, and supercritical). In particular, this correlation is applicable to predict the viscosity of sour/acid-gas mixtures, whatever the thermodynamic conditions. This approach is based on the Lennard-Jones (LJ) fluid model, which has been studied extensively thanks to molecular-dynamics (MD) simulations over a wide range of thermodynamic conditions. This fluid model can be extended to deal with polar molecules such as CO2 or H2S without a loss of accuracy. First, we demonstrate that the proposed physically based correlation is able to provide an excellent estimation of the viscosity [with average absolute deviations (AADs) below 5%] of pure compounds, including normal-alkanes, CO2, or even H2S, whatever the thermodynamic conditions (gas, liquid, or supercritical). Then, using a one-fluid approximation and a set of combining rules, the correlation is applied to various fluid mixtures in a fully predictive way (i.e., without any additional fitted parameters). Using this scheme, the deviations between predictions and measurements are as low as those on pure fluids using temperature and density as inputs. The viscosity of natural- and acid-gas mixtures at reservoir conditions is shown to be very well predicted by the proposed scheme. In addition, it is shown that this correlation can also be applied to predict reasonably the viscosity of asymmetric high-pressure mixtures, even in the liquid phase. This physically based approach is easy to include in any simulation software as long as, apart from temperature and density, the only inputs--the molecular parameters of each species--can be estimated from the critical temperature and the critical volume when not known

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Section: Introductionmentioning

confidence: 80%

Section: Introductionmentioning

confidence: 99%

High-Pressure Acid-Gas Viscosity Correlation

Galliéro¹,

Boned²,

Baylaucq³

et al. 2010

SPE Journal

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“…In the case of H 2 S, there is practically no data because of its toxicity. This lack of information is even pronounced concerning transport properties such as viscosity (Galliero and Boned (2008), Liley et al (1998), Schmidt et al (2008)). …”

Section: Data Bankmentioning

confidence: 99%

Uncertainty in sour gas viscosity estimation and its impact on inflow performance and production forecasting

Elsharkawy

Aladwani

Alostad

2015

Journal of Natural Gas Science and Engineering

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“…The effects of suction pressure on NA-AQ phase equilibrium in porous media can also be taken into account by TMGAS, considering the proper phase pressure in the calculation of mixture components fugacity, as suggested by Firoozabadi (1999). The departure enthalpy can be computed using either the PR or the LK EOS (Lee and Kesler 1975), whereas the dynamic viscosity can be evaluated using either the Friction Theory Model (Quiňones-Cisneros et al 2001;Schmidt et al 2008), the LBC (Lohrenz et al 1964) model or the Galliero and Boned (2008) model. Friction Theory and Galliero-Boned models were developed to describe also the viscosity of sour mixtures with important amounts of H 2 S. Brine properties are evaluated in TMGAS using enhanced versions of the correlations implemented in the EWASG EOS module (Battistelli et al 1997) for water and sodium chloride mixtures initially developed for geothermal reservoir applications.…”

Section: The Tmgas Eos Modulementioning

confidence: 99%

Injection of Acid Gas Mixtures in Sour Oil Reservoirs: Analysis of Near-Wellbore Processes with Coupled Modelling of Well and Reservoir Flow

2010

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The reinjection of sour or acid gas mixtures is often required for the exploitation of hydrocarbon reservoirs containing remarkable amounts of acid gases (H 2 S and CO 2 ) to reduce the environmental impact of field exploitation and provide pressure support for enhanced oil recovery (EOR) purposes. Sour and acid gas injection in geological structures can be modelled with TMGAS, a new Equation of State (EOS) module for the TOUGH2 reservoir simulator. TMGAS can simulate the two-phase behaviour of NaCl-dominated brines in equilibrium with a non-aqueous (NA) phase, made up of inorganic gases such as CO 2 and H 2 S and hydrocarbons (pure as well as pseudo-components), up to the high pressures (∼100 MPa) and temperatures (∼200 • C) found in deep sedimentary basins. This study is focused on the near-wellbore processes driven by the injection of an acid gas mixture in a hypothetical high-pressure, under-saturated sour oil reservoir at a well-sector scale and at conditions for which the injected gas is fully miscible with the oil. Relevant-coupled processes are simulated, including the displacement of oil originally in place, the evaporation of connate brine, the salt concentration and consequent halite precipitation, as well as non-isothermal effects generated by the injection of the acid gas mixture at temperatures lower than initial reservoir temperature. Non-isothermal effects are studied by modelling in a coupled way wellbore and reservoir flow with a modified version of the TOUGH2 reservoir simulator. The described approach is limited to single-phase wellbore flow conditions occurring when injecting sour, acid or greenhouse gas mixtures in high-pressure geological structures.

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Dynamic viscosity estimation of hydrogen sulfide using a predictive scheme based on molecular dynamics

Cited by 16 publications

References 17 publications

High-Pressure Acid-Gas Viscosity Correlation

High-Pressure Acid-Gas Viscosity Correlation

Uncertainty in sour gas viscosity estimation and its impact on inflow performance and production forecasting

Injection of Acid Gas Mixtures in Sour Oil Reservoirs: Analysis of Near-Wellbore Processes with Coupled Modelling of Well and Reservoir Flow

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