Hydrate Formation during Transport of Natural Gas Containing Water and Impurities (original) (raw)
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The upper limit of water content permitted in a natural gas stream during its pipeline transport without a risk of hydrate formation is a complex issue. We propose a novel thermodynamic scheme for investigation of different routes to hydrate formation, with ideal gas used as reference state for all components in all phases including hydrate phase. This makes comparison between different hydrate formation routes transparent and consistent in free energy changes and associated enthalpy change. From a thermodynamic point of view natural gas hydrate can form directly from water dissolved in natural gas but quite unlikely due to limitations in mass and. The typical industrial way to evaluate risk of hydrate formation involves calculation of water condensation from gas and subsequent evaluation of hydrate from condensed water and hydrate formers in the natural gas. Transport pipes are rusty even before they are mounted together to transport pipelines. This opens up for even other routes to hydrate formation which starts with water adsorbing to rust and then leads to hydrate formation with surrounding gas. Rust consist on several iron oxide forms but Hematite is one of the most stable form and is used as a model in this study, in which we focus on maximum limits of water content in various natural gas mixtures that can be tolerated in order to avoid water dropping out as liquid or adsorbed and subsequently forming hydrate. Calculations for representative gas mixtures forming structure I and II hydrates are discussed for ranges of conditions typical for North Sea. The typical trend is that the estimated tolerance for water content is in the order of 20 times higher if these numbers are based on water dew-point rather than water dropping out as adsorbed on Hematite. For pure methane the maximum limits of water to be tolerated decrease with increasing pressures from 50 to 250 bars at temperatures above zero Celsius and up to six Celsius. Pure ethane and pure propane show the opposite trend due to the high density non-polar phase at the high pressures. Typical natural gas mixtures is, however, dominated by the methane so for systems of 80 per cent methane or more the trend is similar to that of pure methane with some expected shifts in absolute values of water drop-out mole-fractions. NOMENCLATURE C Number of components in the Gibbs phase rule E P Potential energy [kJ/mol] F Number of degrees of freedom in the Gibbs phase rule í µí°¹ Free energy [kJ/mol] í µí± Free energy density [kJ/(mol m 3)] f i Fugacity [Pa] g(r) Radial distribution function (RDF) Gibbs free energy [kJ/mol] Gibbs free energy of inclusion of component in cavity type [kJ/mol] Enthalpy [kJ/mol] Cavity partition function of component in cavity type k Cavity type index K Ratio of gas mole-fraction versus liquid mole-fraction for the same component (gas/liquid K-values) N i Number of molecules
Research and Reviews: Journal of Chemistry, 2016
ransport of hydrocarbon on the seafloor of the North Sea involves conditions of methane hydrate formation for most of the transport conditions from delivery to the receiving end. Hydrate stability regions are further extended through additional content of ethane. The critical question is therefore whether water will drop out from the gas and how it will drop out. Water can obviously condense out as liquid water, as has been the usual basis for hydrate risk evaluation schemes. Pipelines are rusty even before they are placed out on the seafloor and the question is if the water will benefit from dropping out onto these rusty surfaces at lower concentrations than dew-point concentrations for the same system at local temperatures and pressures. In this work we have used state of the art theoretical models to estimate maximum water content before condensation, and similar for adsorption on Hematite (rust). It is found that the maximum content of water that would be permitted for dew-point...
Low Temperature Water Content in Natural Gas Systems: New Measurements and Modelling
2014
Natural gas produced from a reservoir or withdrawn from a gas storage reservoir will contain water, which during transport or rapid expansion can condense and potentially form gas hydrates. Natural gas should be dry to a controlled water dew point to avoid hydrate as well as to minimize corrosion problems in processes and transport lines. Knowing the water content in equilibrium with hydrate is essential for determining the dehydration requirements for a given gas system at given operating conditions. In this communication, we report new experimental data for the water content of a natural gas mixture in equilibrium with hydrates at pressures range from 50 to 200 bar and temperatures down to-20°C. The measurements have been made on equilibrated samples taken from a highpressure variable volume hydrate cell using an analyser based upon Tuneable Diode Laser Absorption Spectroscopy (TDLAS) technology. These new data along with literature data were used to validate the predictions of a thermodynamic model using the Cubic-Plus-Association equation of state.
Journal of Chemical & Engineering Data, 2018
Carbon dioxide from the Sleipner gas field in the North Sea has now been injected into the Utsira Formation for more than 20 years. A million tons of carbon dioxide per year is transported and injected. Conditions of temperatures and pressures in the injection pipeline as well as inside the reservoir are outside hydrate-forming conditions. Transport pipelines, on the other hand, are subject to low temperatures and high pressures, which can potentially lead to hydrate formation. In this work, we examine some possible routes to hydrate formation and the consequences for maximum amounts of water that can be permitted to follow the gas. A conventional hydrate risk evaluation involves calculation of water dew point concentrations in the gas as an upper tolerance limit for preventing liquid water to drop out from the gas and eventually form hydrates. Pipelines are rusty even from the moment they are placed on the seafloor in the North Sea. Initially this rust consists of various forms of iron oxides. Hematite (Fe 2 O 3) is one of the most stable of these and is used as a model for rust in this work. A second route to hydrate formation involves adsorption of water on rusty surfaces. Earlier work in the open literature indicates that the chemical potential of adsorbed water may be substantially lower than the chemical potential of liquid water at the same temperature and pressure. This opens up a path for heterogeneous hydrate nucleation toward the pipeline walls. The chemical potential of the first few adsorbed water layers (roughly 1 nm) is too low for them to form hydrates, but outside of that the liquid structure is similar to that of liquid water and can form hydrates. The estimated maximum water content that can be permitted on the basis of the water dew point was found to be on the order of 20 times higher than the amount that would be tolerated if adsorption on hematite were the tolerance criterion. This ratio is similar for the original Sleipner gas with carbon dioxide and the hydrocarbon phase after separation of the carbon dioxide. As expected, the difference is not substantial in absolute tolerance given that the carbon carbon dioxide content is less than 3.5 mol %. Another aspect is the possibility of forming more than one type of hydrate. The dominating components in the mixture are methane, ethane, and carbon dioxide, which are structure I formers. The presence of 3 mol % propane and 0.25 mol % isobutane will have a substantial impact on the dew point curve and thus also the whole phase envelope of the system. The solubility of water in condensed hydrocarbon is qualitatively different and increases with pressure, in contrast to the solubility in supercritical methane. However, the relative tolerance limits between the dew point criterion and the adsorption criterion is found to be on the same order of magnitude as for the gas mixture. The pipeline walls are typically the coldest regions of the pipeline and rarely exceed 280 K for the North Sea seafloor. Sensitivity analyses of the maximum tolerance for water as a function of propane content in methane and in carbon dioxide are also conducted and confirm the relative tolerance limits.
Impacts of CO2 and H2S on the risk of hydrate formation during pipeline transport of natural gas
Frontiers of Chemical Science and Engineering, 2019
Evaluation of maximum content of water in natural gas before water condenses out at a given temperature and pressure is the initial step in hydrate risk analysis during pipeline transport of natural gas. The impacts of CO 2 and H 2 S in natural gas on the maximum mole-fractions of water that can be tolerated during pipeline transport without the risk of hydrate nucleation has been studied using our novel thermodynamic scheme. Troll gas from the North Sea is used as a reference case, it contains very negligible amount of CO 2 and no H 2 S. Varying mole-fractions of CO 2 and H 2 S were introduced into the Troll gas, and the effects these inorganic impurities on the water tolerance of the system were evaluated. It is observed that CO 2 does not cause any distinguishable impact on water tolerance of the system, but H 2 S does. Water tolerance decreases with increase in concentration of H 2 S. The impact of ethane on the system was also investigated. The maximum mole-fraction of water permitted in the gas to ensure prevention of hydrate formation also decreases with increase in the concentration of C 2 H 6 like H 2 S. H 2 S has the most impact, it tolerates the least amount of water among the components studied.
Data and prediction of water content of high pressure nitrogen, methane and natural gas
New data for the equilibrium water content of nitrogen, methane and one natural gas mixture are presented. The new binary data and existing binary sets were compared to calculated values of dew point temperature using both the CPA (Cubic-Plus-Association) EoS and the GERG-water EoS. CPA is purely predictive (i.e. all binary interaction parameters are set equal to 0), while GERG-water uses a temperature dependent interaction parameter fitted to published data. The GERG-water model is proposed as an ISO standard for determining the water content of natural gas. The data sets for nitrogen cover the range 233–348 K, and 5–200 bar. Six of these sets, including this work, are well described by both models; five of them have an average dew point temperature deviation of less than 1 K. The seventh set must be rejected, since the data points are too far removed from the other sets. The 13 sets for methane cover the range 233–373 K and 5–249 bar. Seven of these sets have an average bias less than 1 K, while another five have an average deviation less than 2 K. One set must be again rejected, having data too far from the other sets. Two of the remaining sets should probably be rejected as well, since they have large scatter. The data sets that have been measured at low pressures extrapolate well towards the ideal equilibrium values. The two models show similar results, but differ at high pressure and/or temperature. CPA is shown to extrapolate well for methane–water to 1000 bar and 573 K, and our conclusion is that GERG-water must be used with caution outside its specified working range. For some selected natural gas mixtures the two models also perform very much alike. The water content of the mixtures decreases with increasing amount of heavier components, and it seems that both models slightly over-predict the water content of such mixtures.
Industrial & Engineering Chemistry Research - IND ENG CHEM RES, 2008
In this report, we present a semiempirical method for determining water content of methane-rich hydrocarbon gas in equilibrium with gas hydrates. A model based on equality of fugacity concept for estimating the water content of methane in equilibrium with gas hydrates is first introduced. The model estimates the water content of methane using the vapor pressure of the empty hydrate lattice and the partial molar volume of water in the empty hydrate as well as pressure and temperature of the system. In order to extend the capabilities of this tool for determining water content of methane-rich hydrocarbon gases in equilibrium with gas hydrates, a correction factor, which is a function of gas gravity and the system pressure, is used. The predictions of the developed technique are found in acceptable agreement with independent experimental data (not used in developing this method) reported in the literature and the result of a previously reported predictive tool, demonstrating its reliability for estimating the water content of methane-rich hydrocarbon gas in equilibrium with gas hydrates.
Journal of Geophysical Research: Solid Earth
Methane hydrate saturation estimates from remote geophysical data and borehole logs are needed to assess the role of hydrates in climate change, continental slope stability, and energy resource potential. Here we present laboratory hydrate formation/dissociation experiments in which we determined the methane hydrate content independently from pore pressure and temperature and from electrical resistivity. Using these laboratory experiments, we demonstrate that hydrate formation does not take up all the methane gas or water even if the system is under two phase water-hydrate stability conditions and gas is well distributed in the sample. The experiment started with methane gas and water saturations of 16.5% and 83.5%, respectively; during the experiment, hydrate saturation proceeded up to 26% along with 12% gas and 62% water remaining in the system. The coexistence of hydrate and gas is one possible explanation for discrepancies between estimates of hydrate saturation from electrical and acoustic methods. We suggest that an important mechanism for this coexistence is the formation of a hydrate film enveloping methane gas bubbles, trapping the remaining gas inside.
Thermodynamic Modeling of Natural Gas Systems Containing Water
Industrial & Engineering Chemistry Research, 2013
As the need for dew point specifications remains very urgent in the natural gas industry, the development of accurate thermodynamic models, which will match experimental data and will allow reliable extrapolations, is needed. Accurate predictions of the gas phase water content in equilibrium with a heavy phase were previously obtained using cubic plus association (CPA) coupled with a solid phase model in the case of hydrates, for the binary systems of water−methane and water−nitrogen and a few natural gas mixtures. In this work, CPA is being validated against new experimental data, both water content and phase equilibrium data, and solid model parameters are being estimated for four natural gas main components (methane, ethane, propane, and carbon dioxide). Different tests for the solid model parameters are reported, including vaporhydrate-equilibria (VHE) and liquid-hydrate-equilibria (LHE) calculations, structural transitions, and predictions at low temperatures. Furthermore, model predictions for representative multicomponent mixtures are presented and compared against the ISO-standard GERG-water model and other selected models. In most cases, very good agreement with experimental data is obtained.
ACS Omega, 2021
The estimation of thermodynamic equilibrium conditions of methane hydrates in the presence of crude oil based on experiments is shown in this research work. This pipeline system replicated the gas-dominant multiphase transmission pipelines at deep-sea regions. An experimental study is done by the usage of a Raman gas hydrate reactor. The pressure was maintained in the range of 3−8 MPa for the experimental study. The water cut is kept constant throughout the system as 30%. Initially, the experimental setup is calibrated by using carbon dioxide gas. Then, methane hydrates are formed with and without crude oil. The methane hydrates that are created without the presence of crude oil are validated with simulation that is performed using CSMGEM, PVTSIM software, and literature data. Then, the thermodynamic conditions are found for the methane hydrate formation in the presence of crude oil with an addition of a 15% oil cut to the system. From these results, the phase behavior of a multiphase system is evaluated. The formation of methane hydrates in the system was found to be affected by the presence of an additional oil phase that exhibited an inhibition behavior. This research validates all the multiphase systems that contain similar hydrocarbon and gas compositions.