Effect of Acid Gases on Methane Hydrate Stability Zone (original) (raw)
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Hydrate phase equilibria of gaseous mixtures of methane+ carbon dioxide+ hydrogen sulfide
In this communication, experimental dissociation conditions for clathrate hydrates of methane + carbon dioxide + hydrogen sulfide in liquid water -hydrate-vapor equilibrium are reported. The dissociation temperatures and pressures are in the ranges of (273.9 to 288.25) K and (0.207 to 1.94) MPa, respectively. Concentrations of methane, carbon dioxide and hydrogen sulfide in the feed gas are also varied. To perform the measurements, an isochoric pressure-search method was used. The dissociation data obtained in the present work are compared with the predictions of a thermodynamic model (HWHYD version 1.
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.
STUDY OF THE STABILITY OF METHANE HYDRATES IN NORMAL CONDITIONS
2017
The problems of accumulation, transport and storage of gases and gas mixtures exist in many cases. Often the existent technologies appear ineffective for transporting gas with pipelines, as condensate or compressed gas. Therefore, the transportation and storage of gas in hydrate form can be an alternative method to traditional technologies. Preservation of gas hydrate blocks can last for some time at non-equilibrium conditions. The thermodynamic parameters of forced conservation of gas hydrate blocks are determined with Finite – difference scheme and verified experimentally.
The Journal of Chemical Thermodynamics, 2007
A new method, a molecular thermodynamic model based on statistical mechanics, is employed to predict the hydrate dissociation conditions for binary gas mixtures with carbon dioxide, hydrogen, hydrogen sulfide, nitrogen, and hydrocarbons in the presence of aqueous solutions. The statistical associating fluid theory (SAFT) equation of state is employed to characterize the vapor and liquid phases and the statistical model of van der Waals and Platteeuw for the hydrate phase. The predictions of the proposed model were found to be in satisfactory to excellent agreement with the experimental data.
Effects of salinity on methane gas hydrate system
Science in China Series D: Earth Sciences, 2007
Using an approximately analytical formation, we extend the steady state model of the pure methane hydrate system to include the salinity based on the dynamic model of the methane hydrate system. The top and bottom boundaries of the methane hydrate stability zone (MHSZ) and the actual methane hydrate zone (MHZ), and the top of free gas occurrence are determined by using numerical methods and the new steady state model developed in this paper. Numerical results show that the MHZ thickness becomes thinner with increasing the salinity, and the stability is lowered and the base of the MHSZ is shifted toward the seafloor in the presence of salts. As a result, the thickness of actual hydrate occurrence becomes thinner compared with that of the pure water case. On the other hand, since lower solubility reduces the amount of gas needed to form methane hydrate, the existence of salts in seawater can actually promote methane gas hydrate formation in the hydrate stability zone. Numerical modeling also demonstrates that for the salt-water case the presence of methane within the field of methane hydrate stability is not sufficient to ensure the occurrence of gas hydrate, which can only form when the methane concentration dissolved in solution with salts exceeds the local methane solubility in salt water and if the methane flux exceeds a critical value corresponding to the rate of diffusive methane transport. In order to maintain gas hydrate or to form methane gas hydrate in marine sediments, a persistent supplied methane probably from biogenic or thermogenic processes, is required to overcome losses due to diffusion and advection.
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
Hydrate Formation during Transport of Natural Gas Containing Water and Impurities
Journal of Chemical & Engineering Data, 2016
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.
Effect of H2S Content on Thermodynamic Stability of Hydrate Formed from CO2/N2Mixtures
Journal of Chemical & Engineering Data, 2017
Huge resources of energy in the form of natural gas hydrates are widely distributed worldwide in permafrost sediments as well as in offshore sediments. A novel technology for combined production of these resources and safe long-term storage of carbon dioxide is based on the injection of carbon dioxide injection into in situ methane hydrate-filled sediments. This will lead to an exchange of the in situ methane hydrate over to carbon dioxide-dominated hydrate and a simultaneous release of methane gas. Recent theoretical and experimental results indicate that the conversion from natural gas hydrate to carbon dioxide hydrate and mixed carbon dioxide/methane hydrate follows two primary mechanisms. Direct solid state transformation is possible, but very slow. The dominating mechanism involves formation of a new hydrate from injected carbon dioxide and associated dissociation of the in situ natural gas hydrate by the released heat. Nitrogen is frequently added in order to increase gas permeability and to reduce blocking due to new hydrate formation, and will as such also reduce the relative impact of the fast mechanism on the conversion rates. In addition to carbon dioxide also other sour gases, such as hydrogen sulfide, may follow the carbon dioxide from the sour gas removal process. Hydrogen sulfide is a very aggressive hydrate former. It is abundant in various amounts in thermogenic hydrocarbon systems. In this work we investigate the sensitivity of possible additions of hydrogen sulfide in carbon dioxide/nitrogen mixtures, and how the ability to form new hydrate changes with the additions of hydrogen sulfide. This analysis is applied to four case studies: (1) Bjørnøya gas hydrate basin, (2) the Nankai field in Japan, (3) the Hikurangi Margin in New Zealand, and (4) a gas hydrate basin in SouthWest Taiwan. The hydrate saturations found in these fields vary over a range from 25−80%. Pressures range from 4−22.6 MPa and temperatures from 275.15−292.77 K. For all these ranges of conditions, even 1% H 2 S will substantially increase the ability to form new hydrate from an injected CO 2 /N 2 mixture containing H 2 S. Except for the most shallow of the reservoirs (Bjørnøya) 1% H 2 S results in formation of a new hydrate for all concentrations of CO 2 in N 2 above 1%. Implementation of results from this work into a reservoir simulator is a natural follow-up which can shed light on the macroscopic consequences in term of possible local blocking of the flow due to content of H 2 S. The mass transport, mass balances, and energy balances in a reservoir simulator are also needed for a more detailed evaluation on how the content of H 2 S and CO 2 changes over time and location in the reservoir due to various processes in addition to hydrate formation. H 2 S and CO 2 dissolves significantly in pore water, and also adsorbs well on various sediment minerals.