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Frontiers of Chemical Science and Engineering

ISSN 2095-0179

ISSN 2095-0187(Online)

CN 11-5981/TQ

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2018 Impact Factor: 2.809

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Front. Chem. Sci. Eng.    2019, Vol. 13 Issue (3) : 616-627    https://doi.org/10.1007/s11705-019-1795-2
VIEWS & COMMENTS
Impacts of CO2 and H2S on the risk of hydrate formation during pipeline transport of natural gas
Solomon A. Aromada1(), Bjørn Kvamme2
1. Department of Physics and Technology, University of Bergen, 5007 Bergen, Norway
2. Strategic Carbon LLC, Vestre Holbergsallmenningen 17, 5011 Bergen, Norway
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Abstract

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 CO2 and H2S 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 CO2 and no H2S. Varying mole-fractions of CO2 and H2S 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 CO2 does not cause any distinguishable impact on water tolerance of the system, but H2S does. Water tolerance decreases with increase in concentration of H2S. 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 C2H6 like H2S. H2S has the most impact, it tolerates the least amount of water among the components studied.
Keywords hydrate      hydrogen Sulphide      CO2      dew point      pipeline     
Corresponding Author(s): Solomon A. Aromada   
Online First Date: 18 April 2019    Issue Date: 22 August 2019
 Cite this article:   
Solomon A. Aromada,Bjørn Kvamme. Impacts of CO2 and H2S on the risk of hydrate formation during pipeline transport of natural gas[J]. Front. Chem. Sci. Eng., 2019, 13(3): 616-627.
 URL:  
https://academic.hep.com.cn/fcse/EN/10.1007/s11705-019-1795-2
https://academic.hep.com.cn/fcse/EN/Y2019/V13/I3/616
Fig.1  Schematic 2-dimensional illustration of H2S behaviour in a hydrate cage [21,22]. The darker circles represent water oxygens in the walls of the cavity, and the grey circles show water hydrogens that would like to line along the water connection. The other hydrogens will have variable tipping (in and out of cavity) and on the average the sampled net balance [21,22] is a ?ve electrostatic field inward in the hydrate cavity. The H2S has a+ve centre on the central “S” (represented in orange colour), thus, the rotational modes of H2S in the hydrate cavity result in an average+ve electrostatic field facing outward toward the walls of the hydrate cavity
Fig.2  Estimated equilibrium pressures for a gas mixture containing 92% of methane and 8% of CO2 compared with experimental data and calculated resulted results [35]
Fig.3  Estimated equilibrium pressures for a gas mixture containing 97% of methane and 3% of H2S compared with experimental data [36]
Fig.4  Estimated equilibrium pressures for a gas mixture containing 82% of methane, 12.6% of CO2 and 5.4% of H2S compared with experimental data [37]
Fig.5  Estimated equilibrium pressures for a gas mixture containing 82.45% of methane, 10.77% of CO2 and 6.78% of H2S compared with experimental data [38]
Fig.6  Estimated equilibrium pressures for a gas mixture containing 17.4% of methane and 70.5% of ethane, and 12.1% of propane compared with experimental data [39–41]
Fig.7  Estimated equilibrium pressures for a natural gas with composition of 87.8% of methane, 4% ethane, 2.1% of propane, 1.5% of isobutane, 1.1% of nitrogen, 3.25% of CO2 and 0.25% of H2S compared with experimental data [34]
Components Well-head fluid Separator 1
0°C and 70 bar 1°C and 70 bar
Methane, C1 0.9592 0.9597
Ethane, C2 0.0349 0.0347
Propane, C3 0.0031 0.0030
Isobutane, iC4 0.0028 0.0026
Tab.1  Normalized compositions of Troll gas [42]
Troll gas Reduction in maximum water content a)/%
Dew-point 274 K Dew-point 280 K Hematite 274 K Hematite 280 K
0.01 H2S on Troll gas 1.1 0.2 0.4 0.4
0.05 H2S on Troll gas 2.3 1.3 2.7 1.5
0.10 H2S on Troll gas 4.1 2.9 4.5 3.5
0.01 CO2 on Troll gas 0.8 No reduction No reduction 0.4
0.05 CO2 on Troll gas 0.8 No reduction No reduction 0.4
0.10 CO2 on Troll gas 0.9 0.01 No reduction 0.4
Tab.2  Summary of the impact of H2S and CO2 on the average maximum water content permitted in Troll gas during processing and pipeline transport for a pressure range of 50-170 bar
Fig.8  Impacts of introducing varying concentrations of H2S and CO2 and impact of varying the amount of C2H6 in Troll gas in respect of maximum content of water permitted before liquid water drops out at 50 bar and 274 K
Fig.9  Impacts of introducing varying concentrations of H2S and CO2 and impact of varying the amount of C2H6 in Troll gas in respect of maximum content of water permitted before liquid water is adsorb onto Hematite at 50 bar and 274 K
Fig.10  Maximum tolerance of water in gas mixtures to avoid liquid water drop out at 274 K
Fig.11  Maximum tolerance of water in gas mixtures to avoid adsorption of water on hematite at 274 K
Fig.12  Maximum tolerance of water in gas mixtures to avoid liquid water drop out at 280 K
Fig.13  Maximum tolerance of water in gas mixtures to avoid adsorption of water on hematite at 280 K
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