scholarly journals First-principles microkinetic study of methane and hydrogen sulfide catalytic conversion to methanethiol/dimethyl sulfide on Mo6S8 clusters: activity/selectivity of different promoters

2019 ◽  
Vol 9 (17) ◽  
pp. 4573-4580 ◽  
Author(s):  
Adam A. Arvidsson ◽  
William Taifan ◽  
Anders Hellman ◽  
Jonas Baltrusaitis
Keyword(s):  
Carbon Dioxide ◽  
Hydrogen Sulfide ◽  
Natural Gas ◽  
First Principles ◽  
Dimethyl Sulfide ◽  
Large Fraction ◽  
Catalytic Conversion ◽  
Sour Gas

A large fraction of the global natural gas reserves is in the form of sour gas, i.e. contains hydrogen sulfide (H2S) and carbon dioxide (CO2), and needs to be sweetened before utilization.

Solubility of Sulfur in Hydrogen Sulfide and Sour Gases

1980 ◽  
Vol 20 (05) ◽  
pp. 377-384 ◽  
Author(s):  
E. Brunner ◽  
W. Woll
Keyword(s):  
Carbon Dioxide ◽  
Hydrogen Sulfide ◽  
Natural Gas ◽  
Gas Phase ◽  
Elemental Sulfur ◽  
Gas Production ◽  
Liquid Sulfur ◽  
Fugacity Coefficients ◽  
Production Tubing ◽  
Sour Gas

Description of Problem In recent years the search for natural gas has yielded many reserves that contain high concentrations of hydrogen sulfide. Production of sour gas initially was on a limited scale but since has increased considerably as a result of price increases for fossil fuels. Substantial quantities of sulfur now are produced from the hydrogen sulfide in these natural gas sources. In several of these natural gas fieldse.g., in Canada and north Germany-gas production is hampered severely due to the presence of elemental sulfur dissolved in the gas. The gas-bearing deposits are interspersed with elemental sulfur, which is dissolved to a greater or lesser extent in the sour gas, the solubility being strongly dependent on the pressure, temperature, and composition of the gas. It is well-known that the solubility of sulfur increases with increasing pressure, temperature, and hydrogen sulfide content. As a result of the geothermal temperature profile, the gas stream cools as it rises up the production tubing and there is a drop in pressure due to frictional effects. Consequently, the solubility drops and sulfur is deposited when the solubility limit is exceeded. The gases desolved in the liquid sulfur- principally hydrogen sulfide and carbon dioxide- lead to a lowering of the freezing point. At temperatures between 393.15 and 373.15 K, the sulfur begins to solidify in the line, blocking the tubing and bringing gas production to a standstill. To prevent such blockages, suitable solvents are pumped into the well via an annular space surrounding the production tubing to dissolve the sulfur, which then is carried to the surface with the gas stream. A discussion of the technological problems involved in this process is beyond the scope of this paper. It would be of great value and solving the problem associated with the production of sour natural gas to have more data on, among other things, the solubility of sulfur in compressed sour gases of various compositions over a range of temperatures and pressures. There is little literature on the solubility of sulfur in different natural gases. Kennedy and Wieland reported the results of measurements on the methane/carbon-dioxide/hydrogen-sulfide/sulfur system at pressures up to 40 MPa and temperatures up to 394.15 K Roof examined the solubility of sulfur in hydrogen sulfide up to 30 MPa and 383.15 K, but his results differ considerably from those of Kennedy and Wieland. Swift has published data on the solubility of sulfur in hydrogen sulfide at pressures between 35 and 140 MPa and temperatures between 394.15 and 450.15 K. Using a gas saturation method, we now have measured the solubility of sulfur in pure hydrogen sulfide and in four synthetic sour gas mixtures composed of H2S, CO2, CH4, and N2 in the temperature range of 373.15 to 433.15 K and at pressures up to 60 MPa. Solubility of Solids and Liquids in Compressed Gases It is particularly important that gas-phase fugacity coefficients be employed when calculating the solubility of a solid or a high-boiling liquid in a compressed gas. In general, these fugacity coefficients must be determined experimentally. Corrections for the nonideality of the gas phase, as are employed at lower pressures, can lead to completely erroneous results here. A consideration of both systems-solid/liquid and liquid/liquid is presented in the following. P. 377＾

Supersonic separation technology for carbon dioxide and hydrogen sulfide removal from natural gas

2021 ◽  
Vol 288 ◽  
pp. 125689
Author(s):  
Xuewen Cao ◽  
Dan Guo ◽  
Wenjuan Sun ◽  
Pan Zhang ◽  
Gaoya Ding ◽  
...  
Keyword(s):  
Carbon Dioxide ◽  
Hydrogen Sulfide ◽  
Natural Gas ◽  
Separation Technology ◽  
Sulfide Removal ◽  
Hydrogen Sulfide Removal

scholarly journals Water Scrubbing for Removal of CO2 (Carbon Dioxide) and H2S (Hydrogen Sulfide) in Biogas from Manure

KnE Energy ◽  
2015 ◽  
Vol 2 (2) ◽  
pp. 126 ◽  
Author(s):  
Mufidatul Islamiyah ◽  
Totok Soehartanto ◽  
Ridho Hantoro ◽  
Arif Abdurrahman
Keyword(s):  
Carbon Dioxide ◽  
Hydrogen Sulfide ◽  
Natural Gas ◽  
Animal Health ◽  
Environmentally Friendly ◽  
Purification Process ◽  
Basic Ingredient ◽  
Biogas Purification

<p>Purifying biogas from CO2 (carbon dioxide) and H2S (hydrogen sulfide) needs to be done to improve the quality of the biogas in the fuel. The presence of H2S in biogas can cause corrosive to the equipment, in addition to this, H2S is also dangerous for human and animal health. CO2 contained in Biogas is also an impurity that can cause corrosive beside H2S so the contained in biogas is also an impurity that can cause corrosive, so the purification process needs to be done in order to qualify biogas as natural gas which environmentally friendly and safe for health. The basic ingredient of biogas purification using water scrubbers base ingredients are water, which flowed pressurized biogas purification column from the bottom, of the column in order to reduce CO2 and H2S gases. The result of purification by using this method was that the levels of H2S in biogas reduced by 32.8 % while the CO2 content decreased by 21.2 %. It can be concluded that the H2S gas more soluble in the water compared with CO2, as H2S gas has higher efficiency removal from CO2. </p><p><strong>Keywords</strong>: biogas; carbon dioxide; hydrogen sulfide, waters scrubber</p>

Novel Porous Organic Polymer for the Concurrent and Selective Removal of Hydrogen Sulfide and Carbon Dioxide from Natural Gas Streams

2020 ◽  
Vol 12 (42) ◽  
pp. 47984-47992
Author(s):  
Mahmoud M. Abdelnaby ◽  
Kyle E. Cordova ◽  
Ismail Abdulazeez ◽  
Ahmed M. Alloush ◽  
Bassem A. Al-Maythalony ◽  
...  
Keyword(s):  
Carbon Dioxide ◽  
Hydrogen Sulfide ◽  
Natural Gas ◽  
Selective Removal ◽  
Organic Polymer ◽  
Porous Organic Polymer ◽  
Gas Streams

Research on Corrosion of Well-Bore Tube and Anticorrosive Measure of Tazhong-1 Gas Field

2011 ◽  
Vol 108 ◽  
pp. 308-313 ◽  
Author(s):  
Shan Fa Tang ◽  
Xue Yang ◽  
Da Wei Wu
Keyword(s):  
Carbon Dioxide ◽  
Hydrogen Sulfide ◽  
Natural Gas ◽  
Corrosion Inhibitors ◽  
Produced Water ◽  
Formation Water ◽  
Well Bore ◽  
Gas Field ◽  
Production Wells ◽  
Sulfide Corrosion

Natural gas of Tazhong-1 gas field contains 7.7% carbon dioxide and 2.31% hydrogen sulfide, and produced water salinity is up to 140000mg/L,the well-bore tube has seriously potential corrosion destructive with natural gas being exploited. Based on the corrosion type partition of down-hole tube for eighteen production wells of Tazhong-1 gas field, P110,P110S and P110SS corrosion behavior were investigated under the conditions of simulated formation water containing carbon dioxide or hydrogen sulfide/carbon dioxide, and corrosion inhibitors were chosen to meet need of anticorrosion of Tazhong-1 gas field. The results show that fifteen wells in eighteen production wells belong to hydrogen sulfide corrosion of both hydrogen sulfide and carbon dioxide influence. Other wells are singular carbon dioxide corrosion. The most severe corrosion of three types of down-hole tubes all occurs at 90°C in both corrosion media, and their corrosion resistance order is respectively P110>P110S>P110SS and P110S>P110SS>P110 under the conditions of simulated formation water containing carbon dioxide or hydrogen sulfide and carbon dioxide. The selected anti-temperature corrosion inhibitors (YU-1、YU-4) can control the corrosion rate of three types of down-hole tubular goods within 0.076mm/a in simulated formation water media with carbon dioxide (PCO2=0.08～4.64MPa) or hydrogen sulfide and carbon dioxide (PH2S/Pco2=1.3/4.64Mpa) while added amount of the inhibitor is 120～300mg/L or 200mg/L. All of these provide technical support for safe and fast development of Tazhong-1 gas field.

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