Describes the most chemical process most commonly used for sweetening natural gas.
This paper begins by illustrating the process most commonly used to remove hydrogen sulfide from natural gas. The paper then goes on to describe an alternative method used for the removal of hydrogen sulfide and describes the benefits of this method, as well as some of the problems associated with it. Additionally, the paper points out that the water content of natural gas is an important engineering consideration concerning the sweetening process and presents an overview of the properties of pure acid gases and water and hydrogen sulfide. The paper then goes on to outline and explain additional processes and engineering considerations concerning the removal of hydrogen sulfide and includes some cost estimates and comparisons of the processes.
Properties of H2S and CO2
Vapor / Liquid Properties of Pure Compounds
Vapor / Liquid Phase Behavior
Acid Gas Compression and Dehydration
Metallurgy
Acid Gas Dehydration
Acid Gas Injection Facilities
Cost Comparisons with Small Scale Sulfur Recovery Options
Operating Costs
Properties of H2S and CO2
Vapor / Liquid Properties of Pure Compounds
Vapor / Liquid Phase Behavior
Acid Gas Compression and Dehydration
Metallurgy
Acid Gas Dehydration
Acid Gas Injection Facilities
Cost Comparisons with Small Scale Sulfur Recovery Options
Operating Costs
“Sour natural gas contains hydrogen sulfide (H2S), which has to be removed to meet specifications for sales gas. Sour natural gas also contains carbon dioxide (CO2). The removal of CO2 and H2S, usually called acid gases, from sour natural gas is generally accomplished by means of a regenerative solvent. There are several amine solvents used for this purpose. Upon regeneration of the solvent, the acid gases are liberated, and are usually sent to a modified Claus plant, where the H2S is converted to elemental sulfur (Canjar & Manning 1967). The acid gas stream to the modified Claus plant consists of H2S, CO2, water vapor and minor amounts of hydrocarbon gas.”