The presence of hydrogen sulfide (H2S) in natural gas necessitates a process known as gas sweetening. Natural gas containing H2S is commonly referred to as “sour gas.” This treatment is mandatory to make the gas safe and commercially viable for transport and use. The primary goal of sweetening is to remove acidic contaminants, H2S and carbon dioxide (CO2), which are typically found together. H2S removal is accomplished through various methods, from large-scale chemical absorption to non-regenerative scavenging systems, suited for different gas volumes and H2S concentrations.
Why Hydrogen Sulfide Must Be Removed
Hydrogen sulfide is a colorless gas recognizable by its characteristic “rotten egg” odor at low concentrations. It is highly toxic; exposure to concentrations as low as 10 parts per million (ppm) can desensitize the sense of smell, and higher levels can be fatal within minutes. Its toxicity necessitates removal to protect workers and end-users.
The gas is also extremely corrosive, especially when moisture is present. The combination of H2S and water forms weak acids that cause general internal corrosion in pipelines and processing equipment. H2S can also lead to sulfide stress cracking (SSC), a form of material degradation that reduces the structural integrity and lifespan of steel infrastructure.
Regulatory compliance mandates H2S removal before the gas can be sold or transported. Pipeline specifications require H2S levels to be reduced to very low concentrations, often below 4 ppmv, to protect the network and ensure product quality. Additionally, combustion of untreated sour gas produces sulfur dioxide (SO2), a major air pollutant and contributor to acid rain, making environmental regulations a driver for removal.
Large-Scale Chemical Absorption (Amine Treating)
The most common and economical method for removing high volumes and concentrations of H2S is chemical absorption, known as amine treating. This process uses an aqueous solution of alkanolamines to chemically react with the acidic H2S molecules in a contactor tower. Common alkanolamines used include Monoethanolamine (MEA), Diethanolamine (DEA), and Methyldiethanolamine (MDEA), which act as weak bases to absorb the acid gases.
Sour gas flows up through the absorber column while the “lean” amine solution flows down, facilitating the chemical reaction that binds the H2S to the amine. This reaction produces a sweetened gas stream that exits the top and a “rich” amine solution with absorbed acid gases that exits the bottom. The regenerative nature of this method allows the solvent to be reused.
The “rich” amine is sent to a separate regenerator, or stripper tower, where heat is applied, typically around \(225^{\circ}\text{F}\), to reverse the chemical reaction. Heating the solution breaks the bond between the amine and the H2S, releasing a concentrated stream of acid gas. The regenerated “lean” amine is then cooled and recycled back to the absorber, making amine treating an efficient, closed-loop system for large-scale operations.
Specialized Physical Absorption Methods
An alternative approach for H2S removal, particularly when the gas stream contains high concentrations of CO2 or requires deep purification, involves physical absorption methods. Unlike amine treating, which relies on a chemical reaction, physical solvents remove H2S based on its solubility in the solvent, a property governed by temperature and pressure. The H2S molecules simply dissolve into the solvent rather than reacting chemically.
Solvents such as Selexol (polyethylene glycol dimethylethers) or Rectisol (cold methanol) are commonly employed. H2S is absorbed under high pressure and low temperature in the contactor column. Regeneration is achieved by reducing the pressure, which causes the dissolved H2S to flash out of the liquid, requiring less heat input compared to chemical regeneration. This makes physical absorption suitable for streams with high acid gas content, as the solvent’s capacity is not limited by chemical stoichiometry.
Non-Regenerative Scavenging Systems
For situations involving small volumes of gas, intermittent production, or as a final purification step after a primary sweetening process, non-regenerative scavenging systems offer a straightforward solution. These systems use chemicals that react irreversibly with H2S to form stable, solid or liquid byproducts that are then disposed of, rather than regenerating the chemical for reuse. The sacrificial nature of the scavenger means it must be periodically replaced once saturated.
One common solid-phase system is the iron sponge process, which uses iron oxide to react with H2S to form iron sulfide. Liquid scavengers, such as triazine-based compounds, are widely used and injected directly into the gas stream where they react with the H2S to form a non-toxic liquid product. These methods are cost-effective for treating gas streams with low H2S concentrations, typically below 2,000 ppm, or for polishing the gas to meet stringent sales specifications.
Converting H2S into Usable Sulfur
The concentrated stream of H2S released from large-scale regenerative processes, known as acid gas, cannot be vented due to environmental regulations. This stream is sent to a Sulfur Recovery Unit (SRU), where the H2S is converted into elemental sulfur using the modified Claus process. The Claus process is a two-step reaction scheme that typically achieves a sulfur recovery efficiency of 95% to 98%.
The first step is the thermal stage, where approximately one-third of the H2S is combusted with air in a reaction furnace at temperatures above \(1800^{\circ}\text{F}\). This reaction converts the H2S into sulfur dioxide (SO2) and water. In the second, catalytic stage, the remaining H2S reacts with the SO2 in a 2:1 ratio over a catalyst, such as activated alumina, to produce elemental sulfur and water. The sulfur is condensed and recovered as a molten liquid after each catalytic reactor stage.