Acid Gas Treating Process

Next to sales contract specifications, corrosion protection ranks highest among the reasons for the removal of acid gases. The partial pressure of the acid gases may be used as a measure to determine whether treatment is required. The partial pressure of a gas is defined as the total pressure of the system times the mole % of the gaseous component. Where CO2 is present with free water, a partial pressure of 30 psia or greater would indicate that CO2 corrosion should be expected. If CO2 is not removed, inhibition and special metallurgy may be required. Below 15 psia, CO2 corrosion is not normally a problem, although inhibition may be required.

H2S may cause hydrogen embrittlement in certain metals. Figures 7-1 and 7-2 show the H2S concentration at which the National Association of Corrosion Engineers (NACE) recommends special metallurgy to guard against H2S corrosion.

In the sulfide stress cracking region, appropriate metallurgy is required in line piping, pressure vessels, etc. There is a listing of acceptable steels in the NACE standard. Steels with a hardness of less than 22 Rockwell C hardness should be used in areas where sulfide-stress cracking is a problem.

The concentration of H2S required for sulfide-stress cracking in a multiphase gas/liquid system (Figure 7-2) is somewhat higher than in pure gas streams (Figure 7-1). The liquid acts as an inhibitor.

H2S concentration required for sulfide-sfress cracking in a pure gas system. (Courtesy of National Association t Corrosion Engineers,}

H2S concentration required for sulfide-sfress cracking in a pure gas system. (Courtesy of National Association t Corrosion Engineers,}

In addition to heavy hydrocarbons and water vapor, natural gas often contains other contaminants that may have to be removed. Carbon dioxide (CO2), hydrogen sulfide (H2S), and other sulfur compounds such as mercaptans are compounds that may require complete or partial removal for acceptance by a gas purchaser. These compounds are known as “acid gases.” H2S combined with water forms a weak form of sulfuric acid, while CO2 and water forms carbonic acid, thus the term “acid gas.”

Natural gas with H2S or other sulfur compounds present is called “sour gas,” while gas with only CO2 is called “sweet.” Both H2S and CO2 are undesirable, as they cause corrosion and reduce the heating value and thus the sales value of the gas. In addition, H2S may be lethal in very small quantities. Table 7-1 shows physiological effects of H2S concentrations in air.

At 0.13 ppm by volume, H2S can be sensed by smell. At 4.6 ppm the smell is quite noticeable. As the concentration increases beyond 200 ppm, the sense of smell fatigues, and the gas can no longer be detected by odor. Thus, H2S cannot always be detected by smell. Even if H2S cannot be smelled, it is possible that there is sufficient H2S present to be life threatening. At 500 ppm, H2S can no longer be smelled, but breathing problems and then death can be expected within minutes. At concentrations above 700 to 1,000 ppm, death can be immediate and without warning. Generally, a concentration of 100 ppm H2S or more in a process stream is cause for concern and the taking of proper operating precautions.

Gas sales contracts for natural gases will limit the concentration of acid compounds. In the United States, typically, gas sales contracts will permit up to 2 to 3% carbon dioxide and 1A grain per 100 scf (approximately 4 ppm) of hydrogen sulfide. The actual requirement for any sales contract may vary, depending upon negotiations between seller and purchaser.


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