There has been a concern that DGA might be a good solvent for unsaturated
hydrocarbons. A survey of the DGA users indicates that many of the systems are
operated on gas containing concentrations of C 5 + above 2 % without any indication
of hydrocarbon loading of the system.
Those systems near their hydrocarbon dew point are usually installed with a flash
tank on the rich amine from the absorber. The flash tank is operated at a reduced
pressure, just high enough to get into the plant fuel gas system. This reduces the
vapor load on the regenerator column. (A similar system is recommended on MEA
systems operating near the hydrocarbon dew point.)
DGA allows H 2 S removal to less than ¼ grain per 100 scf and removes CO 2 to
levels of about 200 ppm using normal absorber design parameters.
Methyl Diethanolamine (MDEA)
The amine that is growing in popularity for H 2 S removal from gases is methyl
diethanolamine. MDEA has taken over many of the applications formerly allocated
to MEA and DEA.
MDEA is a tertiary amine that selectively removes H 2 S, with less affinity for
CO 2 . This means that the sour gas from MDEA regeneration contains less CO 2 and
places a lower volume load on the sulfur recovery units. MDEA is relatively
noncorrosive and is commonly used at 50 % concentration without corrosion
inhibitors. It is not degraded significantly by impurities in the gas and has a
relatively low heat of vaporization and specific heat.
The MDEA reactions are similar to the absorption reactions of other amines. It is
a somewhat weaker base in the reactions.
The process know-how for applying MDEA is offered by several vendors, but
can also be applied as open art. MDEA can typically pick up about 0.3–0.5 mole
H 2 S per mole MDEA. In a typical 50 % solution, this amounts to 4.1–6.8 scf of H 2 S
per gallon, significantly more than MEA or DEA at their normal concentration
levels. It has been successfully retrofit into MEA and DEA systems for increasing
capacity with few other changes. Some of these retrofits have actually been done
online while the systems were in operation.
MDEA is capable of meeting ¼ grain H 2 S per 100 scf standard for fuel gases,
but leaves more CO 2 in the gas than the alternative amines.
Other Gas Treating Processes
Hot Potassium Carbonate (Benfield, Catacarb)
This basic process concept has been known since the early 1900s. It was not an
economical, practically-demonstrated process until the mid-1950s. Since that time,
the process has been used for bulk removal of acid gases where residual CO 2
content was not needed in the ppm range.
The process is very similar to the amine processes. High temperatures favor high
solubility of potassium carbonate (PC) in water leading to high concentrations of
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D.S.J. Jones and S.A. Treese
hydrocarbons. A survey of the DGA users indicates that many of the systems are
operated on gas containing concentrations of C 5 + above 2 % without any indication
of hydrocarbon loading of the system.
Those systems near their hydrocarbon dew point are usually installed with a flash
tank on the rich amine from the absorber. The flash tank is operated at a reduced
pressure, just high enough to get into the plant fuel gas system. This reduces the
vapor load on the regenerator column. (A similar system is recommended on MEA
systems operating near the hydrocarbon dew point.)
DGA allows H 2 S removal to less than ¼ grain per 100 scf and removes CO 2 to
levels of about 200 ppm using normal absorber design parameters.
Methyl Diethanolamine (MDEA)
The amine that is growing in popularity for H 2 S removal from gases is methyl
diethanolamine. MDEA has taken over many of the applications formerly allocated
to MEA and DEA.
MDEA is a tertiary amine that selectively removes H 2 S, with less affinity for
CO 2 . This means that the sour gas from MDEA regeneration contains less CO 2 and
places a lower volume load on the sulfur recovery units. MDEA is relatively
noncorrosive and is commonly used at 50 % concentration without corrosion
inhibitors. It is not degraded significantly by impurities in the gas and has a
relatively low heat of vaporization and specific heat.
The MDEA reactions are similar to the absorption reactions of other amines. It is
a somewhat weaker base in the reactions.
The process know-how for applying MDEA is offered by several vendors, but
can also be applied as open art. MDEA can typically pick up about 0.3–0.5 mole
H 2 S per mole MDEA. In a typical 50 % solution, this amounts to 4.1–6.8 scf of H 2 S
per gallon, significantly more than MEA or DEA at their normal concentration
levels. It has been successfully retrofit into MEA and DEA systems for increasing
capacity with few other changes. Some of these retrofits have actually been done
online while the systems were in operation.
MDEA is capable of meeting ¼ grain H 2 S per 100 scf standard for fuel gases,
but leaves more CO 2 in the gas than the alternative amines.
Other Gas Treating Processes
Hot Potassium Carbonate (Benfield, Catacarb)
This basic process concept has been known since the early 1900s. It was not an
economical, practically-demonstrated process until the mid-1950s. Since that time,
the process has been used for bulk removal of acid gases where residual CO 2
content was not needed in the ppm range.
The process is very similar to the amine processes. High temperatures favor high
solubility of potassium carbonate (PC) in water leading to high concentrations of
506
D.S.J. Jones and S.A. Treese