(399a) Hydrogen Sulphide Absorption Performance in Various Amines Solution for Combined Desulphurization and Dehydration

Hydrogen
sulphide absorption performance in various amines solution for combined
desulphurization and dehydration

Usman
Shoukat, Diego D. D. Pinto,Hanna K. Knuutila*

*Corresponding
author e-mail: hanna.knuutila@ntnu.no

Department
of Chemical Engineering, Norwegian University of Science and Technology (NTNU),
Trondheim, Norway. INtroduction

Almost quantitative removal of hydrogen
sulphide (H₂S) from natural gas is necessary prior to use or
pipeline transport. The most commonly used method for H₂S removal is
scavengers. However, these are usually non-regenerative substances and because
of cost and handling they cannot be used for high H₂S concentrations
in the gas stream. Alkanolamines are commonly used for regenerative H₂S
removal processes (Kohl and Nielsen 1997). Natural gas is
commonly saturated with water. The presence of water in the gas accelerates
corrosion, and potentialize the formation of solid gas hydrates, which cause
problems in gas flow in pipelines. One common way to avoid hydrate formation
and to achieve problem free continuous gas transportation operations is to add inhibitors
in gas pipelines (Kohl and Nielsen 1997). A system which can
removed H₂S and control hydrate simultaneously could reduce
equipment size and help to reduce the installation and operational costs for
both subsea and platform operations.

The objective of this study is to identify regenerative
solvents suitable for combined selective H₂S removal in high H₂S
content feed gas and hydrate formation control. Several amine-based solvents
will be screened in this study and the effect of solution composition, inlet H₂S
concentration and temperature on H₂S loading in the solutions will
be discussed. The amines chosen for this work were systematically chosen so
that insight into the influence of amine alkanol groups, alkyl chain length,
hydroxyl group and hindrance of the tertiary amines at H₂S
absorption are given based on their molecular structure. MEthodology

In this study, various amines solutions (20
wt.%) with water, ethylene glycol (MEG) and triethylene glycol (TEG) are
studied for H₂S absorption in a custom built experimental setup at
temperatures relevant to subsea conditions (e.g., 5 °C). The apparatus design is based on the CO₂ screening apparatus
used by (Ma’mun et al. 2007) as shown in Figure 1. As for the CO2 screening apparatus,
the H2S screening is operated at atmospheric conditions. The H₂S inlet
partial pressure was chosen to be 0.03 kPa and 1 kPa and the experiments were
run for 120 minutes for all solutions at 5 and 40 °C. The tests were performed in amine-water and amine-glycol (MEG or
TEG) solutions. ICP-MS was used for the measurement of total sulfur in the liquid
phase to obtain accurate absorbed H₂S in amine solution.  

Figure 1: Schematic flow diagram of screening
apparatus.

H₂S
absorption in various tertiary amines in presence of water, MEG and TEG was performed.
The preliminary results show that the effect of MEG and TEG on the absorption
of H₂S into the amine solutions is significant. For example,
comparing the H₂S absorption at 5ºC and 0.03 kPa pH₂S into
20wt% aqueous N-Methyl diethanolamine (MDEA) solution with glycols (MEG/TEG)-MDEA
solutions shows that replacing of glycols with water in amine solutions restricts
the H₂S absorption significantly as shown in Figure 2. MDEA-MEG solution restricts the H₂S
absorption by 30% as compared to MDEA-H₂O solution while in case of
MDEA-TEG restriction is 50% as compared to MDEA-H₂O and 27% as
compared to MDEA-MEG solution.

Figure 2: Restriction in H₂S absorption
in amine solutions caused by addition of glycols (MEG / TEG)

  Key words: H₂S absorption, alkanol amines References

Kohl, A. L. and R. B. Nielsen (1997). Gas Purification (Fifth Edition).
Houston, Gulf Professional Publishing: 40-186.

Ma’mun, S., H. F. Svendsen, K. A. Hoff and O.
Juliussen (2007). "Selection of new absorbents for carbon dioxide
capture." Energy Conversion and Management 48(1): 251-258.