Hydrocarbon Processing - June 2022 - GP-28

PROCESS OPTIMIZATION
A competitive study for the behavior
of amines in acid gas
N. S. ABBAS, Gulf of Suez Petroleum Co., Cairo, Egypt; M. Z. A. WAHHAB and
E. A. ASHOUR, Minia University, Minia, Egypt; and T. E. FARRAG, Port Said University, Port Said, Egypt
Natural gas is the most common fossil
fuel. However, because it exists in deep
underground reservoirs, it may contain
several non-hydrocarbon components
[e.g., hydrogen sulfide (H2
dioxide (CO2
S) and carbon
)]. These impurities are undesirable
compounds, and can cause several
technical problems, including corrosion
and environmental pollution.
The Gulf of Suez gas plant-located
in the Red Sea region of Egypt-has
been operated by the Gulf of Suez Petroleum
Co. (GUPCO) since 1983. This
plant uses diethanolamine (DEA) for the
sweetening process. The facility received a
significant amount of natural gas containing
acid gas that was beyond the plant's
design conditions. This resulted in corrosion
problems and a shutdown of the
amine unit, leading to production losses.
Using proprietary process simulation
, plant personnel launched a
softwarea
study aimed at simulating the gas plant's
natural gas sweetening process and examining
some of the critical amine process
TABLE 1. Composition of natural gas feed
at the GUPCO gas plant, 2020
Components
O
H2
Molar flow,
MMft3
d
H2
CO2
S
Methane
Ethane
Propane
I-butane
N-butane
I-pentane
Nitrogen
N-hexane
0.0588
0.0072
9.6503
1.2559
0.5646
0.0855
0.178
0.0411
0.0806
0.0295
Mole
fraction
0.0049
0.0006
0.8042
0.1047
0.0471
0.0071
0.0148
0.0034
0.0067
0.0025
28 MAY/JUNE 2022 | GasProcessingNews.com
factors for each amine type. This article
details this process.
Aim of the study. Natural gas is a vital
component in the world's energy supply.
However, despite its importance, there
are many challenges when processing
natural gas. For example, H2
S is a poisonous
and extremely corrosive compound
that exists in natural gas. Offshore and
onshore plants must remove H2
S, as government
regulations make it mandatory
to limit H2
S to 4 parts per million (ppm).
Over time, various methods for removing
H2
S have been successful in plant operations;
however, industry is always aiming
to optimize the removal process and to
create a more efficient sweetening process
to minimize costs.1
Many different processes have been
investigated, but the focus has been to
develop a sweetening process by using different
kinds of adsorption and absorption
methods. When developing gas-sweetening
methods, two focus areas are in general
use: dry adsorption and wet absorption.2
Dry adsorption is usually a non-regenerative
method and consists of a filter
where H2
S is adsorbed.3
These filters
must be changed out regularly to receive
the necessary cleaning. Conversely, wet
absorption is usually a regenerative process
where a liquid stream reacts with the
H2
from the gas stream to the liquid stream
catalyzed by a chemical reaction.4
GUPCO's LPG plant treats acid gas
with DEA solutions. However, due to
corrosion and foaming problems, the
plant studied switching from DEA to
methyl DEA (MDEA) or another amine.
To investigate which natural gas sweetening
method worked best, one process
was chosen and evaluated thoroughly to
evaluate the efficiency of that specific
Process description of the existing
gas plant. The operating conditions of
rich acid gas feed to the unit include the
following:
* Flowrate: 12 MMft3
d
* Feed gas temperature:
41°C (105.8°F)
* Feed gas pressure: 49 kg/cm2
* Concentration of H2
S feed
to the contactor: 600 ppm
TABLE 1 provides the 2020 composition of
the natural gas feed to the amine unit at
the GUPCO gas plant, while the process is
shown in FIG. 1. The acid gas enters the absorber
from the bottom, while the amine
solution enters from the top. The amine
is made to be reused by passing it through
a mixer where it is mixed with a makeup
stream of water.
Additional amine solution may be
S in an absorption column to move it
added to the mixer to ensure the optimal
composition for gas sweetening. A
booster pump increases the pressure to
47 bar, which is the operational pressure
of the absorber. A heat exchanger was installed
to cool the amine solution to the
desired operational temperature of 47.3°C
(117.14°F). The sweetened gas from the
absorber is sent to the pipe transportation
system to be transported to a chilling area
for distribution and further processing.
The bottom liquid leads to a flash tank,
where the stream is heated to flush out
most of the hydrocarbon content in the
stream. The amine solution then heads to
a distillation tower (stripper), where H2
S
is removed to the same level as the sweetcleaning
method. The aim of this study
was to determine the most efficient gas
sweetening process, using proprietary
simulation softwarea
. Once the process
had been identified, an economic analysis
was conducted to ensure that the chosen
model is realistic to use.

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