Gas processing plants are an essential part of the energy
industry and provide one of the cleanest-burning fuels and a
valuable chemical feedstock. The importance and
complexity of gas processing plants have increased over the
years due to their use as a feedstock source and their integration with petrochemical plants.
Important factors that drive the process selection and
design of gas
processing plants are environmental and safety regulations,
capital and operating costs, and process efficiency. Therefore,
selecting an optimized process scheme during the project
feasibility study is vital to ensure that the project is technically feasible,
cost-effective and profitable.
PROCESS SCHEME SELECTION
The process selection study usually begins with a design
basis to specify the general configuration of the plant and its
outline requirements. These requirements consist of:
Feed characteristics, especially H2S,
CO2 and mercaptan concentrations
Product specifications, including maximum
concentrations of sulfur and CO2 in the
The criteria to be optimized for the process scheme
Environmental and safety compliance with local
regulations for effluents from incinerators, flare stacks,
wastewater treatment, etc.
Flexibility and performance
The maximum H2S concentration allowed in the
sales gas is 45 parts per million by volume (ppmv);
therefore, gas treating of the feed gas using amine is
necessary. The amine unit is designed for total H2S
removal and total or partial CO2 removal. This
article will investigate the reason for partial CO2
removal, which is no longer required due to the recent advances
in sulfur recovery technology used in gas processing
plants, including South Pars gas plants.
Partial CO2 removal scheme.
Over a span of 20 years, the process design of each gas
processing plant has been modified to some extent. The main
reasons for the changes are more stringent environmental
regulations for newer projects and higher ethane purities
required for petrochemical plants.
The original scheme designed to meet the product
specifications from a sour feed containing high concentrations
of H2S, CO2 and mercaptans is depicted in
1. Original scheme for sour gas treating
processing facility has a feed gas treating unit (GTU)
using amine for total H2S removal and partial
CO2 removal. The facility also includes utilities,
offsites and necessary infrastructure. The functions of the
main process units can be summarized as follows:
Feed reception and gas/liquid separation
Total H2S removal and partial
CO2 removal from gas
Dehydration using molecular sieve technology
Ethane recovery for production of sales gas and
NGL separation for production of liquid
C3, C4 and gas condensate
Sales gas export compression
Ethane treatment for CO2 removal and
Restrictions affect design.
New environmental standards have influenced product
specifications and have led to changes in the gas plant design.
The main changes that have altered the design are:
Improved sulfur recovery efficiency in the sulfur
recovery unit (SRU), resulting in less sulfur being burned in
Lower CO2 content requirement in the
Lower sulfur content requirement in propane and
This article investigates the best process scheme for the
new conditions and compares total CO2 and
H2S removal for the GTU vs. partial CO2
removal. It also examines the impact of this change on other
units in the plant.
Gas treating unit. The GTU uses amine for
H2S and CO2 removal. Although we assume
that readers are familiar with amines, it is important to note
that three types of amines are already used in most gas
refineries, as summarized in Table 1.1, 2
When the GTU is designed for total H2S and
CO2 removal, normally the CO2 can be
reduced to less than 5 ppmv. However, because of design
limitations, guaranteed figures using generic diethanolamine
(DEA) generally provide maximum CO2 concentrations
of 100 ppmv in the treated gas.
Changes in the sulfur recovery unit. The
acid gases (H2S and CO2) removed in the
amine unit are sent to the SRU. The SRU is based on the
modified Claus process for recovering elemental sulfur from
acid gas. The chemistry of reactions involved in the Claus
process may be described in a simplified form with the
following two equations: the first is a simple combustion of
one-third of the hydrogen sulfide; the second is the reaction
of SO2 produced with the remaining two-thirds of
H2S, according to the following
H2S + 3/2 O2 t SO2 +
H2O 519 kJ/mole (124 kcal/mole)
2 H2S + SO2 t 3/n Sn + 2
H2O 143 kJ/mole (34 kcal/mole)
Feed gas composition. The acid gas from the
GTU regenerator column consists of H2S and
CO2 that is fed to the Claus unit. The Claus process
efficiency is largely dependent on the
H2S/CO2 ratio, and it is difficult to
maintain at a high value when the H2S content in the
acid gas drops below 36%40%. This difficulty is due to
the following factors:
CO2 is an inert gas that dilutes the
process gas and, consequently, reduces the conversion
efficiency by lowering the partial pressure of reactants.
Furthermore, in the reaction furnace (where the thermal Claus
reaction takes place), the conversion efficiency is limited due
to resulting low flame temperature.
The low H2S content may present
challenges to sustaining the flame in the reaction furnace,
where only one-third of the acid gas should be burned to
achieve the stoichiometric H2S-to-SO2
ratio of 2 required by the Claus reaction.
Carbon dioxide may react with a sulfur species
to form carbonyl sulfide (COS) and carbon disulfide
(CS2) or a dissociate, which may result in reduction
of the overall sulfur recovery, unless adequate precautions are
taken for the design of the reaction furnace and the catalytic
Due to the above reasons, limitations in the
Claus process on the maximum CO2 content require a
ratio of 60:40 for CO2:H2S for the acid
gas from the GTU. Lower H2S concentrations can be
accepted using special measures (such as enriched air and fuel
gas co-firing), but at the expense of lower conversion
efficiencies. However, to minimize the Claus unit size and
maximize efficiency, an acid gas enrichment using selective
amine is generally used to produce enriched acid
gas suitable for conventional Claus SRUs.4
Another option is to use an amine absorption
process, which is suitable for H2S concentrations
within the range of 1%30 vol%.5 They offer
less complex designs and the same sulfur quality as the Claus
process, but have the disadvantage of providing lower sulfur
recovery of 96%97%.
Sulfur recovery efficiency. Typical sulfur
recovery efficiencies for Claus plants are 90%96% for a
two-stage reactor and 95%98% for a three-stage reactor.
However, new environmental regulations limit sulfur recovery
efficiencies to 98.5%99.9%. This limitation has led to
the development of a large number of tail gas units based on
different concepts to remove the last remaining sulfur
Changes in ethane quality.
Due to partial CO2 removal in the current design,
the ethane productwhich is separated from the treated gas
in the ethane-recovery sectioncontains CO2.
Therefore, it becomes necessary to add an ethane decarbonation
unit (EDU) to reduce the CO2 level to the specified
maximum of 50 parts per million by weight (ppmw) prior to
export. DEA is used to remove CO2 from ethane in the
EDU before it is dehydrated using molecular sieve beds.
In the case of total CO2 removal in the GTU, the
ethane cut from the ethane recovery section will contain very
little to virtually no CO2. In fact, ethane will
contain around 500 ppmw if CO2 is lowered to 100
ppmv in the GTU using DEA, which can be removed by molecular
sieve beds. Also, there is no need for a separate drying unit
if molecular sieve beds are used, which provides an advantage
in terms of cost, ease of operation and maintenance. Therefore, in the case
of total CO2 removal, even the molecular sieve bed
is just a CO2 guard.
Changes in LPG product quality. The
environmental specification for the total sulfur content in LPG
products (C3 and C4) has been lowered
from 80 ppmw to 10 ppmw; this was the case for LPG products
from South Pars gas plants.
Sulfur species in LPG are essentially mercaptans, which are
removed by direct oxidation with air in the presence of a
proprietary catalyst, using a caustic soda-wash process. The
LPG product is then dried before export.
A molecular sieve sulfur guard is installed after the LPG
dryers. The molecular sieve beds are regenerated using sales
gas that is then sent to the fuel gas system. The regeneration
gas must be CO2-free, as requested by the LPG guard
bed vendor. Therefore, if partial removal of CO2 is
considered for the GTU design, then another DEA absorber must
be installed for total CO2 removal from the
regeneration gas. However, if the CO2 is totally
removed in the GTU, then molecular sieve guard beds can be used
instead of a DEA absorber.
Evaluation of existing GTU.
The CO2 specifications for sales gas fed to a
consumer network should be less than 2 mol%the maximum
limit to prevent general corrosion and pitting in pipelines.
This limit will be achieved if the CO2 content in
the treated gas from the GTU is less than 1 mol%. In fact, the
latter quantity was obtained by back calculation using the
ratio of 60:40 for CO2:H2S in the acid
gas to the SRU and a sulfur recovery of 97.5%. Therefore,
partial CO2 removal in the GTU was dictated by the
process requirements in the SRU.
In more recent projects, environmental regulations
allow for fewer SO2 emissions from the SRU
incinerator, which requires an increase in the conversion of
sulfur recovery from 97.5% to 99.5%. Thus, to achieve higher
overall sulfur recovery, acid gas enrichment and tail gas
treatment units must be used. The acid gas enrichment unit
consists of selective H2S removal from the acid gas
in the presence of CO2 (i.e., partial CO2
removal from the acid gas). This is accomplished by including
an amine unit using a generic MDEA solvent that selectively
absorbs H2S. The offgas leaving the top of the amine
absorber is sent to the incinerator to convert the residual
H2S to less harmful SO2, while the sour
gas reaching the required H2S:CO2 ratio
from the amine regeneration unit is sent as feed to the Claus
Therefore, by making a gas enrichment unit part of the
sulfur gas recovery unit, it is no longer a requirement to
specify an outlet CO2 of 1 mol% in the treated gas
from the GTU. Based on these results, two alternatives exist
for the gas processing plant scheme:
1. Partial CO2 removal in the GTUsimilar
to the old scheme, regardless of the changes in the SRU, as
shown in Fig. 2.
2. Total CO2 removal in the GTUan
optimized gas processing plant scheme based on changes in the
SRU, as depicted in Fig. 3.
2. Sour gas treating plant with partial
3. Sour gas treating plant with total
Effects of total CO2
removal on sales gas quality. The sales gas from gas
processing plants can contain a maximum of 2 mol% of
CO2, as stated in the previous section. Carbon
dioxide is an inert gas that only uses energy to be heated to
the flame temperature, without any heat input contribution to
the combustion. Therefore, its presence at a relatively high
amount in the sales gas is a waste of energy.
In addition to the above, environmental agencies of many
countries continue to implement more stringent emissions
standards requiring companies to report their greenhouse gas
emissions. Thus, many customers buying sales gas want
CO2 levels in the gas to be minimized. Also, the
CO2 present in the sales gas is distributed through
many users, although it can be recovered for industrial use
when totally captured at the gas plant source.
These negative aspects of CO2 presence in the
sales gas are some of the disadvantages that can be easily
prevented by total CO2 removal in the GTU, which can
be achieved using DEA or activated MDEA (aMDEA) in the GTU.
When the GTU is designed for both H2S and
CO2 removal (down to 3 ppmv and 100 ppmv,
respectively) in the treated gas using DEA, the CO2
content in the sales gas ranges from 100 ppmv200
Effects of CO2 removal
on sales gas heating value. When modifying the sales
gas composition by total CO2 removal, it is
important to check the heating value to ensure that the changes
are not significant enough to require burner change in the
consuming furnaces. Two sales gases were studied for this
purpose; the results are presented in Table 2. As the table
shows, the effect of total CO2 removal on sales gas
heating value and its possible consequences on burner
designas well as adverse effects on the operation of
existing burnersis insignificant.
Effects of total CO2
removal on the dehydration unit. If CO2 is
present in the feed gas to the dehydration unit after the GTU,
it might be partially co-adsorbed by the molecular sieve beds,
resulting in a reduced active area for water adsorption and a
longer time for bed regeneration. Therefore, it could be
expected that, in the case of total CO2 removal, the
bed adsorption capacity will be increased while the bed
regeneration time and energy consumption are decreased. This is
an item that needs further investigation by operators and
Overall optimized scheme.
Fig. 3 shows the optimized scheme for total CO2
removal, where the ethane treatment with molecular sieve beds
should only be considered if the treated gas from the GTU will
provide an ethane product with a CO2 content higher
than 50 ppmw.
Before selecting a scheme for a gas
processing plant, it is necessary to construct a clear and
complete picture of the entire facility. The requirements of
each unit within the plant must be understood before they are
integrated into the whole scheme.
The process scheme selection is carried out during the
conceptual stage of a project and should take into account new
technology developments for each
unit in the plant. Such an approach will deliver an optimized
process for the plant that is cost effective, energy efficient,
and meets local environmental and safety regulations.
1 Hanamant Rao, P. P., D. L. Nikolic and R.
Wijntje, Do you have hard-to-handle gases?
Hydrocarbon Processing, July 2009.
2 Centi, G., S. Perathoner and F. Trifiró,
Sustainable Industrial Processes, pp. 450455,
1st ed., 2009.
3 Hocking, M., Handbook of Chemical Technology
and Corrosion Control, pp. 267271, 3rd ed.,
4 Klikenbijl, J. M., M. L. Dilon and E. C. Heyman,
Gas Pre-Treatments and Their Impact on Liquefaction
Processes, Gas Processors Association, Nashville,
Tennessee, US, March 2, 1999.
5 Echt, W. L. and C. J. Wendt, Reduce Sulfur
Emissions from Claus Recovery Units, AIChE, April
6 Ramshni, M., Cost Effective Options to
Expand SRU Capacity Using Oxygen, Sulfur Recovery
Symposium, Banff, Alberta, Canada, May 610, 2002.
Maleki is the process, utility and HSE (health,
safety and environment) department manager at Energy
Industries Engineering and Design Co. He was the
consortium process and HSE manager of South Pars
front-end engineering and design phases 17 and 18. Mr.
Maleki received a BS degree in chemical engineering from
the University of Texas at Austin. He has over 30 years
of experience as a process and HSE manager, project
engineering manager and principal process engineer on
several oil, gas and petrochemical projects.
Khorsand Movaghar has worked in the process
department at Energy Industries Engineering and Design
Co. since 2008. He holds a BS degree in petrochemical engineering and
a PhD in chemical engineering from Tehran Polytechnic
University. Dr. Khorsand also received an MS degree from
the University of Science and Technology in Tehran. He
served as a process engineer on detailed design projects
for gas train unitsincluding acid gas removal,
dehydration and ethane recoveryat South Pars gas
plant phases 20 and 21. He has over five years of
experience as a process engineer and process simulator on
several oil and gas projects.