Chapter 4
Techniques to consider in the determination of BAT
refineries. H2S formed at various processes such as hydrotreating, cracking, and coking in a
refinery, finally ends up as contaminant in refinery fuel gas and treat gas streams. In addition to
H2S these gases also contain NH3 and to a lesser extent CO2 and traces of COS/CS2. H2S
removal from these gases is achieved by extraction with an amine solvent. After regeneration of
the solvent the H2S is released and sent to a Sulphur Recovery Unit (SRU).
4.23.5.1 Amine treating
Description
Before elemental sulphur can be recovered in the SRU, the fuel gases (primarily methane and
ethane) need to be separated from the hydrogen sulphide. This is typically accomplished by
dissolving the hydrogen sulphide in a chemical solvent (absorption). Solvents most commonly
used are amines. Dry adsorbents such as molecular sieves, activated carbon, iron sponge and
zinc oxide may also be used. In the amine solvent processes, amine solvent is pumped to an
absorption tower where the gases are contacted and hydrogen sulphide is dissolved in the
solution. The fuel gases are removed for use as fuel in process furnaces in other refinery
operations. The amine-hydrogen sulphide solution is then heated and steam stripped to remove
the hydrogen sulphide gas. In Figure 4.10 a simplified process flow diagram of an amine
treating unit is shown.
ACID GAS
TO SULPHUR
RECOVERY
FUEL GAS
WATER
MAKE-UP
REGENERATOR
ABSORBER
SOUR GAS
FLASH GAS
TO FUEL GAS
STEAM
LEAN
AMINE
FLASH DRUM
OPTIONAL
Figure 4.10: Simplified process flow diagram of an amine treating unit
The main solvents used are MEA (Mono ethanol amine), DEA (diethanol amine), DGA
(diglycol amine), DIPA (Di-isopropanol amine), MDEA (Methyl diethanol amine) and a
number of proprietary formulations comprising mixtures of amines with various additives. One
important issue concerning the selection of the type of amine is the selectivity concerning H2S
and CO2.
1.
2.
3.
336
MEA has had a wide spread use, as it is inexpensive and highly reactive. However, it is
irreversibly degraded by impurities such as COS, CS2 and O2, and therefore is not
recommended to use when gases from cracking units are present.
DEA is more expensive than MEA but is resistant to degradation by COS and CS2 and
has obtained a wide spread use.
DGA is also resistant to degradation by COS and CS2 but is more expensive than DEA
and has the disadvantage to absorb also hydrocarbons.
Mineral Oil and Gas Refineries
Techniques to consider in the determination of BAT
4.
5.
Chapter 4
DIPA, which is used in the ADIP process, licensed by Shell. It can be used for selective
H2S removal in the presence of CO2 and is also effective in removing COS and CS2.
MDEA is nowadays most widely used, MDEA has a similar characteristic as DIPA, i.e. it
has a high selectivity to H2S, but not to CO2. As MDEA is used as a 40 - 50 % solution
(activated MDEA) in water, this has also potential energy savings. Because of the low
selectivity for CO2 absorption DIPA and MDEA are very suitable for use in Claus Tailgas
amine absorbers, as these do not tend to recycle CO2 over the Claus unit. MDEA is
applied as a single solvent or as in proprietary formulation comprising mixtures.
Achieved environmental benefits
Sulphur is removed from a number of refinery process off-gas streams (sour gas or acid gas) in
order to meet the SOx emissions limits of the applicable regulation and to recover saleable
elemental sulphur. The amine treating unit produces two streams for further use/processing in
downstream units:
• The treated gas stream usually can contain between 20 and 200 mg/Nm3 H2S (H2S content
depends on absorber operating pressure; at only 3.5 bar H2S level is 80 – 140. At higher
pressures as 20 bars the H2S level is around 20).
• The concentrated H2S/acid gas stream is routed to the SRU for sulphur recovery (discussed
in next Section 4.23.5.2).
Cross-media effects
Source
Amine
regenerator
Flow
10 - 50 t/yr
for a 5 Mt/yr
refinery
Composition
Decomposed amine up
to 50 % in water
Waste 1:
Amine filter
cleaning residue
plant
specific
FeS and salt deposits
Waste 2:
Saturated
activated carbon
from skid
mounted unit
plant
specific
Decomposition
products, heavy ends
and amine emulsions
Effluent:
amine
blow down
Comments
In order not to disturb the
biotreater operation and to
meet effluent discharge
specifications on N-Kj an
storage tank or production
planning can be used to
control very small flow to the
WWTP
Removed by skid mounted
unit operated by a specialised
contractor (usually the filter
supplier)
The saturated activated carbon
filling has to be replaced
occasionally for disposal or
regeneration
Operational data
The use of selective amines should be considered, e.g. for a stream containing carbon dioxide.
Measures should be taken to minimise hydrocarbons entering the sulphur recovery system;
operation of regenerator feed drums should be controlled to prevent hydrocarbon accumulation
in, and sudden release from, the amine regenerator as this is likely to lead to an emergency shutdown of the SRU.
Utility consumption per tonne of H2S removed in an amine treating unit is approximately:
Electricity (kWh/t)
70 – 80
Steam consumed (kg/t)
1500 - 3000
Cooling water (m3/t, ∆T =10°C)
25 - 35
Usually a fresh solvent make up rate of 10 - 50 t/yr is required to maintain solvent strength for a
5 Mt/yr refinery.
Amine solutions should be re-used wherever possible and where necessary, suitably treated
before disposal which should not be to land. Recycling of monoethanoleamine-solutions:
Mineral Oil and Gas Refineries
337
Chapter 4
Techniques to consider in the determination of BAT
Corrosive salts, which concentrate during recycling, can be removed via ion exchange
techniques. Some proprietary solutions may be biodegradable under suitable conditions.
It is important also that the amine processes have sufficient capacity to allow maintenance
activities and upsets. This sufficient capacity can be achieved by having redundancy equipment,
apply load shedding, emergency amine scrubbers or multiple scrubber systems.
Applicability
Process off-gas streams from the coker, catalytic cracking unit, hydrotreating units and
hydroprocessing units can contain high concentrations of hydrogen sulphide mixed with light
refinery fuel gases. Emergency H2S scrubbers are also important.
Economics
The cost of upgrade the refinery amine treatment system (2 %) to meet 0.01 to 0.02 % v/v of
H2S in fuel gas is around 3.75 to 4.5 million EUR. This cost is battery limit costs based on 1998
prices and include such items as equipment, licence fees, foundations, erection, tie-ins to
existing plant and commissioning. They are an order of magnitude only. Site-specific factors
such as layout, available space and necessary modifications to existing plant could have a
significant impact. In some cases these factors might be expected to increase the costs by some
50 %.
Driving force for implementation
Reduce the sulphur content of flue gases.
Example plant(s)
Common technology used all over the world
Reference literature
[118, VROM, 1999], [211, Ecker, 1999], [19, Irish EPA, 1993], [268, TWG, 2001]
4.23.5.2 Sulphur recovery units (SRU)
H2S-rich gas streams from Amine Treating Units (see above section) and Sour Water Strippers
(see Section 4.24.2) are treated in a Sulphur Recovery Unit (SRU) normally a Claus process for
bulk sulphur removal and subsequently in a Tail Gas Clean-up Unit (TGCU, see later in this
section) for trace H2S removal. Other components entering the SRU include NH3, CO2 and to a
minor extent various hydrocarbons.
4.23.5.2.1 Claus Process
Description
The Claus process consists of partial combustion of the hydrogen sulphide-rich gas stream (with
one-third the stoichiometric quantity of air) and then reacting the resulting sulphur dioxide and
unburned hydrogen sulphide in the presence of a activated alumina catalyst to produce
elemental sulphur.
OFF-GAS
TO STACK
STEAM
ACID GAS
LINE BURNER
REACTORS
MAIN BURNER
LINE BURNERS
AIR
230-300°C
0.3 barg
STEAM
BFW
BFW
INCINERATOR
REACTOR
200-220°C
0.2 barg
TAIL GAS
TO TGT
STEAM
SULPHUR PIT
SULPHUR
Figure 4.11: Simplified process flow diagram of a sulphur recovery unit (CLAUS) unit
338
Mineral Oil and Gas Refineries