Chemical Engineering April 2013 - 41

units and other methods, followed, if
necessary, by further processing to reduce
mercaptan levels. H2S in water
streams can be removed using chemical
methods such as resin beds or additives,
or by volatilization in a stripper
(oftentimes with co-separation of
NH3). In both cases the resulting gaseous
H2S is generally sent to a sulfur
recovery unit. At the downstream end
of the sulfur recovery unit, remaining
trace sulfur species can be further removed
using a SCOT-type unit or other
tail-gas recovery technologies before
venting to the atmosphere. Taken together,
these processes form the basis
of the sulfur recovery trail (Figure 1),
in which sulfur is generated, captured
and converted for further use, transport,
storage or disposal.
Role of separation processes
The sulfur recovery trail is a complex
interlocked array of different units.
Optimal performance of the trail is
dependent on each of the units operating
at its highest efficiency. Among
the most basic needs for any process,
system and plant in the sulfur
recovery trail is the control of contaminants.
Contamination control is
essential in that it allows effective
process control and enables units to
operate consistently at an optimized
cost and while maintaining or enhancing
throughput.
Separation systems play a dual role
in the process. They not only remove
the daily contamination that exists
in a normal process, but also protect
the process from upstream upsets. The
most common separation technologies
in the sulfur recovery trail include demisters,
filters to remove suspended
solids from liquids, adsorption (activated
carbon) beds, gas coalescers,
flash tanks and two-phase/threephase
separators. Other systems are
also utilized, but are more specialized
and less common.
To cover all separation systems in a
single article would lead to a lengthy
discussion, so for simplicity we will
look at one specific unit - the amine
unit - which encompasses most, if
not all, of the basic separations utilized
in the sulfur recovery trail. The
amine unit arguably suffers the most
from contamination instabilities that
considerably affect the performance,
stability and reliability of the whole
sulfur recovery process, but the concepts
discussed here apply for the
most part to other units in the sulfur
recovery trail, and can be extended to
the rest of the CPI.
Even well-operated amine units
have uncontrollable factors that cause
process upsets. Some of these relate
to contaminants entering the plant
via the gas or liquid to be processed,
which is generally liquefied petroleum
gas (LPG, C3/C4). To better understand
its ramifications, it is important
to understand what kind of contamination
might be present in the feed. In
addition to the gaseous hydrocarbon
containing the H2S, the amine unit
must handle many other components
generated in the upstream oil production
and transmission stages or in the
various upstream refinery units.
Upstream gas production yields
produced water loaded with a variety
of water-soluble contaminants,
and compressor lubricants with surfactant
properties. Additives used to
enhance production include demulsifiers,
hydrate inhibitors, biocides,
methanol and many others, and with
the recent rise of shale gas availability
we might expect new contaminants
in both the upstream gas and
the produced water. Clearly, proper
separation technology is critical.
On the refinery side, contamination
can take the form of coke fines, heatstable
salt precursors, corrosion products,
water, additives (such as corrosion
inhibitors and anti-fouling agents),
carbon fines and compressor oil. Most
if not all of these have some kind of surfactant
activity or other detrimental effect.
Together, these contaminants can
cause a multitude of plant problems,
such as amine contactor foaming leading
to lower capacities, amine losses
and low efficiencies. Additionally, some
components can also cause issues such
as amine degradation and formation of
heat-stable salts.
Effective separation is especially
challenging since all these contaminants
can be in three possible
states: solid, liquid and gas. In the
solid state it is generally found that
iron clusters predominate, along
with carbon and coke fines, and in
some cases sand, salts and oxides.
Most of the liquid contaminants are
lubricants, carried-over hydrocarbon
products, carried-over amine solvent,
cleaning products and water. This
water can also contain soluble impurities,
such as chlorides, sulfates and
acetates among others. In the gas
phase the predominant contaminants
are substances such as hydrogen cyanide,
oxygen and carbonyl sulfide.
Other contaminants that can cause
major plant upsets include methanol
and BTEX (benzene/toluene/ethylbenzene/xylene).
EquipmEnt
in DEtail
Shortcomings of demisters
Inlet separation for gas streams is
usually carried out using a knockout
drum equipped with a demisting element,
such as a mesh pad or vane
pack, installed near or at the outlet
of the vessel. These systems are typically
horizontal in gas plants and
vertical in petroleum refineries. The
basic difference is that a horizontal
drum offers increased residence time
and holding volume, while a vertical
drum has a smaller footprint. Some
less-used technologies include conventional
horizontal filter-separators
as well as cyclonic separators.
However, conventional demisters
are only adequate for removing largediameter
contaminant droplets. These
separators were originally designed
for bulk liquids removal (hence their
alternative name of slug catchers). In
addition, they are not designed for solids
separation (usually done by a wet
scrubber or a particle filter), with the
exception of cyclonic systems that can
remove large solid particles and some
larger liquid droplets.
Most traditional approaches to
separating liquid droplets, including
demisters with mesh pads, vane packs
or certain horizontal filter-separators,
display rather low efficiencies when
removing sub-micrometer aerosols
from the gas streams. As a result, only
a small number of plants have the necessary
means to adequately condition
sour gas entering amine plants.
The most challenging contaminants
to separate in any gas stream are
sub-micrometer liquid aerosols. These
finely divided liquid droplets have
ChemiCal engineering www.Che.Com april 2013 39
http://www.Che.Com
Chemical Engineering April 2013

Table of Contents for the Digital Edition of Chemical Engineering April 2013
