Speight J.G. Natural Gas: A Basic Handbook
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6.7
References
159
6.7
References
Anerousis, J.P., and Whitman, S.K., 1984,
“An
Updated Examination of Gas
Sweetening by the Iron Sponge Process,” Paper No. SPE 13280. SPE
Annual Technical Conference and Exhibition, Houston, Texas,
September.
Barbouteau,
L.,
and Dalaud,
R.,
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Gas Purification Processes for Air
Pollution Control,
G. Nonhebel (ed.), Butterworth and
Co.,
London,
England, Chapter
7.
Conviser, S.A., 1965,
Oil Gas
J.,
63(49): 130.
Curry, R.N., 1981,
Fundamentals of Natural Gas Conditioning,
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Publishing
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Tulsa, Oklahoma.
Duckworth, G.L. and Geddes, J.H., 1965, “Natural Gas Desulfurization by the
Iron Sponge Process,”
Oil
&
Gas
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63(37): 94-96.
Foglietta, J.H., 2004, “Dew Point Turboexpander Process:
A
Solution for High-
Pressure Fields,” Proceedings, IAPG Gas Conditioning Conference,
Neuquen, Argentina. October
18.
Nonhebel (ed.), Butterworth and Co., London, England, Chapter 9.
Fulker, R.D., 1972, in
Gas Purification Processes
for
Air Pollution Control,
G.
Geist, J.M., 1985, “Refrigeration Cycles for the Future,”
Oil
&
Gas
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83(5):
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A.E.,
1985, in
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Processes,
S.A.
Newman (ed.), Gulf Publishing Company, Houston, Texas,
Chapter
10.
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Publishing Company, Houston, Texas.
Publishing Co., Norman, Oklahoma.
Sweetening,
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Gas Treating Processes,
S.A.
Newman (ed.), Gulf Publishing Company,
Houston, Texas, Chapter
8.
Katz, D.K., 1959,
Handbook of Natural Gas Engineering,
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Kohl,
A.
L.,
and Riesenfeld, F.C., 1985,
Gas Purification,
4th edition, Gulf
Maddox, R.N., 1974,
Gas and Liquid Sweetening,
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edition, Campbell
Maddox, R.N., 1982,
Gas Conditioning and Processing, Volume
4:
Gas and Liquid
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A.,
1985, in
Acid and Sour
Mantell, C.L., 195
1,
Adsorption,
McGraw-Hill, New York.
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Inc.
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“Nitrogen Removal from
Natural Gas,” Contract Number DE-AC21-95MC32199-02.
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Chapter
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PcnOKO/webviewable/780455
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Mokhatab,
S.,
Poe, W.A., and Speight, J.G.,
2006,
Handbook
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Natural Gas
Transmission and Processing,
”
Elsevier, Amsterdam, The Netherlands.
Nederland, J.,
2004,
Sulphur,
University of Calgary, Calgary, Alberta, Canada.
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S.A.,
1985,
Acid and Sour Gas Treating Processes,
Gulf Publishing,
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G.,
1964,
Gas Purification Processes,
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V.D.
and Lygeros,
A.I.,
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1985,
in
Acid and Sour Gas Treating Processes,
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Soud, H. and Takeshita,
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Speight, J.G.,
1993,
Gas
Processing: Environmental Aspects and Methods,
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2000,
The Desulfurization
of
Heavy Oils and Residua,
Znd
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Speight, J.G.,
2007,
The Chemistry and Technology of Petroleum,
4‘h
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J.S.,
Rousseau, R.W., and Ferrell, J.K.,
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Acid and Sour Gas
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International Energy Agency Coal Research, London, England.
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Newman (ed.). Gulf Publishing Company,
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CHAPTER
7
Processes
Gas processing (gas refining) usually involves several processes to
remove: oil; water; elements such as sulfur, helium, and carbon
dioxide; and natural gas liquids (Chapter
6).
In addition, it is often
necessary to install scrubbers and heaters at or near the wellhead that
serve primarily to remove sand and other large-particle impurities.
The heaters ensure that the temperature of the natural gas does not
drop too low and form a hydrate (Chapter
1)
with the water vapor
content of the gas stream.
Many chemical processes are available for processing or refining nat-
ural gas. However, there are many variables in the choice of pro-
cessing/re€ining sequence that dictate which process (or processes) is
to be employed. In this choice, several factors must be considered:
1.
The types and concentrations of contaminants in the gas
2.
The degree of contaminant removal desired
3.
The selectivity of acid gas removal required
4.
The temperature, pressure, volume, and composition of the
gas to be processed
5.
The carbon dioxide-hydrogen sulfide ratio in the gas
6.
The desirability
of
sulfur recovery due to process economics
or
environmental issues
161
162
Chapter
7
Processes
In
addition to hydrogen sulfide and carbon dioxide, gas may contain
other contaminants, such as mercaptans (also called
thiols,
R-SH)
and
carbonyl sulfide
(COS).
The presence
of
these impurities may elimi-
nate some of the sweetening processes because some processes remove
large amounts
of
acid gas but not to a sufficiently low concentration.
On
the other hand, some processes that are not designed to remove
(or are incapable of removing) large amounts
of
acid gases. However,
these processes are capable of removing the acid gas impurities to very
low levels when the acid gases are there
in
low to medium concentra-
tions in the gas.
Process selectivity indicates the preference with which the process
removes one acid gas component relative to
(or
in preference to)
another. For example, some processes remove hydrogen sulfide and
carbon dioxide; other processes are designed to remove hydrogen sul-
fide only. It is very important to consider the process selectivity for,
say, hydrogen sulfide removal compared to carbon dioxide removal,
which ensures minimal concentrations of these components in the
product, thus illustrating the need to consider the carbon dioxide to
hydrogen sulfide ratio in the gas stream.
To describe all of the possible processes for gas cleaning is beyond the
scope of this book. Therefore, this chapter focuses
on
processes that
are key to the production
of
a “pipelineable” product (e.g., methane)
for sale to the consumer.
7.1
Olamine
Processes
The most commonly used technique for gas processing is to first
direct the gas flow though a tower containing an amine (olamine)
solution. Amines absorb sulfur compounds from natural gas and can
be reused repeatedly. After desulfurization, the gas flow is directed to
the next section, which contains a series
of
filter tubes. As the
velocity of the stream reduces in the unit, primary separation
of
remaining contaminants occurs due to gravity. Separation
of
smaller
particles occurs as gas flows through the tubes, where they combine
into larger particles that flow to the lower section
of
the unit. Further,
as the gas stream continues through the series of tubes, a centrifugal
force is generated that further removes any remaining water and
small particulate matter.
The processes that have been developed
to
accomplish
gas
purifica-
tion vary from a simple once-through wash operation to complex
7.1
Olamine
Processes
163
multi-step recycling systems (Speight,
1993;
Mokhatab et al.,
2006).
In
many cases, the process complexities arise because
of
the need for
recovery
of
the materials used to remove the contaminants
or
even
recovery
of
the contaminants
in
the original,
or
altered, form (Kohl
and Riesenfeld,
1985;
Newman.
1985).
As currently practiced, acid-gas removal processes involve the chem-
ical reaction
of
the acid gases with a solid oxide (such as iron oxide)
or
selective absorption
of
the contaminants
into
a liquid
(such
as
ethano-
lamine) that is passed countercurrent
to
the gas. Then the absorbent is
stripped
of
the gas components (regeneration) and recycled to the
absorber. The process design will vary and, in practice, may employ
multiple absorption columns and multiple regeneration columns.
7.1.1
Cirdler Process
Amine (olamine) washing
of
natural gas involves chemical reaction
of
the amine with any acid gases with the liberation
of
an appreciable
amount
of
heat, which must be accommodated. Amine derivatives
such as ethanolamine (monoethanolamine, MEA), diethanolamine
(DEA), triethanolamine (TEA), methyldiethanolamine (MDEA), diiso-
propanolamine (DIPA), and diglycolamine (DGA) have been used in
commercial applications (Kohl and Riesenfeld,
1985;
Speight,
1993;
Polasek and Bullin,
1994).
Processes that use methyl diethanolamine (MDEA) became popular
with the natural gas industry because
of
its high selectivity for
hydrogen sulfide over carbon dioxide. This high selectivity allows
for
a
reduced solvent circulation rate, as well as a richer hydrogen sulfide
feed to the sulfur recovery unit. The reaction
of
methyl diethanola-
mine with hydrogen sulfide is almost instantaneous. However, the
reaction
of
methyl diethanolamine with carbon dioxide is much
slower; furthermore, the reaction rate
of
methyl diethanolamine with
carbon dioxide is slower than that of carbon dioxide with
ethanolamine.
Depending upon the application, special solutions may also be used,
such as mixtures
of
amines; amines with physical solvents such as sul-
folane and piperazine; and amines that have been partially neutral-
ized with an acid such as phosphoric acid (Bullin,
2003).
The proper selection
of
the amine can have
a
major impact
on
the
performance and cost
of
a sweetening unit. However, many factors
164
Chapter
7
Processes
must be considered when selecting an amine for a sweetening appli-
cation (Polasek and Bullin,
1994).
Considerations for evaluating an
amine type
in
gas treating systems are numerous. It is important to
consider all aspects
of
the amine chemistry and type because the
omission
of
a
single issue may lead to operational problems. While
studying each issue,
it
is important to understand the fundamentals
of
each amine solution.
2(RNH,)
+
H,S
H
(RNH,),S
(RNH,),S
+
H,S
H
2(RNH,)HS
2(RNHJ
+
CO,
H
RNHCOONH,R
These reactions are reversible by changing the system temperature.
MEA also reacts with carbonyl sulfide (carbonyl sulfide) and carbon
disulfide (carbon disulfide) to form heat-stable salts that cannot be
regenerated.
DEA is a weaker base than MEA, and therefore a DEA system does not
typically suffer the same corrosion problems but does react with
hydrogen sulfide and carbon dioxide:
2R,NH
+
H,S
H
(R,NH,),S
(R,NH,),S
+
H,S
H
2(R,NH,)HS
2R,NH
+
CO,
H
R,NCOONH,R,
Diethanolamine also removes carbonyl sulfide and carbon disulfide
partially as its regenerable compound with carbonyl sulfide and
carbon disulfide without much solution losses.
One
key
difference among
the
various
specialty amines
is
selectivity
towards hydrogen sulfide. Instead
of
removing hydrogen sulfide and
7.1
Olamine
Processes
165
carbon dioxide, as generic amines such
as
MEA
and
DEA
do, some
products readily remove hydrogen sulfide to specifications, but allow
controlled amounts of carbon dioxide to slip through. When the
methyl diethanolamine process was developed in the mid
‘~OS,
it was
principally destined for the sweetening of gases that did not require
complete carbon dioxide removal (Blanc et al.,
1981),
or required the
removal of only a controlled part of the carbon dioxide. The selec-
tivity of methyl diethanolamine-based products can lead to more
energy savings. For example, allowing carbon dioxide to remain in
the treated gas reduces the amount of acid gas in the amine that
needs to be regenerated, thus reducing the amount of energy
required.
A
series of chemical activators used with methyl diethanolamine offers
the most cost-effective answer to complete or controlled acid-gas
removal from sour to very sour natural gases. However, there are limi-
tations to even the most advanced
activated methyl diethanolamine-
only based gas treatment technologies in handling very highly acid-
gas-loaded natural or associated oilfield gases; especially for bulk acid-
gas removal when the acid gases are destined for cycling and/or dis-
posal by re-injection. The activated methyl diethanolamine process is
probably the most cost-effective solution today to meet the widest
range of applications from complete carbon dioxide removal to bulk
hydrogen sulfide and/or carbon dioxide removal even for acid-gas re-
injection projects (Lallemand and Minkkinen,
2001).
The general process flow diagram for an amine sweetening plant
varies little, regardless of the aqueous amine solution used
as
the
sweetening agent (Figure
7-1).
The sour gas containing hydrogen sul-
fide and/or carbon dioxide will nearly always enter the plant through
an inlet separator (scrubber) to remove any free liquids and/or
entrained solids. The sour gas then enters the bottom of the absorber
column and flows upward through the absorber in intimate counter-
current contact with the aqueous amine solution, where the amine
absorbs acid-gas constituents from the gas stream. Sweetened gas
leaving the top of the absorber passes through an outlet separator and
then flows to
a
dehydration unit (and compression unit,
if
necessary)
before being considered ready for sale.
In many units the rich amine solution
is
sent from the bottom of the
absorber to
a
flash tank to recover hydrocarbons that may have
dissolved
or
condensed
in
the
amine solution in
the
absorber.
The
rich
solvent is then preheated before entering the top
of
the stripper
166
ChaDter
7
Processes
Figure
7-1
The amine (olamine) process for
gas
sweetening.
column. The amine-amine heat exchanger serves as heat-conservation
device and lowers total heat requirements for the process.
A
part of the
absorbed acid gases will be flashed from the heated rich solution
on
the top tray of the stripper. The remainder of the rich solution flows
downward through the stripper in counter-current contact with vapor
generated in the reboiler. The reboiler vapor (primarily steam) strips
the acid gases from the rich solution. The acid gases and the steam
leave the top of the stripper and pass overhead through a condenser,
where most of the steam is condensed and cooled. The acid gases are
separated in the separator and sent to the flare or to processing. The
condensed steam is returned to the top of the stripper as reflux.
Lean amine solution from the bottom of the stripper column is
pumped through an amine-amine heat exchanger and then through a
cooler before being introduced to the top of the absorber column. The
amine cooler serves to lower the lean amine temperature to the
100"
F
range. Higher temperatures of the lean amine solution will result in
excessive amine losses through vaporization and also lower acid gas
carrying capacity in the solution because of temperature effects.
Diethanolamine
(DEA)
has a higher boiling temperature than monoet-
hanolamine, requiring other methods
of
reclaiming, such as vacuum
7.1
Olamine
Processes
167
distillation, to prevent thermal degradation of the amine. Moreover,
diethanolamine has a slow degradation rate. Consequently,
in
most
cases
it
is not practical, economical, or necessary to reclaim DEA solu-
tions. Solution purification is maintained by mechanical and carbon
filtration, and by caustic or soda ash addition to the system to neu-
tralize the heat stable amine salts.
Moisture may be removed from hydrocarbon gases at the same time
as hydrogen sulfide is removed. Moisture removal is necessary
to
pre-
vent harm to anhydrous catalysts and to prevent the formation of
hydrocarbon hydrates (e.g.,
C,H,
18H,O)
at low temperatures.
A
widely used dehydration and desulphurization process is the
glycol/amine process,
in
which the treatment solution is a mixture
of
ethanolamine and a large amount of glycol. The mixture is circulated
through an absorber and a reactivator in the same way as ethanola-
mine is circulated in the Girbotol process. The glycol absorbs mois-
ture from the hydrocarbon gas passing up the absorber; the
ethanolamine absorbs hydrogen sulfide and carbon dioxide. The
treated gas leaves the top
of
the absorber; the spent ethanolamine
glycol mixture enters the reactivator tower, where heat drives off the
absorbed acid gases and water.
The processes using ethanolamine and potassium phosphate are now
widely used. The ethanolamine process, known as the Girbotol pro-
cess, removes acid gases (hydrogen sulfide and carbon dioxide) from
liquid hydrocarbons and from natural and from refinery gases. The
Girbotol treatment solution is an aqueous solution
of
ethanolamine,
which is an organic alkali that has the reversible property of reacting
with hydrogen sulfide under cool conditions and releasing hydrogen
sulfide at high temperatures. The ethanolamine solution fills a tower
called an absorber through which the sour gas is bubbled. Purified gas
leaves the top
of
the tower, and the ethanolamine solution leaves the
bottom of the tower with the absorbed acid gases. The ethanolamine
solution enters a reactivator tower where heat drives the acid gases
from the solution. Ethanolamine solution, restored to its original
condition, leaves the bottom of the reactivator tower to
go
to the top
of
the absorber tower, and acid gases are released from the top of the
reactivator.
7.1.2
Flexsorb
Process
The Flexsorb
SE
process
is
based on a
family
of
sterically
hindered
amines in aqueous solutions
or
other physical solvents. The sterically
168
ChaDter
7
Processes
hindered amines are secondary amines that have a large hydrocarbon
group attached to the nitrogen group. The large molecular structure
hinders the carbon dioxide approach to the amine. The larger the
structure the more difficult it becomes for the carbon dioxide to get
close to the amine. They also appear to be unstable
to
the carbamate
form
of
product and revert easily to the carbonate form found
in
the
tertiary amines. Like tertiary amines, they are capable of a high degree
of solvent loading.
One mole/mole, instead
of
0.5
mole/mole typical of primary and sec-
ondary amines. One version
of
the solvent,
Flexsorb
SE
Plus,
is
very
selective towards hydrogen sulfide and has been used
in
several
plants for tail-gas processing or lean acid-gas enrichment
(AGE).
There are
two
mixed hindered amine/physical solvent versions
of
the
Flexsorb process. The
Hybrid
Flexsorb
SE
process employs a solution
of
the Flexsorb
SE
amine, water, and an unspecified physical solvent. The
Flexsorb
PS
solvent consists
of
a different hindered amine, water, and a
physical solvent. Five of these plants are believed to be operating.
7.2
Physical Solvent Processes
Two
of
the most widely used physical solvent processes for gas
cleaning are
Selexol
and
Rectisol
processes. The Selexol process solvent
is the dimethyl ether
of
polyethylene glycol, while the Rectisol
solvent is methanol.
The principal benefits of physical solvents are:
1.
Selectivity for hydrogen sulfide over carbonyl sulfide and
carbon dioxide
2.
High loadings at high acid-gas partial pressures
3.
Solvent stability
4.
Low heat requirements because most of the solvent can be
regenerated by a simple pressure letdown
The performance of
a
physical solvent can be easily predicted. The
solubility of a compound in the solvent is directly proportional to its
partial pressure
in
the
gas
phase,
hence,
the
improvement
in
the
per-
formance
of
physical solvent processes with increasing gas pressure.