Acid gas

Instructor: Dr. Istadi (http://tekim.undip.ac.id/staf/istadi )
Email: istadi@undip.ac.id

DEFINISI
� Acid gas: gas alam yang mengandung H2S, dan CO2
� Sour gas: gas alam yang mengandung H2S dan senyawa sulfur lainnya
(COS, CS2, dan mercaptan)
� Sweet gas: gas alam yang mengandung CO2
� Gas treating: reduction of the “acid gases” to sufficiently low levels to
meet contractual specifications or permit additional processing in
the plant without corrosion and plugging problems.
� Questions:
� Why are the acid gases a problem?
� What are the acid gas concentrations in natural gas?
� How much purification is needed?
� What is done with the acid gases after separation from the natural gas?
� What processes are available for acid gas removal?

Natural Gas Pipeline Specification

Acid Gas Definitions
� Hydrogen Sulfida (H2S):
� Hydrogen sulfide is highly toxic, and in the presence of water
it forms a weak corrosive acid.
� threshold limit value (TLV): 10 ppmv
� When H2S concentrations are well above the ppmv level,
other sulfur species can be present: carbon disulfide (CS2),
mercaptans (RSH), and sulfides (RSR), in addition to
elemental sulfur.
� If CO2 is present, the gas may contain trace amounts of
carbonyl sulfide (COS).
� ASTM D4084 Standard test method for analysis of hydrogen
sulfide in gaseous fuels

H 2S…
� At 0.13 ppm, H2S can be sensed by smell.
� At 4.6 ppm, the smell is quite noticeable.
� As the concentration increases beyond 200 ppm, the
sense of smell fatigues, and the gas can no longer be
detected by odor.
� At 500 ppm, breathing problems are observed and
death can be expected in minutes.
� At 1000 ppm, death occurs immediately.

Acid Gas Definitions
� Carbon dioxida (CO2):
� Carbon dioxide is nonflammable and, consequently, large
quantities are undesirable in a fuel.
� it forms a weak, corrosive acid in the presence of water.
� If the partial pressure of CO2 exceeds 15 psia, inhibitors
usually can only be used to prevent corrosion.
� The partial pressure of CO2 depends on the mole fraction of
CO2 in the gas and the natural gas pressure.
� Corrosion rates will also depend on temperature.
� Threshold Limit Value (TLV): of a chemical substance is a
level to which it is believed a worker can be exposed day
after day for a working lifetime without adverse health
effects.

Gas Purification Level
� The inlet conditions at a gas processing plant are
generally temperatures near ambient and pressures
in the range of 300 to 1,000 psi (20 to 70 bar), so
the partial pressures of the entering acid gases
can be quite high
� If the gas is to be purified to a level suitable for
transportation in a pipeline and used as a residential
or industrial fuel, then the H2S concentration must
be reduced to 0.25 g/100 SCF (6 mg/m 3 )
� the CO2 concentration must be reduced to a
maximum of 3 to 4 mol%

� However, if the gas is to be processed for NGL
recovery or nitrogen rejection in a cryogenic
turboexpander process, CO2 may have to be
removed to prevent formation of solids.
� If the gas is being fed to an LNG liquefaction facility,
then the maximum CO2 level is about 50 ppmv

Acid Gas Disposal
� What becomes of the CO2 and H2S after their
separation from the natural gas? � The answer
depends to a large extent on the quantity of the acid
gases. � Warning: CO2 is the most greenhouse gas
contributor
� For CO2, if the quantities are large � sometimes used
as an injection fluid in EOR (enhanced oil recovery)
projects.

In the case of H 2S, four disposal
options are available:
� Incineration and venting, if environmental
regulations regarding sulfur dioxide emissions can be
satisfied
� Reaction with H2S scavengers, such as iron sponge
� Conversion to elemental sulfur by use of the Claus
or similar process (2 H 2S + O 2 → S 2 + 2 H 2O)
� Disposal by injection into a suitable underground
formation, � if concentration is too high

Acid Gas Removal Processes

Natural Gas Sweetening Processes
� 1. Batch solid bed absorption: For complete removal of H2S at
low concentrations, the following materials can be used: iron
sponge, molecular sieve, and zinc oxide.
� 2. Reactive solvents: MEA (monoethanol amine), DEA
(diethanol amine), DGA (diglycol amine), DIPA (di-isopropanol
amine), hot potassium carbonate, and mixed solvents. These
solutions are used to remove large amounts of H2S and CO2 and
the solvents are regenerated.
� 3. Physical solvents: Selexol, Recitisol, Purisol, and Fluor
solvent. They are mostly used to remove CO2 and are
regenerated.
� 4. Direct oxidation to sulfur. Stretford, Sulferox LOCAT, and
Claus. These processes eliminate H2S emissions.
� 5. Membranes. This is used for very high CO2 concentrations.
AVIR, Air Products, Cynara (Dow), DuPont, Grace, International
Permeation, and Monsanto are some of these processes

Process Selection? Please consider:
� The type and concentration of impurities and hydrocarbon
composition of the sour gas.
� The temperature and pressure at which the sour gas is available.
� The specifications of the outlet gas (low outlet specifications favor the
amines).
� The volume or flow rate of gas to be processed.
� The specifications for the residue gas, the acid gas, and liquid products.
� The selectivity required for the acid gas removal.
� Feasibility of sulfur recovery
� The capital, operating, and royalty costs for the process.
� Acid gas selectivity required
� Presence of heavy aromatic in the gas
� Well location
� Relative economics
� The environmental constraints, including air pollution regulations and
disposal of byproducts considered hazardous chemicals.

PURIFICATION PROCESS
� Four scenarios are possible for acid gas removal from
natural gas:
� CO2 removal from a gas that contains no H2S
� H2S removal from a gas that contains no CO2
� Simultaneous removal of both CO2 and H2S
� Selective removal of H2S from a gas that contains
both CO2 and H2S

Process selection chart for
CO 2 removal with no H 2S present

Process selection chart for
H 2S removal with no CO 2 present

Process selection chart for
simultaneous H 2S and CO 2 removal

Process selection chart for
selective H 2S removal with CO 2 present

CO 2 and H 2S Removal Processes for
Gas Streams

SOLVENT ABSORPTION PROCESSES
� In solvent absorption, the two major cost factors are:
� the solvent circulation rate, which affects both
equipment size and operating costs,
� and the energy requirement for regenerating the
solvent

Comparison of Chemical and
Physical Solvents

� Primary amine
� Secondary amine
� Tertiary amine
Amine Structure

amines…
� The amines are used in water solutions in
concentrations ranging from approximately 10 to 65
wt% amines
� All commonly used amines are alkanolamines, which
are amines with OH groups attached to the
hydrocarbon groups to reduce their volatility

Molecular structures of commonly used amines

Amines remove H 2S and CO 2 in a two
step process
� The gas dissolves in the liquid (physical
absorption).
� The dissolved gas, which is a weak acid, reacts with
the weakly basic amines.
� Absorption from the gas phase is governed by the
partial pressure of the H2S and CO2 in the gas,
whereas the reactions in the liquid phase are
controlled by the reactivity of the dissolved
species

Basic Amine Chemistry
� Amines are bases, and the important reaction in gas
processing is the ability of the amine to form salts with
the weak acids formed by H2S and CO2 in an aqueous
solution
� The reaction between the amine and both H2S and
CO2 is highly exothermic
� Direct proton transfer:
� R 1R 2R 3N + H 2S ↔ R 1R 2R 3NH+HS −

� The reaction between the amine and the CO2 is more
complex because CO2 reacts via two different
mechanisms.
� When dissolved in water, CO2 hydrolyzes to form
carbonic acid, which, in turn, slowly dissociates to
bicarbonate.
� The bicarbonate then undertakes an acid−base
reaction with the amine to yield the overall reaction

� A second CO2 reaction mechanism, requires the presence of a labile
(reactive) hydrogen in the molecular structure of the amine.
� The CO2 reacts with one primary or secondary amine molecule to form
the carbamate intermediate, which in turn reacts with a second amine
molecule to form the amine salt
� The rate of CO2 reaction via carbamate formation is much faster
than the CO2 hydrolysis reaction, but slower than the H2S
acid−base reaction.
� These reactions are reversible and are forward in the absorber (at low
temperature) and backward in the stripper (at high temperature).

Monoethanolamine
� Monoethanolamine (MEA) is the most basic of the
amines used in acid treating and thus the most
reactive for acid gas removal.
� It has the advantage of a high solution capacity at
moderate concentrations, and it is generally used
for gas streams with moderate levels of CO2 and H2S
when complete removal of both impurities is required.
� A slow production of “heat stable salts” form in all
alkanol amine solutions, primarily from reaction with
CO2.
� Oxygen enhances the formation of the salts.

MEA Reactions
� 2(RNH 2) + H 2S ↔ (RNH 3) 2S
� (RNH 3) 2S + H 2S ↔ 2(RNH 3)HS
� 2(RNH 2) + CO 2 ↔ RNHCOONH 3R

Some Representative Operating
Parameters for Amine Systems
� The MEA process is usually using a solution of 15–20% MEA (wt%)
in water.
� Loading is about 0.3–0.4 mol of acid removed per mole of MEA.
� The circulation rate is between 2 and 3 mol of MEA per mole of
H2S
� However, commercial plants use a ratio of 3 to avoid excessive
corrosion.

Monoethanolamine Disadvantages
� A relatively high vapor pressure that results in high
vaporization losses
� The formation of irreversible reaction products with COS
and CS2
� A high heat of reaction with the acid gases that results in high
energy requirements for regeneration
� The inability to selectively remove H2S in the presence of
CO2
� Higher corrosion rates than most other amines if the MEA
concentration exceeds 20% at high levels of acid gas loading
(Kohl and Nielsen, 1997)
� The formation of corrosive thiosulfates when reacted with
oxygen (McCartney, 2005)

Operating Features
� MEA forms foam easily due to the presence of contaminants in the liquid
phases; this foam results in carryover from the absorber. These
contaminants could be condensed hydrocarbons, degradation products,
iron sulfide, as well as corrosion products and excess inhibitors.
� Solids can be removed by using a filter; hydrocarbons could be flashed;
degradation products are removed using a reclaimer.
� The number of trays used in absorbers in commercial units is between
20 and 25 trays. However, the theoretical number of trays calculated from
published equilibrium data is about three to four.
� If we assume an efficiency of 35% for each tray, then the actual number of
trays is 12. It has been reported that the first 10 trays pick up all of the H2S
and at least another 10 trays are of not much value. Thus, it is suggested
to use 15 trays.
� It is recommended that MEA be used if the feed does not contain COS or
CS2, which form stable products and deplete the amine. If the feed has
these compounds, a reclaimer must be used, where a strong base like
NaOH is used to regenerate and liberate the amine. This base has to be
neutralized later.

Diglycolamine
� Compared with MEA, low vapor pressure allows
Diglycolamine [ 2-(2-aminoethoxy) ethanol] (DGA) to be
used in relatively high concentrations (50 to 70%),
� Which results in lower circulation rates.
� It is reclaimed onsite to remove heat stable salts and
reaction products with COS and CS2.

Diethanolamine
� Diethanolamine (DEA), a secondary amine, is less
basic and reactive than MEA.
� Compared with MEA, it has a lower vapor pressure
and thus, lower evaporation losses;
� it can operate at higher acid gas loadings, typically 0.35
to 0.8 mole acid gas/mole of amine (DEA) versus
0.3 to 0.4 mole acid-gas/mole (MEA);
� and it also has a lower energy requirement for
reactivation.
� Concentration ranges for DEA are 30 to 50 wt% and
are primarily limited by corrosion.

DEA Reactions
� 2R 2NH + H 2S ↔ (R 2NH 2) 2S
� (R 2NH 2) 2S + H 2S ↔ 2R 2NH 2SH
� 2R 2NH + CO 2 ↔ R 2NCOONH 2R 2

� DEA forms regenerable compounds with COS and CS2
and, thus, can be used for their partial removal
without significant solution loss.
� DEA has the disadvantage of undergoing irreversible
side reactions with CO2 and forming corrosive
degradation products; thus, it may not be the best
choice for high CO2 gases.
� Removal of these degradation products along with the
heat stable salts must be done by use of either vacuum
distillation or ion exchange.

Methyldiethanolamine (MDEA)
� Methyldiethanolamine (MDEA), a tertiary amine,
selectively removes H2S to pipeline specifications while
“slipping” some of the CO2.
� MDEA has a low vapor pressure and thus, can be used at
concentrations up to 60 wt% without appreciable
vaporization losses.
� Even with its relatively slow kinetics with CO2, MDEA is
used for bulk removal of CO2 from high-concentration gases
because energy requirements for regeneration are lower
than those for the other amines.
� It is not reclaimable by conventional methods

Comparison of Amine Solvents

Principles of Amine Treating Process
� The acid gas is fed into a scrubber to remove entrained water and
liquid hydrocarbons.
� The gas then enters the bottom of absorption tower which is
either a tray (for high flow rates) or packed (for lower flow rate).
� The sweet gas exits at the top of tower.
� The regenerated amine (lean amine) enters at the top of this
tower and the two streams are contacted countercurrently. In this
tower, CO2 and H2S are absorbed with the chemical reaction into
the amine phase.
� The exit amine solution, loaded with CO2 and H2S, is called rich
amine.
� This stream is flashed, filtered, and then fed to the top of a stripper
to recover the amine, and acid gases (CO2 and H2S) are stripped
and exit at the top of the tower.
� The refluxed water helps in steam stripping the rich amine
solution.
� The regenerated amine (lean amine) is recycled back to the top of
the absorption tower.

Process Flow Diagram for Amine Treating

Average Heats of Reaction of the
Acid Gases in Amine Solutions

Amine Reclaiming
� Amines react with CO 2 and contaminants, including
oxygen, � to form organic acids.
� These acids then react with the basic amine to form heat
stable salts (HSS). As their name implies, these salts are
heat stable, accumulate in the amine solution, and must be
removed.
� For MEA and DGA solutions, the salts are removed through
the use of a reclaimer which utilizes a semicontinuous
distillation
� The reclaimer is filled with lean amine, and a strong base,
such as sodium carbonate or sodium hydroxide, is added to
the solution to neutralize the heat stable salts.

Operating Issues
� Corrosion—Some of the major factors that affect
corrosion are:
� Amine concentration (higher concentrations favor
corrosion)
� Rich amine acid gas loading (higher gas loadings in
the amine favor corrosion)
� Oxygen concentration
� Heat stable salts (higher concentrations promote
corrosion and foaming)
� the corrosion products can cause foaming

� Solution Foaming—
� Foaming of the liquid amine solution is a major
problem because it results in:
� poor vapor−liquid contact,
� poor solution distribution,
� and solution holdup with resulting carryover and off spec gas.
� Among the causes of foaming are:
� suspended solids,
� liquid hydrocarbons,
� surface active agents, such as those contained in inhibitors
and compressor oils,
� and amine degradation products, including heat stable salts.
� One obvious cure is to remove the above materials;
the other is to add antifoaming agents.

ALKALI SALTS
� Hot potassium carbonate (K2CO3) is used to remove
both CO2 and H2S.
� Best for the CO2 partial pressure is in the range 30–90
psi.
� The process is very similar in concept to the amine process,
in that after physical absorption into the liquid, the CO2
and H2S react chemically with the solution
� In a typical application, the contactor will operate at
approximately 300 psig (20 barg), with the lean
carbonate solution entering near 225°F (110°C) and
leaving at 240°F (115°C).

Process flow diagram for hot
potassium carbonate process

Batch Processes for Sweetening
� Iron Sponge (Fe2O3)
� Zink Oxide (ZnO)
� Molecular Sieve (crystalline sodium alumino silicates)

Iron Sponge Process
� This process is applied to sour gases with low H2S concentrations
(300 ppm) operating at low to moderate pressures (50–500 psig).
� Carbon dioxide is not removed by this treatment.
� The inlet gas is fed at the top of the fixed-bed reactor filled with
hydrated iron oxide and wood chips.
� 2Fe 2O 3 + 6H 2S ↔ 2Fe 2S 3 + 6H 2O
� The reaction requires an alkalinity pH level 8–10 with controlled
injection of water.
� The bed is regenerated by controlled oxidation as
� 2Fe 2S 3 + 3O 2 ↔ 2Fe 2O 3 + 6S
� Some of the sulfur produced might cake in the bed and oxygen should
be introduced slowly to oxide this sulfur, Arnold and Stewart [2]:
� S 2 + 2O 2 ↔ 2SO 2

Iron sponge ….

Zinc Oxide
� Zinc oxide can be used instead of iron oxide for the
removal of H 2S, COS, CS 2, and mercaptans.
� However, this material is a better sorbent and the exit H 2S
concentration can be as low as 1 ppm at a temperature of
about 300 o C.
� The zinc oxide reacts with H 2S to form water and zinc
sulfide:
� ZnO + H 2S ↔ ZnS + H 2O
� A major drawback of zinc oxide is that it is not possible to
regenerate it to zinc oxide on site, because active surface
diminishes appreciably by sintering.
� Much of the mechanical strength of the solid bed is lost
due to fines formation, resulting in a high-pressure-drop
operation.

Molecular Sieve
� Molecular sieves (MSs) are crystalline sodium alumino
silicates (Al/Si) and have very large surface areas and a
very narrow range of pore sizes.
� They possess highly localized polar charges on their
surface that act as adsorption sites for polar materials
at even very low concentrations.
� This is why the treated natural gas could have very low
H2S concentrations (4 ppm).
� In order for a molecule to be adsorbed, it first must be
passed through a pore opening and then it is adsorbed
on an active site inside the pore.
� There are four major zones in a sieve bed

Adsorption zone in a molecular sieve bed

Sweetening of natural gas by
molecular sieves

� If it is desired to remove H2S, a MS of 5 A* is selected
� If it is also desired to remove mercaptans, 13 X* is
selected.
� In either case, selection made to minimize the
catalytic reaction:
� H2S + CO2 ↔ COS + H2O
� Olefins, aromatics, and glycols are strongly adsorbed,
which may poison the sieves.