A Comprehensive Guide to Controlling H2S Emissions in Natural, Associated and Shale Gas Upgrading

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VULCAN PURIFICATION TECHNOLOGY
A Comprehensive Guide to Controlling H2S
Emissions in Natural, Associated and Shale
Gas Upgrading

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VULCAN PURIFICATION TECHNOLOGY
A Comprehensive Guide to Controlling H2S Emissions in Natural,
Associated and Shale Gas Upgrading
Hydrogen sulfide produced industrially can be controlled using a variety of
methods. Some of the methods can be used in combination, i.e., VULCAN
PURIFICATION TECHNOLOGY - “HYBRID SYSTEMS”. Some of the methods
discussed are more commonly used in specific industrial processes. The process
chosen is based on the end-use of the gas, the gas composition and physical
characteristics, and the amount of gas that needs to be treated. Hydrogen sulfide
removal processes can be either physical-chemical or biological.
Claus process
The Claus process is used in oil and natural gas refining facilities and removes
H2S by oxidizing it to elemental sulfur. The following reactions occur in various
reactor vessels and the removal efficiency depends on the number of catalytic
reactors used:
H2S + 3/2 O2  SO2 + H2O

(Eq. 1)

2H2S + SO2  3S0 + 2H2O

(Eq. 2)

H2S + ½ O2  S0 + H2O

(Eq. 3)

Removal efficiency is about 95% using two reactors, and 98% using four
reactors.
The ratio of O2-to-H2S must be strictly controlled to avoid excess SO2 emissions
or low H2S removal efficiency. Therefore, the Claus process is most effective for
large, consistent, acid gas streams (greater than 15 vol% H2S concentration).
When used for appropriate gas streams, Claus units can be highly effective at
H2S removal and also at producing high-purity sulfur.


Chemical oxidants
Chemical oxidants are most often used at wastewater treatment plants to control
both odor and the toxic potential of H2S. The systems are also often designed to
remove other odor causing compounds produced during anaerobic processes.
The most widely used chemical oxidation system is a combination of sodium
hydroxide (NaOH) and sodium hypochlorite (NaOCl), which are chosen for their
low cost, availability, and oxidation capability. Oxidation occurs by the following
reactions:
H2S + 2NaOH ↔ Na2S + 2H2O

(Eq. 4)

Na2S + 4NaOCl  Na2SO4 + 4NaCl

(Eq. 5)

The oxidants are continuously used in the process and therefore they provide an
operating cost directly related to the amount of H2S in the stream. This process is
only economically feasible for gas streams with relatively low concentrations of
H2S.
The gas phase must be converted to the liquid phase, as the reactions occur in
the aqueous phase in the scrubber. Countercurrent packed columns are the most
common type of scrubber, but other designs such as spray chambers, mist
scrubbers, and venturis are also sometimes used. The products of the above
reactions stay dissolved in the scrubber solution until the solution is saturated. To
avoid salt precipitation, the scrubber solution is either continuously or periodically
removed and replenished.

Caustic scrubbers
Caustic scrubbers function similarly to chemical oxidation systems, except that
caustic scrubbers are equilibrium limited, meaning that if caustic is added, H2S is
removed, and if the pH decreases and becomes acidic, H2S is produced.
The following equation describes the caustic scrubber reaction:
H2S + 2NaOH ↔ Na2S + 2H2O

(Eq. 6)


In a caustic scrubber, the pH is kept higher than 9 by continuously adding sodium
hydroxide (NaOH). A purge stream must be added to prevent salt precipitation.
However, if the purge stream is added back to other process streams, the
reaction is pushed towards the left and H2S is released.
For this reason, the spent caustic must be carefully disposed. Additionally, the
caustics are non-regenerable.

Adsorption
An adsorbing material can attract molecules in an influent gas stream to its
surface. This removes them from the gas stream. Adsorption can continue until
the surface of the material is covered and then the materials must either be
regenerated (undergo desorption) or replaced.
Regeneration processes can be both expensive and time consuming. Activated
carbon is often used for the removal of H2S by adsorption. Activated carbon can
be impregnated with potassium hydroxide (KOH) or sodium hydroxide (NaOH),
which act as catalysts to remove H2S.
Activated carbon and other materials used for adsorption are discussed in detail
in a later section.
H2S scavengers
Hydrogen sulfide scavengers are chemical products that react directly with H2S
to create innocuous products. Some examples of H2S scavenging systems are:
caustic and sodium nitrate solution, amines, and solid, iron-based adsorbents.
These systems are sold under trademarks by various companies.
The chemical products are applied in columns or sprayed directly into gas
pipelines. Depending on the chemicals used, there will be various products of the
reactions. Some examples are elemental sulfur and iron sulfide (FeS2).


One commercially available H2S scavenging system using chelated iron H2S
removal technology is the LO-CATR(US Filter/Merichem) process, or VULCAN
Series VGP-400N high capacity / efficiency fixed-bed absorbents
They can remove more than 200 kg of S/day and are ideal for landfill gas.

Amine absorption units
Alkanolamines (amines) are both water soluble and have the ability to absorb
acid gases. This is due to their chemical structure, which has one hydroxyl group
and one amino group. Amines are able to remove H2S by absorbing them, and
then dissolving them in an aqueous amine stream.
The stream is then heated to desorb the acidic components, which creates a
concentrated gas stream of H2S, which can then be used in a Claus unit or other
unit to be converted to elemental sulfur. This process is best used for anaerobic
gas streams because oxygen can oxidize the amines, limiting the efficiency and
causing more material to be used.
Amines that are commonly used are monoethanolamine (MEA), diethanolamine
(DEA), and methyldiethanolamine (MDEA).
Amine solutions are most commonly used in natural-gas purification processes.
They are attractive because of the potential for high removal efficiencies, their
ability to be selective for either H2S or both CO2 and H2S removal, and are
regenerable. One problem associated with this process is that a portion of the
amine gas is either lost or degraded during H2S removal and it is expensive and
energy intensive to regenerate or replace the solution. Other disadvantages
include complicated flow schemes, foaming problems, and how to dispose of foul
regeneration air.


Liquid-phase oxidation systems
Liquid-phase oxidation systems convert H2S into elemental sulfur through redox
reactions by electron transfer from sources such as vanadium or iron reagents.
The Stretford process is regarded as the first liquid-phase oxidation system.
Hydrogen sulfide is first absorbed into an aqueous, alkali solution. It is then
oxidized to elemental sulfur, while the vanadium reagent is reduced. This
process is relatively slow and usually occurs in packed columns or venturis.
However, vanadium is toxic and these units must be designed so that both the
“sulfur cake” and solution are cleaned.
Because of problems with the Stretford process, liquid-phase oxidation systems
have now been designed using iron-based reagents. Chelating agents are used
to increase iron solubility in water so that liquid streams, as well as gas phases,
can be treated.
Ferric iron is reduced to ferrous iron in the process, while hydrogen sulfide is
oxidized to elemental sulfur. Ferrous iron (Fe2+) can be regenerated by air
oxidation. The reaction between the hydrogen sulfide and iron occurs much
faster than in the Stretford process.
One system, LO-CATR by US Filter/Merichem, is an example of a H2S removal
system that utilizes chelated iron solution. The basic reactions are as shown in
Eq. 7 and 8:
2Fe3+ + H2S  2Fe2+ + S + 2H+

(Eq. 7)

2Fe2+ + 1/2 O2 + H2O  2Fe3+ + 2OH-

(Eq. 8)

The LO-CATR system is attractive for H2S removal from biogas streams because
it is over 99% effective, the catalyst solution is non-toxic, and it can operate at
ambient temperatures.
Other metal-based reagents can also be used. Magnesium and copper sulfate
solutions have been tested, but due to the complexity, costs, and severity of
reactions, it is unlikely that these reagents can be utilized for hydrogen sulfide
removal from biogas.


Physical solvents
Using physical solvents as a method to remove acid gases, such as H2S, can be
economical depending on the end use of the gas. Hydrogen sulfide can be
dissolved in a liquid and then later removed from the liquid by reducing the
pressure. For more effective removal, liquids with higher solubility for H2S are
used. However, water is widely available and low-cost.
Water washing is one example of a physical solvent-utilizing process. Water also
has solubility potential for CO2, and selective removal of just H2S has not proved
economical using water.
Other physical solvents that have been used are methanol, propylene carbonate,
and ethers of polyethylene glycol.
Criteria for selecting a physical solvent are high absorption capacity, low
reactivity with equipment and gas constituents, and low viscosity. One problem
with using physical solvents is that a loss of product usually occurs, due to the
pressure changing processes necessary to later remove the H2S from the
solvent. Losses as high as 10% have been found.

Membrane processes
Membranes can be used to purify biogas. Partial pressures on either side of the
membrane control permeation through the membrane. Membranes are not
usually used for selective removal of H2S, and are rather used to upgrade biogas
to natural gas standards. There are two types of membrane systems: high
pressure with gas phase on both sides of the membrane, and low pressure with a
liquid adsorbent on one side. In one case, cellulose acetate membranes were
used to upgrade biogas produced by anaerobic digesters.


Biological methods
Microorganisms have been used for the removal of H2S from biogas. Ideal
microorganisms would have the ability to transform H2S to elemental sulfur, could
use CO2 as their carbon source (eliminating a need for nutrient input), could
produce elemental sulfur that is easy to separate from the biomass, would avoid
biomass accumulation to prevent clogging problems, and would be able to
withstand a variety of conditions (fluctuation in temperature, moisture, pH,
O2/H2S ratio, for example).
Chemotrophic bacterial species, particularly from the Thiobacillus genus, are
commonly used. Chemotrophic thiobacteria can be used both aerobically and
anaerobically. They can utilize CO2 as a carbon source and use chemical energy
from the oxidation of reduced inorganic compounds, such as H2S. In both
reactions, H2S first dissociates:
H2S ↔ H+ + HS-

(Eq. 9)

Under limited oxygen conditions, elemental sulfur is produced:
HS- + 0.5O2 → S0 + OH-

(Eq. 10)

Under excess oxygen conditions, SO42- is produced, which leads to acidification:
HS- + 2O2 → SO42- + H+

(Eq. 11)

One chemotrophic aerobe, Thiobacillus ferroxidans, removes H2S by oxidizing
FeSO4 to Fe2 (SO42-)3, and then the resulting Fe3+ solution can dissolve H2S and
chemically oxidize it to elemental sulfur.
These bacteria are also able to grow at low pH levels, which make them easy to
adapt to highly fluctuating systems.
Biological H2S removal can be utilized in biofilter and bioscrubber designs. One
commercially available biological H2S removal system is Thiopaq. It uses
chemotrophic thiobacteria in an alkaline environment to oxidize sulfide to
elemental sulfur. It is able to simultaneously regenerate hydroxide, which is used
to dissociate H2S.
Flows can be from 200 Nm3/h to 2,500 Nm3/h and up to 100% H2S, with outlet
concentrations of below 4 ppmv.

Another system, H2SPLUS SYSTEMR, uses both chemical and biological
methods to remove H2S. A filter consisting of iron sponge inoculated with
thiobacteria is used. There are about 30 systems currently in use in the U.S.,
mostly at agrifood industry wastewater treatment plants.
Gas flows of 17 to 4,200 m3/h can be used, and removal capacity is up to 225 kg
H2S/day.
Materials Used for H2S Adsorption
Various materials are used as adsorbents for hydrogen sulfide. These materials
have specific surface properties, chemistry, and other factors that make them
useful as H2S adsorbents. A study by Yan, Chin, Ng, Duan, Liang, and Tay
(2004) about mechanisms of H2S adsorption revealed that H2S is first removed
by physical adsorption onto the liquid water film on the surface of the adsorbent,
then by the dissociation of H2S and the HS- reaction with metal oxides to form
sulfides, then with alkaline species to give neutralization products, and finally with
surface oxygen species to give redox reaction products (such as elemental
sulfur). If water is not present, CO2 can deactivate the alkaline-earth-metal-based
reaction sites and lead to lower H2S removal.
Additionally, the oxidation reactions of H2S are faster when Ca, Mg, and Fe are
present, as they are catalysts for these reactions. Physical adsorption also
occurs in pores, and pores between the size of 0.5 and 1 nm were found by Yan
et al. to have the best adsorption capacity. Significant adsorption occurs when a
material is able to sustain multiple mechanisms. The materials described in this
section have been shown to utilize one or more of these mechanisms and have
shown potential as H2S adsorbent materials.
Activated carbon
Activated carbons are frequently used for gas adsorption because of their high
surface area, porosity, and surface chemistry where H2S can be physically and
chemically adsorbed. Much of the research has focused on how the physical and
chemical properties of various activated carbons affect the breakthrough capacity
of H2S.
Most activated carbon tested is in granular form, called Granular Activated
Carbon (GAC). Activated carbon can come in two forms: un-impregnated and
impregnated.

Impregnation refers to the addition of cations to assist as catalysts in the
adsorption process. Un-impregnated activated carbon removes hydrogen sulfide
at a much slower rate because activated carbon is only a weak catalyst and is
rate limited by the complex reactions that occur.
However, using low H2S concentrations and given sufficient time, removal
capacities of impregnated and un-impregnated activated appear to be
comparable in laboratory tests. Removal capacities may vary greatly in on-site
applications, as the presence of other constituents (such as VOCs) may inhibit or
enhance the removal capacity, depending on other environmental. The cations
added to impregnated activated carbon are usually caustic compounds such as
sodium hydroxide (NaOH) or potassium hydroxide (KOH), which act as strong
bases that react with H2S and immobilize it.
Other compounds used to impregnate activated carbons are sodium bicarbonate
(NaHCO3), sodium carbonate (Na2CO3), potassium iodide (KI), and potassium
permanganate (KMnO4). When caustics are used, the activated carbon acts
more as a passive support for the caustics rather than actively participating in the
H2S removal because of its low catalytic ability. The caustic addition has a
catalytic effect by oxidizing the sulfide ions to elemental sulfur until there is no
caustic left to react.
The reactions that un-impregnated activated carbon undergoes to facilitate H2S
removal is far less understood. A typical H2S adsorption capacity for impregnated
activated carbons is 150 mg H2S/g of activated carbon. A typical H2S adsorption
capacity for un-impregnated activated carbons is 20 mg H2S/g of activated
carbon.
Much research has focused on mechanisms of H2S removal using activated
carbon.
A Researcher from the Department of Chemistry in the City College of New York,
Teresa Bandosz, has performed numerous studies on the adsorption of H2S on
activated carbons. Her studies have focused on hydrogen sulfide adsorption on
activated carbons as it relates to surface properties, surface chemistry,
temperature, concentration of H2S gas, addition of cations, moisture of gas
stream, and pH. These experiments have used both biogas from real processes
and laboratory produced gases of controlled composition.


In a study by Bagreev and Bandosz (2002), NaOH impregnated activated carbon
was tested for its H2S removal capacity. Four different types of activated carbon
were used and different volume percentages of NaOH were added. The results
showed that with increasing amounts of NaOH added, the H2S removal capacity
of the activated carbons increases. This effect occurred until maximum capacity
was reached at 10 vol% NaOH.
This result was the same regardless of the origin of the activated carbon, and
was even the same when activated alumina was used. This result implies that
the amount of NaOH present on the surface of the material is a limiting factor for
the H2S removal capacity in NaOH impregnated activated carbons.
Although impregnated activated carbon can be an effective material for the
adsorption of H2S, there are a few drawbacks of using this material.
First, the addition of caustics lowers the ignition temperature and therefore
the material can self-ignite and is considered hazardous.
Secondly, the addition of caustics to activated carbon increases the costs
of production.
Lastly, because of the high cost of activated carbon, it is desirable to “wash” or
“clean” the activated carbon in order to regenerate it so that it will regain some of
its ability to remove H2S (a leading producer of activated carbon, priced an unimpregnated activated carbon used in wastewater treatment applications to be
$8.44/lb and impregnated activated carbon is even more expensive).
One of the simple ways to regenerate the activated carbon is to wash it with
water.
The caustic additions to impregnated activated carbon cause H2S to be oxidized
to elemental sulfur, which cannot be removed from the activated carbon by
washing with water and therefore costs of H2S removal are increased due to the
need to purchase more adsorbent.


As of yet, the complete mechanisms by which H2S is removed using activated
carbon are not well understood. It is accepted that removal occurs by both
physical and chemical mechanisms. One chemical removal mechanism is
caused by the presence of heteroatoms at the carbon surface. Important
heteroatoms are oxygen, nitrogen, hydrogen, and phosphorus. They are
incorporated as functional groups in the carbon matrix and originate in the
activated carbon as residuals from organic precursors and components in the
agent used for chemical activation.
They are important in the chemical removal of H2S because they influence the
pH of the carbon, which can control which species (acidic, basic, or polar) are
chemisorbed at the surface. Another important factor in H2S removal has been
the presence of moisture on the carbon surface. Bandosz has a theory that, in
un-impregnated activated carbon, H2S will dissociate in the film of water at the
carbon surface and the resulting sulfide ions (HS-) are oxidized to elemental
sulfur (Bandosz, 2002).
Bandosz found that the activated carbon’s affinity for water should not be greater
than 5%, otherwise the small pores of the adsorbent become filled by condensed
adsorbate and the direct contact of HS- with the carbon surface becomes limited.
It was found that some affinity for water adsorption was desirable in an
adsorbent. However, when biogas is used at the source of H2S, it is not practical
to optimize the amount of water on the media because biogas is usually already
water saturated.
Too much water can interfere with the H2S removal reactions because the water
in gaseous form reacts with CO2 to form carbonates and contributes to the
formation of sulfurous acid which can deactivate the catalytic sites and reduce
the capacity for hydrogen sulfide to react and be removed.
Bandosz and her research group have focused considerably on the mechanisms
of H2S removal on un-impregnated activated carbon. It was found that as
oxidation occurs on the surface of the carbons, the capacity for adsorption
decreases.
The adsorption and immobilization of H2S was found to be related to its ability to
dissociate and this was inhibited by the oxidized surface of the activated carbons.
No relationship between pore structure and adsorption ability was found, but it
was noted that a higher volume of micropores with small volumes enhances the
adsorption capacity.


The most important finding of this study was that the pH of the surface has a
large affect on the ability of H2S to dissociate.
Acidic surfaces (<5) decrease the H2S adsorption capacity of the activated
carbons.
The concentration of H2S in the inlet gas may affect the adsorption capacity of
activated carbons. One study indicated that the H2S removal capacity of
impregnated activated carbons increases when the H2S concentration
decreases. In the same study, it was also found that small differences in oxygen
content (1-2%) and different temperatures (from 38°C-60°C) did not have a
significant effect on the hydrogen sulfide removal.
In another study, it was found that adsorption capacities of H2S on impregnated
activated carbon slightly decrease with increasing temperature (30 and 60°C
were tested).
The effect of low H2S concentration on removal capacity can be explained by the
fact that the low concentration slows down oxidation kinetics, which in turn slows
down the rate of surface acidification. Surface acidification has been shown to be
detrimental to H2S removal because H2S does not dissociate readily in acidic
conditions.

Zeolites (Molecular sieves)
Zeolites, also commonly referred to as molecular sieves, are hydrated aluminosilicates which are highly porous and are becoming more commonly used to
capture molecules.
The size of the pores can be adjusted by ion exchange and can be used to
catalyze selective reactions. The pores are also extremely uniform. Zeolites are
especially effective at removing polar compounds, such as water and H2S, from
non-polar gas streams, such as methane. Current research is focusing on how to
implement zeolites in “clean coal” technology, or Integrated Gasification
Combined Cycle (IGCC) power plants. Some studies about the use of zeoliteNaX and zeolite-KX as a catalyst for removing H2S from IGCC gas streams have
been performed.
One study found a yield of 86% of elemental sulfur on the zeolites over a period
of 40 hours (Lee, Jun, Park, Ryu, & Lee, 2005).


Gas streams from IGCC power plants are at a high temperature, between 200
and 300°C. Further, molecular sieves have recently been used as a structural
support for other types of adsorbents (Wang, Ma, Xu, Sun, & Song, 2005).

Polymers
There has not been significant research done using polymers as adsorbents for
H2S, but a a study was found where polymers were used in conjunction with
other materials to enhance adsorption.
This study, by Wang et al. (2008), studied the effects on H2S adsorption of
adding various compositions of a polymer, polyethylenimine (PEI), to a molecular
sieve base. The mesoporous molecular sieves tested were amorphous silicates
with uniform mesopores. PEI was deposited on the samples in varying
compositions of 15-80 wt% of the molecular sieve.
The results showed that the lower temperature tested (22°C) had higher sorption
capacity, a loading of 50 wt% PEI on the molecular sieves had the best
breakthrough capacity, and that a loading of 65 wt% PEI had the highest
saturation capacity.
Additionally, the sorbents can easily be regenerated for continued H2S
adsorption. The authors suggest that H2S adsorbs onto the amine groups of the
PEI, and at low compositions of PEI on the molecular sieves the amines present
may be reacting with acidic functional groups on the molecular sieve surface. At
high compositions of PEI on the molecular sieves, the surface area of the
molecular sieve was significantly decreased and because the adsorption and
diffusion rates of H2S depend on surface area, the H2S was not able to be
effectively adsorbed.


Metal oxides
Metal oxides have been tested for hydrogen sulfide adsorption capacities. Iron
oxide is often used for H2S removal. It can remove H2S by forming insoluble iron
sulfides. The chemical reactions involved in this process are shown in the
following equations:
Fe2O3 + 3H2S  Fe2S3 + 3H2O

(Eq. 12)

Fe2S3 + 3/2O2  Fe2O3 +3S

(Eq. 13)

Iron oxide is often used in a form called “iron sponge” for adsorption processes.
Iron sponge is iron oxide-impregnated wood chips. Iron oxides of the forms
Fe2O3 and Fe3O4 are present in iron sponge. It can be regenerated after it is
saturated, but it has been found that the activity is reduced by about one-third
after each regeneration cycle.
Iron sponge can be used in either a batch system or a continuous system. In a
continuous system, air is continuously added to the gas stream so that the iron
sponge is regenerated simultaneously. In a batch mode operation, where the iron
sponge is used until it is completely spent and then replaced, it has been found
that the theoretical efficiency is approximately 85%. Iron sponge has removal
rates as high as 2,500 mg H2S/g Fe2O3.
Some challenges associated with the use of iron oxide for hydrogen sulfide
removal from shale gas are that the process is chemical-intensive, there are
high operating costs, and a continuous waste stream is produced that must either
be expensively regenerated or disposed of as a hazardous waste.
There are some commercially produced iron oxide based systems that are able
to produce non-hazardous waste. One commercially available iron oxide base
system, Sulfatreat 410-HPR was found to have an adsorption capacity of 150 mg
H2S/g adsorbent through lab and field-scale experiments. (Abatzoglou & Boivin,
2009)
The iron sponge is a widely used and long-standing technology for hydrogen
sulfide removal.
Because of this, there are accepted design parameters for establishing an H2S
removal system. Table 2 summarizes these design parameters.


The iron sponge costs around $6/bushel (approx. 50 lbs) from a supplier, but
other technologies that utilize iron sponge, such as the Model-235 from Varec
Vapor Controls, Inc., can cost around $50,000 for the system and initial media
(McKinsey Zicarai, 2003).
Other metal oxides besides iron oxide have been used to remove hydrogen
sulfide.
Carnes and Klabunde (2002) found that the reactivities of metal oxides depend
on the surface area, crystallite size, and intrinsic crystallite reactivity.
It was found that nanocrystalline structures have better reactivity with H2S than
microcrystalline structures, high surface areas promote higher adsorption, and
high temperatures are ideal (but not higher than the sintering temperature,
otherwise a loss of surface area occurs). Also, the presence of Fe2O3 on the
surface furthers the reaction.


The reason proposed for this was that H2S reacts with the Fe2O3 to form iron
sulfides that are mobile and able to seek out the more reactive sites on the core
oxide and exchange ions, and ultimately acts as a catalyst in the reaction.
However, at ambient temperatures this effect is not as clearly seen. In the study,
calcium oxide was the most reactive (and with additions of surface Fe2O3 it was
even more reactive), followed by zinc oxide, aluminum oxide, and magnesium
oxide.
In one study, Rodriguez and Maiti (2000) found that the ability of a metal oxide to
adsorb H2S depends on the electronic band gap energy: the lower the electronic
band gap energy, the more H2S is adsorbed.
This is because the electronic band gap is negatively correlated to the chemical
activity of an oxide and the chemical activity depends on how well the oxide’s
bands mix with the orbitals of H2S. If the bands mix well, then the oxide has a
larger reactivity towards the sulfur-containing molecules, and metal sulfides are
created, which cause H2S molecules to dissociate and the sulfur to be
immobilized in the metal sulfides. Use of metal oxides for hydrogen sulfide
removal can have problems such as low separation efficiency, low selectivity,
high costs, and low sorption/desorption rate.
Zinc oxides are used to remove trace amounts of H2S from gases at high
temperatures (from 200°C to 400°C), because zinc oxides have increased
selectivity for sulfides over iron oxides. Davidson, Lawrie, and Sohail (1995)
studied hydrogen sulfide removal on zinc oxide and found that the surface of zinc
oxide reacts with the H2S to form an insoluble layer of zinc sulfide, thereby
removing H2S from a gas stream.
Approximately 40% of the H2S present was converted over the ZnO adsorbent.
The reaction described in Equation 14 leads to H2S removal:
ZnO + H2S  ZnS + H2O

(Eq. 14)

Various commercial products use zinc oxide, and maximum sulfur loading on
these products is typically in the range of 300 to 400 mg S/g sorbent.


Sludge derived adsorbents
Because many commercially available adsorbents of H2S are costly or have
other associated problems, attention has been given to using various sludge
derived materials as adsorbents. When sludge undergoes pyrolysis, a material is
obtained with a mesoporous structure and an active surface area with chemistry
that may promote the oxidation of hydrogen sulfide to elemental sulfur.
The mechanisms of H2S removal described by Yan et al. (2004) can be applied
to sludge derived adsorbents. Sludge has a complex chemistry, but it has
enough of the reactive species given by Yan et al. that it could provide an
alternative to using non-impregnated activated carbon.
The efficiency of sludge at H2S removal has been found to be similar to that of
iron based adsorbents, but less efficient than impregnated activated carbon. A
concern with using sludge is that it may contain compounds which adversely
affect H2S removal.
Some compounds in question are derived from metal sludge produced by
industry. A study by Yuan and Bandosz (2007) mixed various weights of sewage
sludge and metal sludge derived from a galvanizing process used in industry,
pyrolyzed them, and tested them for hydrogen sulfide adsorption capacity. It was
found that the capacity for H2S adsorption is comparable to the capacity of
impregnated activated carbons, and that the adsorption capacity depends on the
overall sludge composition and the pyrolysis temperature.
Samples with higher content of sewage sludge pyrolyzed at higher temperatures
(800°C and 950°C) had the best adsorption capacity. The highest adsorption
capacity reported was less than 21 mg H2S/g adsorbent, which is less than the
adsorption capacity of un-impregnated activated carbon.


APPENDIX
Summary of H2S Removal Process Characteristics


Summary Table Comparing Dry-Based H2S Removal Processes from Shale
Gas


A Comprehensive Guide to Controlling H2S Emissions in Natural, Associated and Shale Gas Upgrading

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A Comprehensive Guide to Controlling H2S Emissions in Natural, Associated and Shale Gas Upgrading