Manage hydrogen sulfide hazards with chemical

®
Originally appeared in:
December 2014, pgs 73-76.
Used with permission.
Safety Developments
G. KENRECK, GE Water & Process Technologies,
The Woodlands, Texas
Manage hydrogen sulfide hazards
with chemical scavengers
Hydrogen sulfide (H2S) and its associated hazards are well
known in the oil and gas production and refining industries.
Legislation has been in place for years, imposing strict regulations on H2S levels of hydrocarbon streams in pipelines, and
in storage and shipping containers and in marine fuels. A variety of chemical scavengers are available to reduce both the
concentration and corresponding hazards of H2S in produced
water, produced gas, crude oil and refined products. There are
several pros and cons for the most common chemistries used
to scavenge H2S. The associated effectiveness and the potential
downstream impacts of these scavengers will be explored here.
Guidelines will be presented to facilitate the selection of the
most appropriate scavenger chemistry and application method
to reduce H2S efficiently and in a cost-effective manner.
of which can potentially lead to leaks or spills of petroleum
products and the subsequent exposure of personnel to H2S.
Furthermore, the presence of water (H2O), salts or carbon dioxide (CO2 ) can increase the corrosivity of H2S.
Toxic gas. H2S is a highly toxic, flammable and corrosive gas
Fluid
H2S equilibrium ratios
Naphtha, gasoline
1,000, vapor/1, liquid
Crude oil
100–200, vapor/1, liquid
Gasoil (GO), #6 oil
5–10, vapor/1, liquid
Oil/water
3.0–4.1 H2S, oil/ 1 H2S, water 1
that dissolves in hydrocarbon and water streams, and it is present in the vapor phase above these streams. It is found in natural gas. Also, it occurs naturally in oil and gas production and is
produced during refining processes. Therefore, safety precautions must be observed during extraction, storage, transportation and processing of crude oil or natural gas.
Partitioning of H2S to the oil, water and vapor phases is influenced by temperature, pH and pressure. Typical partitioning ratios are listed in TABLE 1.
Hazards. In a gaseous state, H2S is extremely hazardous to
health. It is heavier than air and will, therefore, collect in low
places, such as the bottom of storage or shipping vessels. The
human odor-detection limit ranges from 3 parts per billion
(ppb) to 20 ppb—meaning that its presence may be detected
long before it reaches a hazardous level. Once concentrations
exceed 150 parts per million (ppm), H2S will cause olfactory
fatigue, affecting the sense of smell such that the hazard is not
recognized.2 Acute effects of exposure to H2S include headaches, nausea, convulsions, coma and death. The health effects at various exposure levels are shown in TABLE 2.
The flammability limits for H2S range from a lower explosive limit (LEL) of 4% to an upper explosive limit (UEL) of
44%. Again, as it is heavier than air, H2S can collect in low
places, where any ignition source poses a significant danger of
fire and explosion.
Finally, H2S is a corrosive acid that can cause embrittlement or sulfide stress cracking (FIG. 1) or pitting (FIG. 2), all
MANAGEMENT MORE REGULATED
Because exposure to H2S can have such dire health consequences, including death, regulations have been promulgated
to manage H2S and minimize personnel exposure. Where exposure to H2S is possible, personnel are required to wear portable detection devices and appropriate personal protection
equipment (PPE), taking precautions if an “action-level” conTABLE 1. H2S equilibrium ratios
TABLE 2. Health effects at various H2S concentration levels2
H2S concentration
< 20 ppb
5 ppm
5–10 ppm
10 ppm–30 ppm
> 30 ppm
100 ppm
150 ppm–200 ppm
100 ppm–1,000 ppm
> 1,000 ppm
5,000 ppm
HYDROCARBON PROCESSING DECEMBER 2014
Health effects
Olfactory threshold (begin to smell)
Increase in anxiety symptoms (single exposure)
Relatively minor metabolic changes in
exercising individuals during short-term
exposures. Long-term exposure could result
in headaches, insomnia, nausea, eye or throat
irritation, or shortness of breath
Moderate irritation of the eyes
Short-term exposure can result in olfactory
fatigue (sense of smell is significantly impaired)
Immediately dangerous to life and health
concentration
Olfactory nerve paralysis, eye irritation,
potential damage to cornea
Serious respiratory, central nervous
and cardiovascular system effects
Loss of consciousness and possible death
Immediate death
Safety Developments
centration is detected.3 In addition, specifications are being
established to reduce levels of H2S in petroleum products and
to subsequently reduce the hazard of handling and transporting these products around the world. TABLE 3 lists some of these
regulations and specifications. It is important to note that regulations, such as CFR 1910.1000, are enforceable by law. Other
specifications, however, such as ISO 8217, are not regulated by
law but are commercial requirements.
PROS AND CONS
Several classes of chemicals effectively lessen the hazards
associated with H2S. Selection of an appropriate chemical H2S
scavenger, combined with its proper application, can help meet
product specifications and comply with the regulations now encountered in the oil industry. As each application may be unique,
characteristics to be considered when selecting an H2S scavenger
should include treatment economics, ease of handling and use,
efficiency of reaction, selectivity for H2S and irreversibility. Selecting the wrong scavenger can result in negative downstream
impacts. For example, if a metal salt is used in a fuel oil, it may
result in the ash content limit being exceeded and require the fin-
ished fuel to be discounted in price or reprocessed. Detailed descriptions of several types of H2S scavengers are provided here:
Triazine has been the benchmark H2S scavenger for decades, especially in the oil field. Triazine is a reaction product
of an amine (nitrogen-based) and formaldehyde. Although
formaldehyde is a listed carcinogen, in this form, the formaldehyde reactivity is retained without the adverse health impact.
Amines, such as methyl amine (MA) or monoethanolamine
(MEA), are used to produce water-based triazines; whereas
higher-molecular-weight amines, such as methoxypropylamine
(MOPA), are used to produce a water-free (oil-soluble) version.
Triazine reactions are well documented. The primary reaction product is dithiazine. One mole of triazine, regardless of
the amine used to produce the triazine, will generally react with
two moles of H2S and liberate two moles of amine.
The weight of amine released will vary depending on the
amine, but the moles of nitrogen released are identical. This is
important to know since the nitrogen contribution on a weight
basis to the treated fluid will be the same regardless of the amine
used to create the triazine. In some cases, when a crude oil has
been treated with triazine, the amines released in the reaction can
stabilize emulsions and deteriorate desalter performance. They
can also contribute to chloride salt formation and deposition in
distillation towers, with subsequent increases in corrosion and
fouling potential. The nitrogen released can ultimately end up at
the wastewater treatment plant (WWTP) and negatively impact
the equalization basin performance and microorganism health.
Triazines generally are more effective at higher pH ranges
because, as illustrated in FIG. 3,4 triazine half-life is exponentially
reduced as pH decreases. Because triazines release amines that
increase the pH of a system, it has been shown that the use of triazine in oil production can negatively impact the performance of
scale inhibitors by decreasing the solubility of calcium carbonate
TABLE 3. Regulatory history for H2S
29 CFR 1910.1000 (7/1/98)
29 CFR 1915.1000 Maritime sub regulation
FIG. 1. Example of sulfide stress cracking.
NIOSH; Occupational Exposure to Hydrogen Sulfide (1977)
DHEW (NIOSH) Publication 77-158
US Department of Transportation, 2000 Emergency Response
Guidebook, RSPA P 5800, 8th Ed.
MARPOL Annex VI
ISO 8217 H2S in marine fuels
Triazine half-life as a function of pH
1,000
Triazine half-life, sec
100
10
1
0.1
0.01
0.001
0.0001
0
FIG. 2. Localized corrosion, typical of sulfide pitting.
2
FIG. 3. Effect of pH on triazine.4
HYDROCARBON PROCESSING DECEMBER 2014
4
pH
6
8
10
Safety Developments
(CaCO3 ) in produced water.5 This, in turn, can lead to an increase
in the scale inhibitor needed to achieve the desired inhibition.
Finally, findings presented by the Esbjerg Institute of Technology at Aalborg University6 have shown that various side reactions can occur when H2S is the excess reactant in scavenging
applications. Dithiazine can undergo further reaction to form an
amorphous dithiazine (FIG. 4) and can contribute to deposition
and equipment fouling. These reactions can be avoided when using the correct treatment level of triazine in the application.
Due to its long-standing industry acceptance, combined with
its perceived economic benefit, triazine will most likely continue
to play a significant role as an H2S scavenger for years to come.
However, as crudes become more sour and the H2S content increases, triazine treatment levels will escalate as well. When this
happens, the potential negative downstream impact associated
with triazine may encourage the use of other types of chemistries.
Metal salts of organic acids (iron, zinc and magnesium)
typically react with H2S to form nonvolatile byproducts. In general, metal salts are water-free. Water-free scavengers may be
desirable in applications where temperatures exceed 350°F. Although reaction kinetics may be slower, compared to other types
of scavengers, these metal salts may blend more easily into hydrocarbon streams. However, metals and their byproducts can
contribute to fouling in exchangers or reactors, as well as increase
the ash content in finished fuels. Therefore, this class of scavenger is generally used for reducing H2S levels in bitumen, but
would not be appropriate for use in refinery feedstocks and fuels.
Formaldehyde and acrolein are very reactive with H2S,
however, they are typically not recommended as scavengers
because of the health hazards associated with their use and
handling. Formaldehyde is a listed carcinogen, and acrolein is a
highly toxic gas. Reaction products may decompose in the refinery furnaces to form methyl sulfides or carbon disulfide (CS2 ),
which may have deleterious downstream impacts, such as catalyst poisoning during processing of treated petroleum products.
Mixing oxidizers and organics is generally restricted by
best practices; therefore, the use of oxidizers, such as hydrogen peroxide or nitrites/nitrates, to scavenge H2S is not appropriate for petroleum streams but they can be used in water
systems. However, they are not considered to be economically
effective, and the handling of hydrogen peroxide presents additional risk of fire or explosion.
Amines are relatively safe to handle, less expensive and fairly effective chemicals for scavenging H2S. In fact, gas desulfurization units use various amines to remove H2S from the gas.
Unfortunately, the reaction with H2S is reversible as temperatures increase or pH decreases. Amines also react with CO2 and
certain acids. In many cases, these aspects limit the application
of amines. The low solubility of amines in fuels and their reaction byproducts also tend to limit their use.
Oil-based aldehyde derivatives can be used for scavenging H2S in gas or high-temperature applications. This class of
chemicals may not truly be oil-soluble but are water-free and
are delivered in a polar organic solvent to prevent the introduction of water. The overall treatment cost of these products is
generally higher than water-based alternatives.
Non-amine chemistry is the final class of scavengers addressed here, and this class includes aliphatic aldehydes that react effectively with H2S. The treatment cost is similar to that of
triazines. These scavengers are relatively safe to handle and do
not produce amines from their reaction with H2S. This avoids
the problems associated with the use of triazines—specifically,
nitrogen impact at the WWTP and corrosive amine chloride
formation in refining process equipment. This chemistry also
minimizes the formation of CS2 and similar sulfur compounds
that have been found to migrate to naphtha cuts and poison
process catalysts. Non-amine H2S scavengers are especially
beneficial in treating crude oils and refinery feedstocks. They
have also been used in light distillate fuels to scavenge H2S
when nitrogen contamination is a concern.
SCAVENGER SELECTION
The proper selection of the chemistry and application
methodology is determined by the fluid to be treated, the system where the scavenger will be injected into the fluid, and the
end use of the fluid to be treated. There are several applications
and treatment options worthy of exploration.
Crude oil may be treated as it is produced to prevent personnel exposure to H2S. Treatment at the wellhead, or as oil
is transferred to tankage, or as containers are being loaded or
unloaded, is essential to reducing the risk of exposure to H2S.
However, the production of more sour crudes and highersulfur crudes results in increased scavenger levels in the crude
oil. This may amplify the negative downstream impacts. The
oil producer may understand the value of treatment, but may
not fully grasp the magnitude of the downstream impacts that
those chemicals can have in the refining process and even in
finished fuel quality. Triazines have been successfully used to
reduce H2S in crude oil, but, they can also contribute to multiple downstream issues. The use of non-amine scavengers can
help avoid many of these problems.
Gas produced at the wellhead may be high in H2S. However, treatment at the point of production can be costly, and
can also cause fouling, corrosion or scale deposition in gas processing and transmission systems. Typically, natural gas is deOH
+
SH
HO
N
S
O
N
S
S
SH
S
H2O
SH
HS
O
N
+
S
SH
O
S
S
S
SH
OH
HS
HN
S
S
OH
O
N
S
S
S
S
S
S
S
S
HN
S
FIG. 4. Formation of amorphous dithiazine.6
HYDROCARBON PROCESSING DECEMBER 2014
S
Safety Developments
TABLE 4. Applications and typical treat rates for various H2S scavenger chemistries
Chemical family
Applications
Water-based triazine
Crude, GO, LPG, finished fuel, gas streams
Water-free triazine
Hot streams: bitumen, GO, fuel oil
1.6
Metal salts
Bitumen
2.5
Amine
GO, LPG, gas streams
0.33
Water-free aldehyde derivatives
Hot streams: bitumen, GO, fuel oil
1.15
Non-amines: Water-based aliphatic aldehydes
Crude, naphtha, GO, finished fuel, water
0.9
a
Relative treat rate, l/kg H2Sa
1
The values shown in Table 4 are normalized such that water-based triazine, considered a benchmark for H2S scavenging in the oil industry, is 1.
sulfurized in amine absorbers. Where this is not possible, scavengers may be needed. In this case, attention should be given
to the potential downstream impacts. Triazines have been used
in gas systems, but, when they are injected into an H2S-rich
environment, they may form amorphous dithiazine or trithiane. This, in turn, can cause fouling or deposition in control
valves or compressors. Oil-based scavengers have been used in
these applications; however, proper liquid removal equipment
is required downstream of the application to prevent the reaction products from carrying down the pipeline. Triazines and
amines have been successfully used in liquefied light petroleum fractions where water-based reaction products are easily
removed and the H2S is effectively reduced.
GO and heavy cuts of petroleum products, such as fuel oils,
are processed at elevated temperatures. Application of scavengers above 350°F may require water-free chemistry. Amines
can be used, provided the fluid will not be further processed
or refined, due to the deleterious effects previously described.
Water-based triazines have been successfully used in high-temperature applications when the injection point is located in a
rundown line and the temperature is below 350°F. Since these
hot streams are usually below the saturation limit for water, the
water from the scavenger can solubilize, thus minimizing the
potential for steam formation and the associated pressure and
flashing or foaming in the storage tanks. Distribution of the
scavenger into viscous fluids is also a challenge; therefore, a
properly installed injection system that distributes the additive
into the fluid to be treated is essential for effective performance.
Gasoline and naphtha occasionally require treatment to
reduce H2S levels. In some cases, the petroleum fluid is well below the saturation limit for water. In these cases, special attention must be taken to ensure efficient reaction and prevent dehydration of the scavenger. Amines, triazines and non-amines
have been used to effectively scavenge H2S in these streams.
The different H2S scavenger chemistries are summarized in
TABLE 4, along with application areas and typical treat rates.
APPLICATION METHODOLOGY
The application methodology for H2S scavengers is very
important for effective performance, and each application is
unique. Therefore, site-specific application methodologies
and dose requirements should be established by an application
expert. Proper treatment levels for H2S scavengers depend on
many factors such as system size, unit operating conditions and
system design. In most cases, for consistent effectiveness, H2S
scavengers should be fed continuously by a chemical propor-
tioning pump. Injection location and feedrates vary depending on system design and stream composition. For best performance, H2S scavenger programs should be conscientiously
evaluated by routinely recording critical unit parameters including feed composition, temperature and program targets.
Use this information to make adjustments to the chemical feed
rate and the measured H2S concentrations in the treated fluid.
The application methodology is critical for both effective
performance and optimum economics. For example, either
under-treatment or overtreatment with triazines can have serious consequences. Either case could occur if the application
system for the scavenger is not properly designed to optimize
the amount of scavenger that is to be used. Under-treatment
could leave H2S residuals and not fully mitigate the risks associated with H2S. Overtreatment can stabilize emulsions, negatively impacting desalter performance. If additional amine
content is added, this increases the potential for chloride salt
formations in process equipment. It also boosts nitrogen loading to the wastewater plant.
MAKE THE FINAL DECISION
Proper selection and application of H2S scavengers can effectively lower H2S levels in hydrocarbon fluids and reduce the
risk of personnel exposure to the potentially lethal hazards of
H2S. The properties, effectiveness and impacts of chemicals
used to reduce H2S are important factors to consider when selecting an H2S scavenger. Selecting the proper injection system
and location can improve the efficiency of the treatment of H2S
and the performance of the application. An experienced application specialist who understands the aspects of scavengers
and appropriate application methodology can design an efficient and effective program that can reduce the overall treatment cost and risks associated with H2S, while also meeting
H2S specifications.
LITERATURE CITED
1Eden, B., P. J. Laycock and M. Fielder, Oil Field Reservoir Souring, HSE Books,
ISBN 0-7176-0637-6, 1993.
2Skrtic, L., “Hydrogen Sulfide, Oil and Gas, and People’s Health,” May 2006.
3Wanek, R., “Monitoring H2S to meet new exposure standards,” Drager Safety.
4Bakke, J. M., J. Buhaug and J. Riha, “Hydrolysis of 1,3,5-Tris(2-hydroxyethyl)
Hexahydro-s-triazine and its Reaction with H2S,” Ind Eng Chem Res, 2001, 40,
6051-6054.
5Sumestry, M. and H. Tedjawidjaja, “Case study: Calcium carbonate-scale inhibitor performance degradation because of H2S scavenger injection in Semoga field,”
Oil and Gas Facilities, February 2013.
6
Soegaard, E. G., “Investigation of Fouling Formation during H2S Scavenging with
1,3,5-tri-(2-hydroxyethyl)-hexahydro-s-triazine,” Maersk Oil and Dansk Shell,
Esbjerg Institute of Technology at Aalborg University, 2012.
Eprinted and posted with permission to GE Water & Process Technologies from Hydrocarbon Processing
December © 2014 Gulf Publishing Company