353
15
Hydrogen Sulde Scavengers
15.1 INTRODUCTION
Hydrogen sulde (H
2
S) is a very toxic and pungent gas that causes problems in both the upstream
and downstream oil and gas industry.
1
Exposure to this gas even at fairly low concentrations can
cause serious injury or death. Natural gas for sale often requires the concentration of H
2
S to be
below about 4 ppm. H
2
S is often accompanied by smaller amounts of mercaptans (RSH or R
2
S) such
as methyl mercaptan CH
3
SH, aromatic sulde species, polysuldes, and carbonyl sulde (COS).
Hydrogen sulde is known as a sour gas, which is appreciably soluble in water. It behaves as a
weak acid partially dissociating into hydrosulde and sulde ions:
H
2
S + H
2
O = H
3
O
+
+ HS
pK
a
= 6.9
HS
+ H
2
O = H
3
O
+
+ S
2−
pK
a
= 19
The concentrations of the anionic species are dictated by the pH, particularly by the presence of
another acid gas, CO
2
. The relationships describing the partitioning of H
2
S have been reported.
80
Being a weak acid, H
2
S is corrosive, reacting with steels in wells and pipelines, causing pitting and
stress cracking corrosion and deposition of iron sulde scales.
2
Other sulde scales that have been
observed include zinc sulde and lead sulde (see Chapter 3 on scale control for furtherinformation).
There are several natural processes that can generate H
2
S in reservoirs.
81
They include bacterial
sulfate reduction by indigenous sulfate-reducing bacteria (SRBs), thermal cracking, and thermo-
chemical sulfate reduction (TSR) by hydrocarbons. Generally, H
2
S problems are negligible in elds
where the reservoir temperature is above 140°C–150°C, as SRBs do no thrive over this temperature.
It has been proposed that it is the TSR that leads to the largest amount of H
2
S; however, other stud-
ies suggest that TSR by hydrocarbons only takes place signicantly above 140°C (284°F) in the
reservoir.
3
This phenomenon involves hydrocarbon oxidation and sulfate reduction (from anhydrite
either naturally occurring or formed from injected sulfate anion in seawater) and produces as by-
products H
2
S, carbon dioxide, carbonate minerals, and heavy organosulfur compounds.
Hydrogen sulde production is usually signicantly higher in reservoirs that are seawater-ooded
for secondary oil recovery.
4
Seawater contains about 2800 ppm sulfate ions. These ions are reduced
to H
2
S by indigenous SRBs in the reservoir and by the TSR process, which eventually reaches the
production wells. The growth of SRBs also requires the presence of an easily metabolized carbon
source such as organic acids. These are usually found in high-enough quantities in the reservoir u-
ids to sustain SRB growth.
5,6
Volatile fatty acid ions such as acetate have historically been assumed
to be the favored nutrient source by SRB; however, recent eld experience has suggested that other
dissolved organic carbon sources are contributors.
82
One way to reduce reservoir souring is to treat
the injection water with sufcient biocide to prevent growth of SRB. Other preventive methods
include controlling SRB metabolism or promoting the growth of nonindigenous SRB.
83
Chapter 14
on biocides should be consulted for these methods. A nal method of preventing biogenic sulde
formation is to inject nonsulfated aquifer water, if it is available, or inject desulfated seawater using
membrane technology. In the latter case, not all the sulfate ions can be removed from seawater, but
enough are removed to reduce reservoir souring as well as sulfate scaling considerably.

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