Page 181 - Handbook Of Multiphase Flow Assurance

Reservoir souring 177

Both sulfate-reducing bacteria (SRB) and nitrate-reducing bacteria (NRB) may already be
present in the reservoir. Bacterial activity may be subdued due to high reservoir temperature.
Bacteria become more active in the temperature range between 10 °C and 70 °C. As water is
injected into the reservoir, it usually lowers the temperature. Fresh water is seldom available
2−
offshore, so seawater may be injected. Seawater carries dissolved sulfate ions SO 4 with it
into the reservoir. Seawater usually contains 0.26 wt% of sulfate. Along with lowering the
temperature to a more comfortable range, seawater also brings food for the sulfate-reducing
bacteria.
SRB bacteria become more active and release H 2 S which over several years migrates with
the reservoir fluid to the producer wells and causes increased H 2 S concentration in the pro-
duced fluids.

Mitigation of reservoir souring

Usually generation of H 2 S by SRB bacteria is prevented or reduced by reduction of their
activity. This is accomplished by either addition of calcium nitrate to the injection water in 70–
80 mg/L dosage in order to activate the NRB and thus suppress the activity of SRB. Another
method is the removal of sulfate ions in topsides desulphation plant. Desulphated seawater
is injected into the reservoir without activating the bacteria.
Batch deployment of biocides such as THPS at 300–500 ppm is used. Acrolein is very rarely
used.
An alternative method may be to suppress the bacterial activity by allowing the injected
seawater to warm up to reservoir conditions. Injected seawater is usually cold as it flows
through water injection pipeline exposed to ambient seabed temperature, which is commonly
around 4 °C. Water gains some heat while flowing down the injection well from heat exchange
with rock. If well were drilled deeper than the perforation depth, and injected water flowed
down the tubing to the bottomhole and up through annulus to the injection perforations, it
would gain more heat from the rock. However, such method may be expensive to implement
due to the offshore well drilling cost.

Treatment of sour production
Wells which are already producing H 2 S are commonly treated with H 2 S scavenger chem-
icals. Usually triazine is used at 20–40% active component dissolved in toluene or similar
solvent as H 2 S scavenger.
Usually H 2 S is dealt with in one of the following methods: corrosion inhibitor is injected
to protect production systems made of carbon steel; use of corrosion-resistant alloy (CRA) for
the production system construction; injection of H 2 S scavenger chemical; amine scrubbing.
The first three methods are applicable between reservoir and separator. Amine scrubbing can
only be done in a surface or topsides process equipment.
The capital cost of H 2 S scavenger chemicals is usually low, with low space requirement.
However, the operating cost is high and can reach $10/pound of sulfur. The economic limit
for H 2 S scavenger deployment is usually $3000–4000/day. Chemical demand may be as high
as 20 pounds of H 2 S scavenger to remove 1 pound of H 2 S.