American Oil and Gas Reporter - May 2020 - 61

SpecialReport: Production & Processing

Direct-treat applications of the
new processing technology are
operating at pressures between
30 and 180 psig, with flow rates
from 750,000 Mcf/d to 25 MMcf/d.
The process has successfully
and continuously treated H2S
from 200 to 40,000 parts per million, and demonstrated successful treatment from 0.1 to 16 long
tons of sulfur per day. The highpurity and quality of the sulfur
makes it ideal for use as an agricultural fertilizer.

nology are in operation in West and South
Texas at pressures between 30 and 180
psig, with designs in place to operate up
to 1,440 psig, and flow rates between
750,000 Mcf and 25 million cubic feet a
day. The process has successfully and
continuously treated H2S levels from 200
to 40,000 parts per million, with a tailgas treater designed to handle 40% H2S
now under construction. In terms of sulfur
loading, the process has demonstrated
successful treatment from 0.1 to 16 long
tons a day.
All units have reported greater than
99% uptime, with cumulative operating
hours totaling more than 40,000 hours.
Since 2018, the units have treated and
produced more than 9 million pounds
(4,000 long tons) of sulfur. At no time
was the level of H2S measured in the
outlet gas stream greater than 4.0 ppm
by volume, and was less than 1.0 ppm
greater than 99.9% of the operating time.
The sulfur quality is better than 99%
pure, which makes it readily used as
an agricultural fertilizer. The particle
sizes are ideally suited for integrating
into soil. The filter cake cleaning process
removes nearly all the chemistry, and
the cake retains 15%-30% moisture,
which can undergo further dehydration
if necessary. The only other components
found in the solid waste stream are
trace amounts of hydrolyzed surfactant,
which ultimately biodegrades within
days of disposal.

Field Applications
An operator in South Texas was seeking
to reduce lease operating expenses by replacing a triazine-based scavenger with
an alternative technology for wellhead
treating. One site was selected as part of
an early development program, and then
two subsequent sites were chosen for
commercial units after the successful
pilot. The total gas flow rate for all three
sites was 13 MMcf/d containing an average
of 1,300 ppmv of H2S. The total sulfur
production was approximately 1,400
pounds/day). The result saw the average
site treating costs reduced by 43%, including the amortized capital expenditure
of the equipment. The units have been
operating continuously with 99% uptime
since their commissioning in late 2018.
On a larger scale, an operator in West
Texas was seeking to treat H2S in associated
gas production on its gathering facility,
which initially was determined to be 25
MMcf/d and contain 1.6% (16,000 ppmv)
H2S, for a total of approximately 15 long
tons/day of sulfur. The entire plant was
designed, built and commissioned in a
period of only 29 weeks.
Upon plant startup, the H2S level increased significantly, reaching values of
more than 40,000 ppmv, but it eventually
leveled at 20,000-25,000 ppmv. The unit
was able to treat this higher concentration
of H2S to 0 ppmv in the outlet stream.
An expansion (debottlenecking) of the
unit was undertaken to extend the capacity

of the existing units to 40,000 pounds/day
(17.8 long tons/day).
A third train has been constructed at
the site since to increase total treating
capacity to 40 MMcf/d and 71,360 pounds
(31.8 long tons) a day of sulfur. This expansion allowed a 150% increase of the
gathering field in a very short time, unlocking an additional 3,000 barrels of oil
a month based on treatment capacity of
the associated gas, and saved $2
million/month compared with triazine
scavenger treatment. This single train is
designed for twice the capacity of the
initial trains, which significantly reduced
overall CAPEX. In addition, the advanced
modular design allowed the modules to
be set in five days after completing the
groundwork. The overall time from field
installation to startup was eight weeks.
Several companies have deployed multiple units with a capacity of 7 MMcf/d
with a maximum 5,000 ppmv of H2S to
different sites in South and West Texas
based on a standard five-module design.
These skid-mounted modules were installed within five days of delivery to the
site. Each unit was a replacement for triazine or fixed-iron bed scavengers. All
units experienced higher operating efficiencies than expected.
The process can include a modified
amine unit that operates at an acid gas
pressure of 30 psig, the pressure needed
for the contactor, to remove higher concentrations of both H2S and CO2. The
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American Oil and Gas Reporter - May 2020

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