American Oil and Gas Reporter - October 2018 - 87

SpecialReport: Oil Field Chemistry
"Another area we are looking at is
laboratory analysis methods," Burress
says. "We are experimenting with several
techniques for evaluating chemicals that
we hope will strengthen the correlation
between performance in the lab and results
in the field."
The industry is particularly interested
in coming up with better ways to evaluate
asphaltene inhibitors, Burress details. She
points to the University of Michigan, the
University of Utah and Rice University,
which are involved in consortia working
to understand and analyze asphaltene detection and treatment.
"Operators and service companies are
looking for ways to apply chemistry
earlier in a well's life cycle," she adds.
"For example, we frequently include scale
inhibitors in hydraulic fracturing fluids
to keep scale from becoming an issue as
long as possible."
Multi-Chem's fluid systems often employ a novel approach to controlling the
generation of hydrogen sulfide, Burress
comments. "Instead of treating the reservoir conventionally, we deploy nitratereducing bacteria (NRB), in combination
with a nitrate source, to promote conditions
fostering nitrate reduction rather than
H2S production," she outlines.
This technique can be more cost-effective than conventional treatments, according to Jake White, Multi-Chem's
senior product manager for production
chemicals. He explains that even the most
effective treatments will leave conditions
prone to hydrogen sulfide generation, necessitating periodic treatments. "In contrast, the NRB replicate down hole to
sustain the right conditions for controlling
and preventing H2S," he reports.
"Instead of introducing a new chemical
to the system, we merely are creating an
environment where the 'beneficial' bacteria
can thrive," White adds.
Offshore Shifts
In their efforts to reduce costs, offshore
operators are adopting a new philosophy
on facility design that is increasing chemicals' importance, White contends. "To
lower overall cost, operators are more
willing to mitigate risks as opposed to
designing out all risk altogether," he says.
"For example, to minimize the number
of platforms they have to build, operators
are using longer subsea tiebacks, accepting
the risks associated with treating for hydrate formation in exchange for lower
upfront costs."

Low-dosage hydrate inhibitors that are
applied continuously can reduce the risk
enough for that approach to be viable,
White assures. "We have had enough success with the inhibitors that operators will
be comfortable continuing to use longer
subsea tiebacks going forward," he says.
Another way operators are reducing
costs is standardizing subsea tiebacks.
"They used to design each tieback for
the application, specifying the pipe size
and umbilical tube count that would be
ideal for each well," White recalls. "Today,
we see a trend toward standard designs,
which means they may have only two
umbilical lines for a well that needs three
or four chemicals, or alternatively may
not have any backup lines available."
That situation has required chemical
companies to develop combination products with compatible chemical elements
that collectively address multiple issues,
White notes.
In the long run, White says the industry's approach to chemistry will become
more multidisciplinary. "We are deepening
our understanding of how chemistry interacts with a well's other components to
maximize the operator's return on investment," he says.
White illustrates using an electric submersible pump. "Scale and paraffin can

damage the pump and cause it to fail
prematurely," he notes. "By looking at
how the chemistry we put in place during
the completion can address those issues,
we can extend the ESP's life and reduce
costs for the operator."
Flow Assurance
As subsea tiebacks get longer, the opportunities for paraffin formation increase,
says Charlie Talley, vice president of technology at Ideal Energy Solutions LLC.
"When produced water mixes with oil in
turbulent flow, the oil tends to become
sticky and agglomerate on the pipe's wall
as paraffin," he observes.
"The old way of thinking held that
only a carbon chain of 20 or higher had
a pour point high enough to fall out of
solution in a subsea environment, but
we are seeing paraffin form from smaller
chains with only 16 or 17 carbon atoms,"
he says. "In fact, these chains start the
problem. They are smaller and stickier,
so they build up on pipeline imperfections, creating a surface that larger chains
agglomerate onto."
Over time, this process restricts and
eventually blocks flow, Talley notes. He
says Ideal frequently treats lines with
flow areas that have been reduced 40-60
percent.

This paraffin-plugged pipeline is one of many to be remediated using novel chemistries.
Ideal Energy Solutions reports that its proprietary paraffin treatment removed 284 barrels
of solids from the pipeline-enough to ﬁll 71 percent of its 397-barrel capacity-by breaking
the blockages into chunks small enough to be pumped out.

OCTOBER 2018 87

American Oil and Gas Reporter - October 2018

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