American Oil and Gas Reporter - July 2020 - 44

SpecialReport: Proactive Chemistry
allowed oil and water to separate, tubulars
and rods in contact with the oil will see
little risk. Depending on a particular
well's oil/water cut and reservoir pressure,
the greatest corrosion risk will be in the
lower part of the production string, where
reservoir temperature and wellbore pressure are at or near maximum. Such pressure drives more acid gas into solution in
the brine. Corrosion rates increase with
temperature, making the lateral and lower
part of the well the highest risk segments
for corrosion potential.
While weak acid concentration, temperature and pressure will determine the
actual rate of any corrosion, the overall
potential for downh---ole damage to rods
and tubulars depends on the length of
the shut-in.
As the well returns to production, steps
should be taken to re-establish a corrosion
film on the downhole equipment. If the

well had been treated with periodic batch
treatments with a corrosion inhibitor prior
to shutting in, batch treatment should resume as quickly as possible, with the first
treatment containing an abnormally large
volume of corrosion inhibitor. If the well
was shut in two-four weeks, the operator
should consider two or three times the
normal corrosion inhibitor application. If
shut in longer than three weeks, the first
treatment should be sized with four-five
times the normal inhibitor volume. A preflush with a suitable surfactant should be
placed in front of the inhibitor pill to
wash off any possible corrosion byproducts
on the tubing or rods.
If the well was treated continuously
with a corrosion inhibitor down the tubing/casing annulus without the aid of a
capillary injection line, there likely will
be some fluid that may impair the corrosion inhibitor's reach. To shorten the

time needed to get inhibitor down hole
and back to surface through the tubing,
a mixture of 10 gallons of corrosion inhibitor and 20 barrels of clean lease
brine can be pumped down the tubing/casing annulus.
Bacterial Corrosion
Bacteria have been found in oil and
gas operations and studied for decades.
Many different species such as acid-producing, iron-oxidizing, iron-reducing and
sulfate-reducing bacteria have been known
to contribute to metal corrosion in oil
and gas wells. Some contribute to corrosion
by secreting weak acids, and some, such
as sulfate reducers, utilize the sulfate ion
for respiration, eventually releasing what
remains as H2S into the produced brine.
Some bacteria have been found to be
naturally occurring in a reservoir, while
others have been introduced through

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transportation and disposal of excess
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Fault analysis from CGG's Avalon 3D multi-client survey, Delaware Basin,
reveals inter-formational faults, a recognized risk for increased water cuts.

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http://www.cgg.com/respack

American Oil and Gas Reporter - July 2020

Table of Contents for the Digital Edition of American Oil and Gas Reporter - July 2020

American Oil and Gas Reporter - July 2020 - Intro
American Oil and Gas Reporter - July 2020 - 1
American Oil and Gas Reporter - July 2020 - 2
American Oil and Gas Reporter - July 2020 - 3
American Oil and Gas Reporter - July 2020 - 4
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