Dustin Traylor, MSE, Axalta Coating Systems, Hoston, TX
Abstract
Within the environments currently
being explored today by oil and gas
operators, higher temperatures and
concentrations of H2S, CO2, and other
gas contaminates may warrant the use
of significantly more expensive metal
chrome alloys to avoid corrosion and
failure. Coatings are a lower cost alternative that have been used within
the industry for years; however, most
anti-corrosion coatings cannot perform
in environments with high temperatures, pressures, and high levels of gas
contaminates. This paper explores the
development and testing of a new internal pipe coating system that is resistant
to high concentrations of H2S and CO2,
even when subjected to high temperatures and pressures.
Drilling Deeper
A continuous increase in worldwide oil
and natural gas demand has led to the
search for deeper reservoirs, resulting
in the extraction of heavier grade crude
oils (transitional and unconventional),
characterized by their more viscous form
and higher sulfur content. The combi-
nation of this “sour” crude (containing
greater than 0.5% sulfur impurities) and
the higher temperatures that come from
drilling deeper within the earth, has ac-
celerated the rate of corrosion observed
by engineers and designers. This corro-
sion rate acceleration has warranted the
use of significantly more costly metal
chrome alloys to avoid corrosion failure
of piping assets.
The problems associated with drilling
in deeper reservoirs do not only affect
downhole operations. Pipeline operating
temperatures have increased dramatical-
ly to facilitate transportation of heavier
oils that do not easily flow at conven-
tional crude oil pipeline temperatures.
A major flood of new oil from produc-
ers of sour crude oil in North America:
Alberta (Canada), United States’ por-
tion of the Gulf of Mexico, Alaska and
Mexico; South America: Venezuela,
Colombia, and Ecuador; and the Middle
East: Saudi Arabia, Iraq, Kuwait, Iran,
Syria, and Egypt, has created more de-
sign problems for metallurgists and
corrosion engineers. As a result, the de-
mand for internal pipe coating systems
that are resistant to the increasingly
higher temperatures required for trans-
porting hydrocarbons is on the rise.
This has prompted the Research and
Development team at Axalta Coating
Systems to prioritize the development of
a new generation of internal pipe coat-
ings with higher glass transition (Tg)
temperatures. By providing good cor-
rosion protection and mechanical prop-
erties, these new internal pipe coatings
are designed to provide downhole and
pipeline integrity in higher service tem-
perature environments.
More Depth, More
Problems
Why does depth mean more problems
with corrosion and higher chances of
pipe failure? In the subsurface of the
earth, four factors that affect corrosion of
Development and evaluation using Electrochemical Impedance Spectroscopy (EIS)
New, High Tg Internal
Pipe Coating System
Coating Tg Max Operating Temperature* Intended Applications
“C” 115 °C (228 °F) > 205 °C (400 °F)
• High temperature drill pipe
• High temperature downhole environments
• Oil, gas, and water wells
• Rod pump wells
• Gas Lift
Target for
newly developed
Axalta product
180 °C (356 °F) > 205 °C (400 °F)
• High temperature drill pipe
• High temperature downhole environments
• Oil, gas, and water wells
• Gas Lift
• Gathering Systems
Table 1. Comparison of FBE coating available in the marketplace (C) to newly developed product.
*Coatings commercially available
