Features

New, High Tg Internal Pipe Coating System

By Dustin Traylor, MSE, Axalta Coating Systems, Hoston, TX | December 9, 2016

Development and evaluation using Electrochemical Impedance Spectroscopy (EIS)

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 combination of this “sour” crude (containing greater than 0.5% sulfur impurities) and the higher temperatures that come from drilling deeper within the earth, has accelerated the rate of corrosion observed by engineers and designers.  This corrosion 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 dramatically to facilitate transportation of heavier oils that do not easily flow at conventional crude oil pipeline temperatures.  A major flood of new oil from producers of sour crude oil in North America: Alberta (Canada), United States’ portion 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 design problems for metallurgists and corrosion engineers.  As a result, the demand for internal pipe coating systems that are resistant to the increasingly higher temperatures required for transporting 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 coatings with higher glass transition (Tg) temperatures.  By providing good corrosion protection and mechanical properties, these new internal pipe coatings are designed to provide downhole and pipeline integrity in higher service temperature 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 metals and coating performance increase dramatically with increasing depth:
1. Temperature
2. Formation fluid pressure
3. Gas contaminants (H2S, CO2)
4. Microbiological contaminants.

To understand how an internal pipe coating system degrades over time at high operating temperatures, several factors must be considered, such as the environment to which it will be exposed during its lifetime. However, the most critical property for the success of Fusion Bonded Epoxy (FBE) coating systems is its glass transition temperature, Tg. The Tg is the temperature at which a change of the polymer (coating) from a hard and relatively brittle solid state to a viscous or rubbery condition occurs. At or above this temperature, the permeation rate of oxygen, moisture, and other ionic substances increases considerably, which may lead to rupture of the polymer structure and ultimately failure of the coating system.

Temperatures above 110 °C (230 °F) start to represent a conflict in selection of protective coating systems for corrosion control because many of the most popular internal pipe FBE coating systems available today have a Tg of around 109 °C (228 °F).  Table 1 shows a comparison of an FBE coating currently available on the market and advertised as able to withstand 205 °C (400 °F), to our newly developed product.

Development of a New Internal Pipe Coating System

When Axalta staff began research and development work on a new FBE internal pipe coating system for the oil and gas market, researchers examined many specifications from end-users in order to find the most difficult required autoclave qualification testing to pass.  The JO Wafra “Test Condition 4” was agreed upon as the most difficult testing environment. The autoclave test conditions are:

• Temperature: 400±2 °F (205±1 °C)
• Duration: 96 Hours
• Pressure: 755±10 psi
• Gas Phase: 20% (20% H2S, 15% CO2, and 65% CH4)
• Hydrocarbon Phase: 40% (Toluene/Kerosene @ 1:1 by Volume)
• Water Phase: 40% (25% NaCl Solution).

After exposure, the barrier properties of the coating were evaluated using Electrochemical Impedance Spectroscopy and compared with a sample of the coating not exposed to the autoclave environment. The results of the evaluation were also compared to the results of post-autoclave exposure testing on a commercially available product as a control.

Results Summary

Figure 1 (coating “C”) and Figure 2 (experimental Axalta coating) contain photographs of both coatings before and after autoclave exposure.  The newly developed Axalta coating exhibited excellent adhesion, no blistering, and no swelling.  “Coating C” was completely disbonded from the steel test substrate and no further evaluation was possible.

Understanding EIS Testing

Organic coatings provide corrosion protection by isolating the corrosive environment from the steel structure to which they are applied. In general, a coating needs to have good barrier properties to provide good protection.  Low permeability to water, ions, gases, and other corrosives is essential to the success of a coating system at higher temperatures.

Field experience and laboratory research have shown that highly protective coatings with good barrier properties have a high electrical resistance. EIS is now a well-established laboratory technique for evaluating the corrosion protection of organic coatings because EIS allows for simultaneous measurement of the degradation of a coating caused by exposure to an electrolyte and the change in the corrosion rate of the substrate caused by coating perforation.

During the test, an AC voltage of varying frequency is applied to the sample, which allows collection of information about the electrochemical reactions. The capacitance of the coating will change during the experiment as a result of water swelling or absorption. Typically, a three-electrode arrangement with a working electrode, a reference electrode, and a counter-electrode is used to perform EIS in aqueous solutions.

As demonstrated in Figure 3, the corrosion protection from a coating, expressed in terms of Log Z, increases as its impedance increases. Therefore, a newly applied, high-performance coating will have a high impedance in the range of Log Z= 9 to 11.

Post-Autoclave Exposure EIS Results

Figure 4 is a graph representing the results of the post-autoclave exposure EIS testing of the experimental Axalta FBE. The Axalta FBE coating system exhibited excellent barrier properties in EIS evaluation.  The pre-autoclave exposure Log Z of the Axalta FBE was measured as 11.09.  After exposure, the Log Z observed within the water phase was 10.66, within the hydrocarbon phase was 10.92, and within the gas phase was 10.84.  This very slight change in Log Z indicates the new Axalta internal pipe coating did not lose barrier properties, even after exposure to high temperatures and high levels of oilfield gas contaminants.

Conclusion

As demonstrated by the post-autoclave exposure results, FBE coatings with lower glass transition temperatures do not offer protection for valuable steel assets in high temperature, highly corrosive environments.  At temperatures well above the Tg of the coating, water, gas, and other ion permeation is inevitable. However, the newly developed Axalta internal pipe coating system (with a Tg of greater than 180 °C) protects even in the most extreme environments.

The corrosion problems associated with higher temperatures and higher concentrations of gas contaminants does not necessarily constrain engineers and designers to the use of expensive alloys for piping.  A coating solution for the challenges of the new oil and gas marketspace now exists. 

References

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3. RAE Coatings Laboratory. RAE Coatings Laboratory Available at: http://www.raecoatingslab.ca/electrochemical-impedance-spectroscopy-eis. (Accessed: 4th November 2016).
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5. Sour crude oil. Wikipedia Available at: https://en.wikipedia.org/wiki/sour_crude_oil. (Accessed: 1st November 2016).
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