Gas Production Corrosion Mitigation

Emerson's Chris Burke


As an oil & gas reservoir ages, the composition of the production often changes. For gas wells, this change is often from dry gas to a wetter gas. The wet components can be quite acidic due to CO2 and organic acids contained in this liquid phase.

In an Oilfield Technology article, Mitigating corrosion in ageing gas fields, Emerson’s Chris Burke describes how technology has become available to better address the corrosion and erosion problems associated with wet gas.

Oilfield Technology: Mitigating corrosion in ageing gas fieldsChris describes how gas well changing production characteristics can create these corrosion and erosion challenges:

During early production, the throughput is generally dry, and the metallurgy of the equipment would have been selected accordingly. However, as the reservoir depletes, it tends to produce more corrosive liquid and solid substances. If wet sand is being pulled through a pipe originally designed and installed to handle dry gas, this can have a significant impact on the erosion of the pipe wall.

If not monitored, this can lead to asset damage, or worse, loss of hydrocarbon containment.

He cites a Dutch offshore North Sea gas producer who reconfigured some platforms to remove wet gas processing from satellite platforms and concentrate this processing on a central gathering platform to optimize operational costs. This reconfiguration posed a challenge and to address it:

…various equipment and valves were replaced with corrosion-resistant alloys. However, it proved too complex and expensive to replace the existing carbon steel piping infrastructure, and this would have almost certainly rendered the project uneconomical.

Injecting the proper levels of corrosion inhibitors can help keep corrosion in check. This injection:

…needed to take place only when the process fluid reached certain levels of wetness. If too much inhibitor was added too early, this could actually increase the risk of corrosion instead of mitigating it.

Measuring corrosion has traditionally been performed with intrusive probes that:

…infer corrosion levels. What the probes are actually measuring is the loss of metal from the sacrificial element of the probe itself.

Using these inferred measurements may not be enough or may require manual checks:

It is perfectly possible that the chemicals are within recommended levels, but excess internal corrosion is still occurring.

To improve injection control with direct corrosion measurement:

…Emerson’s Permasense™ wireless ultrasonic thickness measurement sensors were installed to monitor metal pipe wall loss at critical locations…

30 wireless corrosion sensors were installed:

…in high risk areas of the pipework, and sensors were installed to give the well operator continuous, accurate insight into the actual levels of corrosion occurring.

For this Dutch gas producer, the:

…sensors detected elevated corrosion rates in some of the flow-back lines, downstream of the first and second compression stage. Flow-back lines are particularly vulnerable to internal corrosion due to the variable and often low flow rates, which can allow water to gather and increase local corrosion activity.

Read the article for more on how the operations staff used this continuous monitoring information to improve the performance of their corrosion inhibiting strategies and successfully manage their oil & gas field reliability and optimization efforts.

Visit the Permasense section of Emerson.com to learn more about this non-intrusive integrity monitoring systems for oil and gas production facilities and refineries.

At the October 1-5 Emerson Exchange conference, you can also connect and interact with experts on corrosion management best practices including workshops such as: