Mitigating Corrosion in Ageing Gas Fields

 If not properly addressed, natural gas production can release excessive amounts of methane into the atmosphere from production sites and pipelines. Failing equipment can be a culprit, and leaks can be caused by older piping and vessels corroding quietly until joints and fittings begin to emit gas.

In the September issue of Oilfield Technology, Chris Burke addresses one side of the problem in his article, Mitigating Corrosion in Ageing Gas Fields. Based in Aberdeen, Chris Burke looks at North Sea production, but the concepts also apply anywhere natural gas is produced or transported.

As a field matures, additional wells are often drilled and brought on-stream to maintain production capacity. Some assets were originally designed to handle a certain type of input. Take a gas well for example. 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.

This kind of situation applies in every field where gas wells of a certain age are operating. Methods to compensate for falling production can take their toll on equipment, and modifications necessary to extract more from those wells don’t ensure solid containment.

Reconfiguration work, combined with the increasing volume of formation water typically produced from ageing wells, requires a robust corrosion management strategy. If left undetected and unchecked, corrosion can have a major negative impact on asset integrity, resulting in expensive repair work or even loss of hydrocarbon containment – with possibly catastrophic environmental, safety, financial and reputational implications. Corrosion monitoring and control is therefore essential to manage risks effectively.

The improvement effort has to begin with corrosion monitoring. Operators have to know the condition of the equipment in real-time to determine what is still safe and what may already be in the danger zone. Chris talks about one example of a company working with declining wells in the North Sea.

Over the last decade, the operator has implemented a strategy to extend the economic life of its producing assets by consolidating existing infrastructure and streamlining operations. As part of the consolidation process, the principal platform was reconfigured to handle wet gas from the adjacent wells. The carbon steel pipework transporting hydrocarbon gas between the principal platform and each of its sister facilities was originally designed to handle dry gas. The challenge with wet gas is that the water phase is acidic because it contains CO2 and organic acids. Therefore, corrosion was a particular concern from the outset.

There it is: equipment designed for one kind of gas has to be used for another. Determining what a program of equipment upgrades and corrosion inhibitor use would look like had to begin with an evaluation of the existing condition, and that meant measuring and monitoring pipe wall thickness using Emerson Permasense wireless ultrasonic thickness measurement sensors.

These sensors are affixed to the external surface of the pipework to determine the thickness of the pipe wall by continuously monitoring for metal loss at critical locations. The technology is non-intrusive and wireless, meaning it can be installed while assets are on-stream, and without expensive cable runs to retrieve the data. This solution also offers users the flexibility to deploy sensors in any required configuration, from close set in arrays at critical points, to widely dispersed in other areas.

Chris goes into more detail of how the company implemented its program, so be sure to read the entire article. Suffice it to say, this program, beginning with Permasense sensors, has provided critical information enabling the company to keep operating with a minimum of additional expenses.

By having a direct measurement of corrosion occurring at the wall of the metalwork – rather than just of the levels of inhibitor in the flow or the corrosivity of the fluid – operators can have confidence in the readings, meaning fewer manual inspections and unhampered production. Continuous system feedback means operators can adjust for and eliminate certain variables to swiftly address any underlying problems.

You can find more information like this and meet with other people looking at the same kinds of situations in the Emerson Exchange365 community. It’s a place where you can communicate and exchange information with experts and peers in all sorts of industries around the world. Look for the Upstream, WirelessHART and IIoT Groups and other specialty areas for suggestions and answers.