Avoid Corrosion-Induced Asset Integrity Loss

by | Sep 11, 2018 | Downstream Hydrocarbons, Industrial IoT, Industry

Jim Cahill

Chief Blogger, Editor

Emerson's Christiane Lederer


A U.S. Energy Information Administration’s post, When was the last refinery built in the United States?, reveals that more than half the “newest refineries” in their list were built in the 1970s or 1980s, or 30 to 40+ years ago. And, with 137 operating U.S. oil refineries, the rest are even older. A lot has changed over this time, but much of the piping and vessel infrastructure remains the same.

Chemical Engineering: Using Corrosion Data to Stave Off ExtinctionIn a Chemical Engineering article, Using Corrosion Data to Stave Off Extinction, Emerson’s Christiane Lederer discusses how changes in crude oil feedstocks, aging assets and regulatory changes are increasing the difficulty in containing corrosion with the plant piping, vessels and asset.

Christiane cites a NACE International study which:

…put the total annual cost of corrosion in the oil-and-gas industry at $1.372 billion.

Integrity loss from corrosion can lead to:

…unplanned downtime and costly repairs, or in the worst case, an incident posing major risk to personnel, the environment and stakeholder value.

The choices for refineries with aging assets are:

…do they decommission the asset at a substantial cost and search for ways to replace its production, continue to produce at a potential profit with the associated risk, or find a way to continue operation in a cost-effective and safe manner?

Christiane shares some of the causes of increased corrosion in refineries including fracking fluids in feedstocks, higher total asset number (TAN) crudes, and compounds contained in the fluid streams such as hydrogen sulfide, ammonia, cyanides, and other organic acids.

Jetties along waterways provide cost effective transportation for crude oil feedstocks in and refined products out. In many instances when the refineries were built:

…it wasn’t cost effective to construct these jetty pipelines from stainless or alloy steel; instead, carbon steel was used to build the pipelines decades ago.

This carbon steel is more susceptible to corrosion, especially:

…in jetty lines, since they have intermittent or slow flowrates, allowing water to settle in low points.

Christiane describes the traditional approach to monitor corrosion through manual inspection on 3- to 6-month intervals. This opens broad time windows where integrity loss can occur. Applying digital technologies offers a better approach.

Permanently installed, ultrasonic, wireless wall-thickness-monitoring sensors…are ideal for corrosion monitoring because they provide the data required to make proper decisions on a continuous basis.

Permasense Permasense wireless wall-thickness corrosion monitoring sensorsThese non-intrusive Permasense wireless wall-thickness monitoring sensors provide:

…corrosion information…to make the right decisions at the right time about when and where critical maintenance should be carried out to support safer and more economic operations.

These sensors work by measuring:

…the thickness of the pipe wall and send data directly to server-based analysis software via a wireless network. With the enhanced insight provided by this realtime data, refinery operators can quickly realize improved safety, reduce operational expenditure and increase production from their aging assets.

Read the article for more on the conditions causing corrosion in older refineries and how modern wireless sensing technology can help mitigate loss of asset integrity risks.

Join us at the Oct 1-5 Emerson Exchange conference and see the short course, How Integrated Corrosion Monitoring Can Lead to Top Quartile Refinery Performance or visit the Permasense section of Emerson.com.

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The opinions expressed here are the personal opinions of the authors. Content published here is not read or approved by Emerson before it is posted and does not necessarily represent the views and opinions of Emerson.