Managing Equipment Damage Caused by Corrosive Feedstocks Encountered with Biofuel Production (Part 2)

by | Apr 15, 2024 | Chemical, Downstream Hydrocarbons, Oil & Gas

When we talk about renewable fuels to the general public, many might imagine cars running on gasoline made from wildflowers and meadow grass. However, those who work in the industry recognize that the fats and oils used to make renewable diesel can be just about anything but that, and in fact often come from more prosaic sources, such as meatpacking waste.

From a process viewpoint, waste sources can cause serious problems because those fats and oils often contain corrosive contaminants, far worse than anything routinely encountered in conventional refining operations. Advice on how renewable diesel and sustainable aviation fuel (SAF) producers can deal with this issue is the topic of my comprehensive two-part article in Hydrocarbon Processing, Implement Innovative Corrosion Management Solutions for Biofuel Refining. Part 1 is in the September issue, Part 2 in October. Producers must understand that they will encounter these contaminants, and they will take a toll on equipment, but the effect can be managed.

In Part 1, we look at how corrosion is associated with the feedstock sources. Clean feedstocks from oil seeds are easy to work with but are taken from food supplies. Producers wanting to find the lowest cost alternatives and avoid contributing to global food insecurity will surely find themselves dealing with difficult animal fats and crop waste.

As with all waste products, there are challenges of consistent feedstock quality and reliable supply chains. Polyethylene packing impurities are typically found in animal fats, resulting in process challenges with catalyst deactivation, fouling concerns with heat exchangers, and flow constraints and catalyst bed pressure drops triggered by plugging. In general, these types of waste oils require heat-traced feed piping due to their lower cloud point.

Obviously, these are problems, but corrosiveness can be an even worse issue.

While organic sulfur components in renewables are decreased compared to petroleum feedstocks, the increased influx of organic chlorides and nitrates creates challenges with process equipment and piping integrity downstream of hydrotreating units. In addition to these and other corrosion-accelerating substances, the presence of water facilitates corrosion mechanisms by providing an electrolytic pathway. Water solubilizes organic and inorganic acids, creating carbon dioxide via hydrodecarboxylation, which turns organic chlorides into hydrochloric acid and promotes microbiologically influenced corrosion.

Part 2 of the article goes into more detail as to where these corrosion mechanisms tend to occur in the process and the specific types of corrosion, plus it includes a brief case study showing how one European renewable diesel producer implemented a program to mitigate the risk. Here are a few highlights from Part 2:

  • The reactor stage of all hydroprocessing units experiences various degrees of degradation based on hydrogen partial pressures and temperatures. Process variables influence cracking severity and the influx of corrosive specimen from feedstock streams.
  • At temperatures above 450°F (230°C) and at locations downstream of the injection point, the presence of hydrogen will lead to generalized corrosion mechanisms with process streams containing H2
  • CO2 dissolves in water to form carbonic acid, which also results in lowered pH levels—with both phenomena leading to generalized corrosion of carbon and low-alloy steels under 12% Cr.
  • Low-molecular-weight acids may form and cause significant aqueous corrosion when they dissolve in water. Highly susceptible are areas where the water dewpoint is reached, such as pumparounds and headers of distillation columns.
  • All hydroprocessing effluent piping and equipment are subject to ammonium chloride and amine hydrochloride corrosion, which often presents as pitting. It usually occurs under deposits of ammonium chloride, even without the presence of a free water phase.

These corrosion problems often stem from refineries repurposing old process equipment for this new purpose. The metallurgy used in that equipment was likely designed to handle conventional crude oil feedstocks with a much lower level of corrosiveness. The inevitable result will be that this equipment suffers metal loss. Operators must monitor the loss to avoid unexpected catastrophic failure of a pipe or vessel wall. The answer is continuous monitoring of metal thickness at strategic points using ultrasonic sensors, such as Emerson’s Rosemount Wireless Permasense WT210 sensors.

Permanently installed ultrasonic wireless wall thickness monitoring sensors address these and other issues, making them the best option for most high-temperature corrosion monitoring applications. These sensors can measure small changes in wall thickness and exhibit robustness to extreme plant conditions, while also having extended battery life to provide reliable operation over the entire cycle between turnarounds.

For more information, visit Emerson’s Corrosion & Erosion Monitoring pages at Emerson.com. You can also connect and interact with other engineers in the Oil & Gas Groups at the Emerson Exchange 365 community.

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