Many refineries rely on equipment well past original design life. These assets, some of which now have been in operation for double that time, face an ever-increasing risk of failure due to internal corrosion attack.
Corrosion in refineries often is caused by contaminants in produced hydrocarbons that, over time, lead to deterioration of pipe and vessel walls. Loss of equipment integrity can result in unplanned downtime and costly repairs or, in the worst case, a catastrophic event posing major risk to personnel, the environment and stakeholder value.
Exacerbating the problem, many refineries no longer process the specific type of oil, such as sweet crude, they originally were designed to handle. The changing nature of oil feedstock magnifies corrosion problems in aging refineries.
For instance, in the U.S., refiners are taking advantage of the availability of light tight oils (LTOs), which afford significantly higher margins. The production of LTOs relies on the use of fracking fluids, a cocktail of chemicals for stimulating oil flow from the field. In many instances, these chemicals can end up in the crude oil feedstock to the refinery. In addition, the transportation of LTOs by railcar requires the addition of H2S passivator chemicals that can introduce other corrosion-related problems. These amine-based compounds can deposit as salts in the top section of crude towers, top pump-around and draw trays — with the resulting possibility of more corrosion.
Another example is Canadian oil sands crude, which has a high total acid number (TAN). Many of the world’s existing refineries were designed to process crudes with a TAN of 0.3 mg KOH/g or less but lots of newer crudes have a TAN of 1 mg KOH/g or more.
High TAN crudes create naphthenic acid corrosion, a particularly aggressive and often localized form characterized by the “orange peel” effect (Figure 1). While this issue primarily affects crude and vacuum distillation units, the gas, oil and residue products fed to downstream conversion and hydroprocessing units also can exhibit TAN levels that cause problems in feed-section equipment fabricated from carbon steel.
Refiners have two principal mitigation strategies against corrosion: upgrading the metallurgy of many or all the susceptible areas, often to expensive high-nickel alloys or titanium; or using chemical corrosion inhibition treatment.
Both strategies should include online corrosion monitoring at critical locations to verify the state of the metallurgy upgrade or the inhibitor distribution and effectiveness. Alternatively, online corrosion monitoring can validate that the existing mitigation strategy is performing adequately.
Assets At Risk
Refinery processing hardware prone to corrosion include sour-water strippers, crude and amine units, terminal jetties and many other assets.
Sour-water stripper tower corrosion and fouling from corrosion byproducts like iron sulfide are common operational problems compromising asset integrity. Tower and crude overhead sections are exposed to high levels of hydrogen sulfide and ammonia, and can experience excessive rates of ammonium bisulfide corrosion. High levels of cyanides from upstream units that concentrate in the overheads can compound corrosion risks (see Safeguard Sour-Water Strippers section below).
Free cyanides can be deposited in the wet gas stream, causing hydrogen blistering. Cyanides can destabilize any passivation (iron sulfide) layer, causing it to flake off as free iron sulfide, resulting in plugging and fouling.
Amine systems are subject to corrosion by both carbon dioxide and hydrogen sulfide in the vapor phase, the amine solution and the regenerator reflux — as well as from production of amine degradation products in the amine solution. In refineries specifically, amine systems suffer from corrosion by several components such as ammonia, hydrogen cyanide and organic acids not generally found in natural and synthesis gases; some of these will accumulate at various points around the refinery amine system.
Refineries can turn to two methods to measure corrosion: probes and ultrasonic sensors.
Corrosion probes, which have been in use since the 1960s, rely on an intrusive element with a sacrificial tip that sits in the process fluid. As the sacrificial tip corrodes, its electrical resistivity changes. The corrosion of the sacrificial tip is used to infer the level of corrosion being experienced by the surrounding equipment.
While simple to use, corrosion probes suffer from two disadvantages:
1. The center-line measured corrosion at the tip may not match the corrosion rate at the pipe wall.