Corrosion in refinery operations has been, and still is, the subject of many studies, papers, courses and web forums. Although a lot of what has been written shows that significant progress in understanding corrosion has been made, it also makes it clear that the problem continues to exist and that quite possibly is getting worse.
It is estimated that the global costs of refinery corrosion are in the order of 15 billion USD annually. Getting more exact numbers is not possible as refineries do not make available the extent of their corrosion problems, which is understandable considering the ever increasing environmental legislation they face. It is worth mentioning that in these costs, profit losses and loss of production uptime have not been taken into account. An analysis report by NACE International states that in the USA alone annual profit losses due to refinery corrosion may be as high as 12 billion USD!
Despite extensive research and vast amounts of available literature, many of the corrosion mechanisms are not yet fully understood. The problem with petroleum refining is that there is not one single source of corrosion, but many. To add to the problem, some of the corrodents might interact and increase or inhibit each other’s corrosivity. Also, physical process conditions play a role; so temperature, flow and Reynolds number have to be taken into account too. Of no less importance is the refinery infrastructure itself. Pipes, vessels, weldings, instruments, etc. are obviously also part of the equation. Given the number of variables then, it becomes clear that corrosion is a complex problem.
One reason why the situation is not expected to improve soon is the increased processing of low quality sour crudes. Sour crude is crude oil with a high sulfur content (as opposed to low sulfur containing “sweet” crude). Because it provides a lower feedstock cost, sour crude is preferred by refineries for economic reasons. Further, sweet crude is becoming less readily available as the bulk of its supply is exhausted. In sour crude, sulfur is present in the form of mercaptans, H2S, sulfide salts, elemental sulfur and so on. Many of these species are reactive and cause sulfide stress cracking and sulfuric acid corrosion throughout the refining process.
Besides sulfur, crude contains many species that are quantified by the total acid number (TAN) of the oil. This number is not specific to a particular acid but refers to all possible acidic components in the crude, and is defined by the amount of potassium hydroxide required to neutralize the acids in one gram of oil. Typically found are naphthenic acids, which are organic, but also mineral acids, H2S, HCN, CO2, etc. can be present, all of which can contribute significantly to corrosion of equipment. Even materials suitable for sour service do not escape damage under such an onslaught of aggressive compounds. Again, because of cost considerations, a trend towards a preference for crudes with a higher TAN is noticeable.
Desalting of the crude is the first step in refining that has a direct effect on corrosion and fouling. By mixing and washing the crude with water, salts and solids transfer to the water phase which settles out in a tank. An electrostatic field is induced to speed up the separation of oil and water. In this way, inorganic salts that could cause fouling or hydrolyze and form corrosive acids are largely removed. Often, chemicals are added in the form of demulsifiers to break the oil/water emulsion. Also, chemicals such as caustic soda are introduced to neutralize acidic components. Uncontrolled feeding of caustic can, however, have a detrimentaleffect. An excess of caustic can result in the formation of soap due to, for instance, the presence of fatty acids. Soap stabilizes the oil water mixture and obstructs the separation process. Also, too strong a mixing of crude and water can create an emulsion that is very difficult to break. Frequently the crude arrives at the refinery as an emulsion due to the presence of water that had been used to maximize the oil extraction from the oil reservoir, or water might have occurred naturally in the reservoir. It can happen that emulsions are too strong and prove impossible to break. When this is the case a lot of the contaminants end up in downstream processes, which may have serious consequences.
One process parameter that can play a vital role in both neutralizing acids and demulsification, is process pH. Carefully monitoring pH in the desalter water effluent allows for efficient dosing of caustic or acid which may result in significant cost savings. The stability of the oil / water emulsion depends partly on pH. Maintaining the pH of the mixture within a certain range helps the demulsifier chemicals in breaking the emulsion by interacting directly with the water droplets. The speed and quality of the separation process can thus be improved which leads to less water carry-over, which in turn can result in a significant reduction in downstream corrosion and fouling.
Despite a good desalting operation, an abundance of corrodents can still appear during downstream processing. A good example of this is the sour water corrosion that occurs in the crude distiller. During the process lots of acid gases are formed of which hydrogen sulfide is notorious. Steam, which is injected into the crude tower to improve the fractionation, condenses in the upper part of the unit. The hydrogen sulfide dissolves in the condensate and forms a weak acid which is known to cause stress corrosion cracking in the top section of the tower and in the overhead condenser. This may lead to frequent retubing of the condenser and in severe cases to replacement of the entire crude tower top.
Although this particular cause of corrosion is well known to refinery operators, counter measures are not always in place. Typically, corrosion inhibitors and lots of neutralizers such as caustic soda or ammonia are injected with the aim of increasing the pH of the sour water. Although this is an obvious response to the problem, the cure can be worse than the disease. The presence of various acid gases and ammonia can result in solid salt depositing from which ammonium bisulfide is one of the main causes of alkaline sour water corrosion. pH levels higher than 7.6 dramatically increase ammonium bisulfide corrosion. By overdosing caustic that level is easily achieved. Hence, as in desalting, the key to corrosion reduction is in accurate pH control. Proper neutralizer dosing through crude distiller overhead condenser boot water pH measurement will not only reduce corrosion but also reduce chemical consumption. Reductions in the use of corrosion inhibitors of more than 15 % have been reported.