Real-time crude and desalter monitoring
An analyser array supports corrosion management through continuous insights into changes in crude quality
ALBERT MOURIS and ETIENNE HUNT, Hobré Instruments
KEVIN CLARKE, CREAS Energy Consulting
Viewed : 259
To maximise profits and remain competitive, refineries regularly reoptimise their crude slate with changing market conditions. As a result, crudes change frequently, and the plant is driven towards processing cheaper, heavier, and lower quality crudes. Many of these lower quality crude oils contain higher levels of salts (chlorides), organic chlorides, sulphur, nitrogen, metals, tramp amines, as well as high solids and acidity. All of these factors can drive up corrosion within the crude processing complex without proper conditioning which, in turn, can be hampered by the difficulty in determining the precise crude mix hour-by-hour (inadequate tankage for proper segregation, layering, tank heels of unknown composition, slops reprocessing, tight crude oil inventory controls to minimise working capital, and the frequency of crude tank changes). Many refiners report crude changes as often as every two to three days.
A critical element of corrosion control within the crude complex is the desalter (see Figure 1). The desalter serves several purposes:
• Reduces the salt (inorganic chloride) content of the crude oil
• Solid separation
• Recovery of phenols from wastewater
Salt occurs naturally in crude oil, so a certain amount of brine is produced with crude which is separated in the field and relatively dry crude oil is sent to the refinery. Chlorides introduced into an oil well during a workover or well stimulation will also appear in the produced crude. Salt can also enter crude oil from seawater during transportation. The salts in crude oil consist primarily of sodium, magnesium, and calcium chlorides.
While some of these lower quality crudes can be priced at a $2-$3/bbl discount to Brent, most refiners would not be able to process these at more than 25% of their total crude slate – implying a commercial incentive of approximately $0.50-$0.75/bbl or $37-55 million/y for a typical 200000 b/d refinery. Recent studies have suggested that the annual cost of corrosion in refining is approximately $15 billion or $0.45-0.50/bbl of total global crude oil processed. Processing of these lower quality crude oils is concentrated within a subset of the global refining population, so there is clearly considerable commercial risk to processing these crudes without adequate monitoring of contaminants, operations, and corrosion rates to mitigate the potential for integrity problems.
Magnesium and calcium chlorides have a higher tendency to remain in the oil phase than sodium chloride, so sodium chloride removal by effective desalting is usually nearly complete. In most cases, magnesium and calcium chloride levels in crude are low.
As crude is processed through the crude tower and then the vacuum unit and downstream residue upgrading units such as delayed cokers, residual magnesium or calcium chlorides will hydrolyse in the presence of trace water, releasing hydrogen chloride. The hydrolysis to temperature relationship is illustrated in Figure 2.
Sodium chloride will not decompose to any significant extent, but passes into the atmospheric residue where it can accelerate coking in the vacuum unit and downstream residue conversion units (visbreaker, delayed coker, and so on), shortening the run length between heater decokes. In addition, sodium in the FCC feed serves to exaggerate the conversion impact of any vanadium in the FCC feed, with implications for fresh catalyst use and yield performance (see Figure 3).
Hydrogen chloride generated from the magnesium and calcium salts will move upwards in the distillation columns until it finds ammonia or amines to combine with, or until a liquid water phase forms, or until the hydrogen chloride is drawn into a product. The corrosive impact of the chlorides will then be observed in the crude tower and the overhead heat exchangers. Therefore good control of the desalter can substantially reduce corrosion within the crude tower overheads, as well as fouling in the preheat exchanger train and oil content of the desalter effluent water. However, many refineries have increased processing capacity over time and are running a progressively heavier crude slate, without making the corresponding modifications to their desalters, with the result that desalting and dehydration efficiencies have declined, thereby driving up the risk of downstream reliability issues.
In addition, normal build-up of sediments in the bottom of the desalter during the run (see Figure 4 for typical desalter internals) can also serve to reduce residence time, so desalting efficiency can reduce across the cycle. Within these tight net margin environments, it is surprising that the operation of many crude oil desalters is not rigorously adjusted following changes in the crude slate, and there has been limited investment in tracking desalter operating performance in real-time to provide advance warning of sub-optimal performance and potential downstream issues.
Clear understanding of the chloride content of the desalter effluent crude oil is therefore critical to mitigating corrosion. Chlorides (NaCl, MgCl2 and CaCl2) in excess of 20 ppm are known to cause serious corrosion issues due to the liberation of chloride ions which travel to the top of the crude tower (see Figure 5) and condense with the first drop of water at the water dewpoint, with a very low pH (1-3). This highly localised point of corrosion can move around within the overhead system, depending on the water content, top temperature, functioning of the condensers, and vapour flow rate. Refiners inject ammonia or amines into the overhead system to neutralise the acid, as well as filming amines which cover the internal surfaces of the exchanger tubes to prevent the acid from reaching the metal surface. Frequent crude changes and variations in desalter performance can result in under-dosing of neutralising amine. Filming amines can also be stripped by high vapour velocities or may fail to coat all surfaces evenly. As a result, dewpoint corrosion remains an ongoing issue within many crude towers.
This difficult situation is further exacerbated by two other factors:
• The declining demand for gasoline, particularly in European and Asian economies where refiners typically aim to maximise middle distillate (jet fuel and diesel) production. This drives down the optimum temperature for the crude tower overhead, further raising the risk of dew point corrosion, as well as the exposure of larger areas of the crude overhead system to the potential of dewpoint corrosion, such as the tower dome itself.
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