Mitigating corrosion from naphthenic acid streams
The authors describe how crude and side-cut analysis, laboratory and field data lead to strategies for managing high severity operating conditions needed for pocessing opportunity crudes
David Johnson and Gregg R McAteer, Ondeo Nalco Energy Services
Heinz Zuk, Norsk Hydro AS
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The growing variety of discounted opportunity crudes on the market usually contain one or more risks for the purchaser, such as high naphthenic acid content. As the availability and volume of highly naphthenic crudes processed increase, the risk of experiencing high temperature corrosion on refinery equipment must be considered. Detailed studies carried out during laboratory and field evaluations, utilising online monitoring systems, identified associated problems while processing naphthenic acid crudes.
The concerns with naphthenic crude’s corrosivity at high operating temperatures also indicated the need for additional desalting and fouling studies. These multi-layered studies yielded a thorough understanding of the metallurgical effects from various crude oils relatively high in naphthenic acid content. Corrosion rates were evaluated through the use of corrosion probes and coupons. Finally, the use of high temperature corrosion inhibitors was successfully evaluated as a means to mitigate naphthenic acid corrosion.
Many opportunity crudes are known to contain naphthenic acids, which can cause corrosion in high temperature regions within the refinery, normally around the crude and vacuum towers. These opportunity crudes, also known as high acid crudes (HAC) and high neutralisation number crudes (HNN), are often discounted due to the added risks associated with processing these crudes. Because of the economic advantages [J Skippens et al, Evaluation of the economics for the processing of naphthenic crudes; International Conference for Corrosion in Refinery Petrochemical and Power Generation Plants, Venice, Italy, 18–19 May 2000], many refiners are looking increasingly at processing high levels of naphthenic crude oils in their crude slates.
The properties of crude oils rich in naphthenic acid species vary. For example, Captain, Alba, Gryphon, Harding and Heidrun are all considered opportunity crudes from the North Sea region. The gravities range from 0.88 to 0.94 and TAN ranges from 2.0 to 4.1. Gryphon has a sulphur content of 0.4 wt% while Alba has a 1.3 wt% sulphur. These variations allow refiners to find high acid crude oils that are suitable for their product profile.
Over the next five years it is forecast that HAC supply (crudes having a TAN > 1.0) will continue to increase significantly, with production rising across the world. All of these crude oils have significant acid numbers. Therefore, corrosion management is of vital importance to ensure that corrosion risk to the plant is minimised, a proper inspection system is in place to identify the corrosion which might occur, and areas of the plant that might be subject to severe corrosion are identified so that the need for more corrosion resistant alloys can be predicted.
In addition to high temperature corrosion management, many of these HACs can be harder to desalt and lead to increased overhead corrosion, fouling and product stability issues. To be sure, this is another compelling reason to develop and outline the proper evaluation techniques and safe management of naphthenic acid crudes.
To safely run such crude oils in the refinery it is important to first assess the susceptibility of the plant and its equipment to undergo naphthenic corrosion. Typically, data is reviewed to establish potential corrosion rates, which could be used to estimate the remaining life on the refinery process, pressure pipelines, pumps and vessels.
Literature reviewed and experience indicates that pipelines and equipment containing crude, light diesel, heavy diesel, atmospheric residue, light and heavy vacuum gas oil (HVGO) and vacuum residue operating at temperatures higher than 200°C were possible areas for naphthenic acid attack. Areas are highlighted in the basic schematic provided in Figure 1.
Unfortunately, experience has shown that it is difficult to correlate corrosion rates for particular crudes from refinery to refinery. This is due to the differences in equipment design, operating temperatures, flow velocities and other crudes present, which may provide a natural passivating effect to the system.
There are several important variables to consider while performing a risk assessment on a unit: stream analysis, temperature, velocity, metallurgy, flow regimes etc. Every piece of the puzzle must be analysed before the best mitigation strategies can be developed, including:
— Stream analysis
— Two-phase flow
— Areas of turbulence
— Predictable zones of first vaporisation or condensation
— Reactive sulphur content of the various side cut oils
— “Other” overhead corrosion, desalting and fouling variables
— Side-cut stability.
In the stream analysis, the TAN and naphthenic acid content (from the naphthenic acid titration test, or NAT) for most crude oils varies with the temperature of distillation fraction. NAT represents only the naphthenic acids within the TAN. There are many different naphthenic acid species, and some are more corrosive than others. Testing the whole crude and the side cuts shows where the different naphthenic acids will distil and concentrate.
It is wise to conduct such testing on the anticipated blends that could be encountered to ensure the contributions of other crudes to TAN and NAT are captured. For example, North Sea Captain crude has a whole crude TAN of 2.5 and a NAT of 2.2, yet the lightest cut only has a TAN of 0.25 and a NAT of 0.3. As heavier cuts are tested, it is observed that the TAN and NAT levels increase to a high TAN of 3.8 and NAT of 2.6 in the 390–482°C cut.
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