Monitoring and simulation resolves overhead corrosion
Online corrosion monitoring in tandem with simulation modelling identified the root cause of corrosion in a crude unit overhead
PHILIP THORNTHWAITE, Nalco Champion
JAKE DAVIES, Permasense
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Corrosion of crude unit overhead exchangers continues to be a significant concern towards integrity and reliability within the refining industry; failure mechanisms have been the subject of many technical papers over the years. For many crude units, good desalting and caustic injection practices are first lines of defence in managing overhead corrosion issues while injection of organic amine neutralisers and corrosion inhibitors is also applied in order to keep corrosion rates to a minimum. Additionally, many refiners look to control corrosion through non-chemical means by installing continuous wash water systems and metallurgy upgrades, replacing carbon steel sections with alloys that provide enhanced corrosion protection.
Regardless of the corrosion control strategy employed, one fundamental consideration is use of the correct diagnostic tools to allow monitoring of process conditions and corrosion rates in susceptible parts of the system. This monitoring provides a thorough understanding of corrosive species present in the system as well as operational factors that contribute to corrosion.1
Traditional corrosion monitoring and control revolves around periodic sampling and analysis of overhead sour water to determine the corrosive nature of the process and to give an indication of corrosion rates by the measurement of iron in sour water. This process stream analysis is often complimented by online corrosion monitoring in order to correlate changes in process conditions to subsequent changes in observed corrosion rates.
However, even with frequent analysis, corrosion monitoring and good management of the desalter operation and the overhead corrosion control programme, there remain many instances where high corrosion rates are observed that are difficult to explain and result in equipment failures, unplanned shutdowns and increased maintenance costs.
Herein lies the challenge since refiners are being increasingly tasked to find a balance between two competing objectives.
On the one hand, refineries are being asked to process more challenging crudes and while these present a price advantage they also increase the risk level. In conjunction with processing a more challenging crude diet, process conditions in the top sections of the atmospheric tower are being adapted to produce more valuable distillates and less naphtha in order to maximise margins. This can cause elevated levels of corrosion in parts of the system where none has been previously observed.
The other side of the challenge is that refiners are facing continuing pressure to reduce costs through increasing run length between turnarounds and reduction in head count and contractor use, often including inspection department and chemical vendor resources. Ultimately, this can compromise the ability of a refiner to maintain an appropriate level of surveillance of plant integrity.
Given these challenges, crude units previously able to operate with minimal issues are now facing challenges from increased crude unit overhead corrosion, which is resulting in serious economic penalties. Therefore, a more proactive approach to asset integrity management and crude unit overhead corrosion is required.
In order to successfully mitigate high overhead corrosion rates, the refiner and the chemical vendor are required to undertake a rigorous audit of the operation to identify all root causes that are contributing to the issue. A number of factors can contribute to this problem, therefore a total system approach needs to be taken and the mechanical, operational and chemical aspects of the unit’s operation need to be reviewed to obtain an in-depth view and understanding.
This thorough understanding of the underlying root causes aids in the selection and implementation of a correct corrosion control strategy. The primary tools for diagnosing root causes fit into two categories: analytical testing, which can be used to identify the responsible corrodents; and a modelling technology, such as Nalco Champion’s Pathfinder, that provides a means to understand the environmental factors that dictate the conditions under which corrosion occurs.1 These methods are used together not only to investigate the factors influencing corrosion but they are also utilised to define the operating envelope through which corrosion can be effectively controlled.
As well as utilising analytical testing and process modelling, online corrosion monitoring is used to complement these tools in order to link process conditions to actual corrosion events happening in the overhead system and to assess the success of corrosion mitigation methods. The move towards real-time online corrosion measurements with permanently installed UT thickness measurements, such as Permasense, has provided a significant improvement in the quality of the corrosion monitoring data, allowing cross correlation with process data, identifying corrosion events and helping facilitate root cause analysis.
This article will discuss techniques that can be used to monitor corrosion and determine the mechanisms in near real-time, including permanent UT thickness monitoring and computer simulation of the overhead condensing system and how these tools were used to effectively troubleshoot previously unexplained high rates of CDU overhead corrosion at a European refinery.
The continuing challenge: crude unit overhead corrosion and its control
Corrosion due to strong acids in crude tower overheads is a problem that all refiners face. The most prevalent cause of strong acid corrosion in crude unit overheads is due to hydrochloric acid condensation in the overhead system.
Hydrochloric acid is formed because the desalter operation is not wholly efficient, leaving residual amounts of hydrolysable salt, specifically calcium and magnesium chlorides, entrained in the crude oil. These salts are passed through the preheat exchangers and ultimately to the fired heater where they hydrolyse to form hydrochloric acid (HCl). The generated HCl and other acidic species like sulphur oxide (SOx) based acids and low molecular weight organic acids enter the atmospheric distillation column where they end up in the overhead condensing system.
The presence of these acids in the overhead system will result in a very low pH at the initial water dewpoint and, without adequate control measures, this results in very high corrosion rates.
Caustic is frequently added to the desalted crude in order to lower the effective salt hydrolysis rate by converting Ca and Mg chloride salts to non-hydrolysable sodium salts. This effectively reduces the amount of hydrochloric acid produced. However, the use of caustic can lead to increased furnace fouling as well as reduced catalyst activity if residue is fed to a FCC or hydroprocessing unit. While caustic use can be beneficial, it is desirable to keep the injection rate to a minimum.
A variety of techniques is employed to control corrosion in the overhead system,1 the most common being chemical corrosion control programmes which utilise neutralising amines to control pH (typically between 5.0 and 6.5) and filming corrosion inhibitors to create a protective barrier on the metal surfaces.
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