Treatment programme overcomes high TAN problems
Processing high TAN crude with low sulphur shale oil presented challenging corrosion problems for a refiner.
Sanjay Dwivedy and Ralph Navarrete
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With the increase in unconventional crude supplies, the processing of new crude blends has become a pathway to profitable operations for many refiners. However, to fully capture the discounted price of opportunity crudes, a number of diverse challenges may need to be overcome. One of the biggest challenges that opportunity crudes bring is the corrosion that can result from highly acidic crudes, which can lead to refinery failures. When metallurgical upgrades are neither feasible nor economical, chemical treatment strategies may be the best option to mitigate the corrosion potential of high total acid number (TAN) crude oils.
Refiners are looking for the best corrosion mitigation programme, whether they are facing traditional or non-traditional challenging naphthenic acid corrosion (NAC) issues. It is essential that these programmes include the right assessment, tailored additives, and real-time monitoring to safely increase crude TAN levels and â€¨ultimately improve operating margins. Baker Hughes offers â€¨the Smartguard NAC control programme that uses a combination of chemical inhibitors, detailed unit surveys, and monitoring techniques to reduce the impact of NAC on refinery operations.
One such example is a north east US refinery whose NAC challenges resulted after a change in crude mix, forcing the refinery to greatly reduce the amount of high TAN opportunity crude they were processing. Historically, the refinery had always run a light, sweet crude slate typical of north-east US refineries, but had added a heavy, high TAN opportunity crude to the diet several years prior to take advantage of favourable crude discounts. More recently, like many other refiners, this company had begun adding increasing amounts of shale oil to its crude diet.
Crude slates that are high in TAN and low in sulphur, like the crude blends being processed in this refinery, are highly corrosive and require specific corrosion control solutions. The lack of sulphur in the different streams reduces protection from the normally occurring iron sulphide passivation layer and increases the need for other protections, such as chemical inhibitor treatment. Throughout this time, this refiner, like many across the country, was slowly increasing the percentage of low-to-no sulphur shale oil in its crude blend, which became an extremely important factor in determining why corrosion was accelerating.
Traditional phosphate ester inhibitors had been used successfully at â€¨this refinery for years as part â€¨of a comprehensive reliability programme. As expected, traditional inhibitors provided effective protection for nearly all crude unit equipment, only showing vulnerability in the areas of highest shear, typically areas of two-phase flow and extremely high velocity, such as vacuum tower heater transfer lines. High shear stresses result in rapid deterioration of any protective scale — whether from naturally occurring sulphur or chemical inhibitors — exposing fresh bare metal and accelerating corrosion rates.
During a planned crude unit shutdown, the refinery discovered unexpected corrosion in areas of the vacuum tower heater transfer lines that previous risk assessments had identified as being at lower risk for failure. In response, the refiner made the necessary repairs and restarted the unit, but reduced the amount of high TAN opportunity crude they were processing, significantly impacting the profitability of the refinery.
The refiner needed a solution that would protect the vacuum tower transfer lines — as well as other potentially at-risk circuits — and allow the unit to restore the higher charge rates of high TAN opportunity crude. Although the refinery planned to eventually replace the transfer lines with upgraded, corrosion-resistant metallurgy, the customer wanted reassurance that the transfer lines would not fail again before the planned turnaround could be completed.
The first step for the Baker Hughes team was to understand the root cause of the failures and why areas historically at lower risk were now seeing abnormally high corrosion rates. The Baker Hughes metallurgists and corrosion specialists assessed the operation to gain an understanding of the feedstock and side stream characteristics, equipment configuration and metallurgies, and corrosion performance history.
Recognising that the high TAN, low sulphur feedstock of the refinery was not a typical opportunity crude operation, the Baker Hughes team hypothesised that further reduction in total sulphur in the crude — driven by the increasing amount of shale oil in the crude slate — might be the reason for the accelerated corrosion rates. Examining the last three years of data on the atmospheric tower bottoms (ATB), they found that the ratio of sulphur:TAN in the ATB had steadily fallen over the previous year to an average of 0.07 (see â€¨Figure 1).
When compared side-by-side with other Baker Hughes customers processing high TAN opportunity crudes, this refinery’s sulphur:TAN ratios proved to be clear outliers, nearly 75% lower than the next highest ratio (see Figure 2). What was happening at this refinery was a unique confluence of operating conditions that was manifesting itself as corrosion damage in locations that, under only slight circumstances, would likely have shown no damage.
Additionally, Baker Hughes evaluated the effectiveness of two inhibitors under these unique conditions: Smartguard 2805, the traditional phosphate ester that has been an industry workhorse for more than 20 years, and Smartguard 2800, a patented thiophosphate ester in wide use globally. Historically, the two inhibitors have shown nearly identical performance in both laboratory and commercial applications at the same dosages.
However, in laboratory corrosion testing of oils with very high TAN (5.0) and no sulphur (0%), Smartguard 2800 significantly outperformed the traditional phosphate ester chemistry. The corrosion rate of a carbon steel coupon treated with Smartguard 2800 was more than 80% lower than that of a coupon treated with the same dosage of the traditional additive (see Figure 3).
To confirm why the Smartguard 2800 inhibitor performed substantially better than the traditional phosphate ester in very low sulphur conditions, Baker Hughes exposed parts of carbon steel coupons to each inhibitor — leaving part of the coupon as bare metal, unexposed to the additive — and used vertical scanning interferometry (VSI) to obtain a 3D image of the surface of the metal.
As Figure 4 shows, the VSI results reveal that the fraction of each coupon that was exposed to the inhibitor shows a greater thickness due to the protective scale that was created on the surface. However, the scale in the area exposed to the Smartguard 2805 additive (left) is noticeably more variable — note the greater number of peaks and valleys — than the tighter, more uniform coverage created by Smartguard 2800 the thiophosphate ester (right). It is believed that the incorporation of sulphur directly into the inhibitor molecule allows more effective transport of inhibiting phosphorus to the metal surface, particularly in comparison to traditional phosphate esters or products that only add sulphur compounds to the inhibitor solvent.
One side benefit of the more efficient interaction with the metal surface was that Smartguard 2800 was able to be formulated with a much lower phosphorus content than traditional naphthenic acid inhibitors. The use of low phosphorus inhibitor formulations has garnered greater attention in recent years as refineries look to reduce the risk of potential downstream phosphorous effects, such as equipment fouling or poisoning of expensive hydrotreater catalyst.
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