W. Fazackerley, Emerson, London, England
The production of carbon-neutral and renewable transportation fuels is growing rapidly, driven by the need to find feedstocks beyond fossil resources. Environmental, social and governance (ESG) initiatives—along with accelerated consumer demand for sustainable and carbon-negative fuel products—are also driving demand. Renewable fuels for aviation and road transportation are at the forefront of this trend, and low-carbon and renewable fuel standards have been implemented by many nations worldwide to accelerate progress.
This two-part article provides a holistic overview of renewable fuel processing equipment and associated corrosion mechanisms, and also shows how corrosion monitoring can be used to mitigate issues. Part 1 detailed renewable feedstocks and renewable fuels production processes, as well as common corrosion monitoring technologies. This article, Part 2, will focus on corrosion, along with a case study of how a European refiner used an online corrosion monitoring solution to mitigate the increased risk associated with renewable feedstocks.
Reactor stage. The reactor stage of all hydroprocessing units experiences various degrees of degradation based on hydrogen partial pressures and temperatures. Process variables influence cracking severity and the influx of corrosive specimen from feedstock streams.
High-temperature hydrogen/hydrogen sulfide (H2S) corrosion. At temperatures above 450°F (230°C) and at locations downstream of the injection point, the presence of hydrogen will lead to generalized corrosion mechanisms with process streams containing H2S. The formed scale, which is tenacious and expands five times in volume compared to the lost metal, can be mistaken for unaffected metal by its shiny gray appearance.
Permanently mounted wall thickness monitoring may be used to safeguard critical process equipment—especially with changing feedstock scenarios—with high-temperature wireless electromagnetic acoustic transducer sensors that are most suitable for this service (FIG. 4). These wireless sensors are magnetically deployed and secured with a simple strap, so installation is fast and simple. Highly reliable and accurate wall-thickness measurements can be transmitted wirelessly twice daily to monitoring software.
Industry experience curves aid in the appropriate material selection and chromium (Cr) and molybdenum content, as they predict corrosion rates based on process temperatures and H2S concentrations for select material.
Couper-Gorman curves provide a reasonable estimate of corrosion rates for areas susceptible to hydrogen/H2S corrosion, such as the reactor feed downstream of the hydrogen mixing point, the reactor itself, the reactor effluent and the recycle hydrogen gas lines.
Downstream from the reactor. As described, the high oxygen content from renewable feedstocks leads to the formation of large amounts of water and carbon dioxide (CO2), causing corrosion concerns.
Carbonic acid corrosion. CO2 dissolves in water to form carbonic acid, which also results in lowered pH levels—with both phenomena leading to generalized corrosion of carbon and low-alloy steels under 12% Cr. Pitting and localized corrosion may be caused in areas of increased process flow velocities, impingement and turbulence.
Generally, corrosion rates increase with the presence of oxygen and CO2 partial pressures, often where CO2 condensates from the vapor phase. Corrosion rates will increase with process temperatures until CO2 is driven off into the gas phase.
Hydroprocessing effluent streams can be affected by severe corrosion when process temperatures drop below the dewpoint, which may vary depending on unit operation. At risk are areas where condensation may occur, such as bottoms with water phases, at water/vapor interfaces and in top areas of wet gas systems.
Areas of risk are those of high turbulence, such as elbows, tees, reducers and piping downstream of control valves. Pitting, grooving or smooth washouts have been experienced.
Dosage of corrosion inhibitors, pH increases above six in condensate systems, and selective upgrades have shown to be successful tools for carbonic acid corrosion mitigation. Adjustments to piping configurations, as well as the effective management of flow regimes, can improve operating conditions—in turn, minimizing corrosion.
Measurements from strategically placed wall-thickness monitoring sensors—along with water analyses of pH, iron and oxygen—can be used to determine successful changes in operating conditions.
Aqueous organic corrosion. Low-molecular-weight acids may form and cause significant aqueous corrosion when they dissolve in water. Areas of high susceptibility include where the water dewpoint is reached, such as pumparounds and headers of distillation columns.
The corrosivity of these acids decreases with their molecular weight or chain length (TABLE 2). Low organic acids are soluble in naphtha and are transported throughout the process, and they are extracted when liquid water is present. Besides concentration levels, the system’s pH and presence of other substances—such as hydrochloric (HCl), hydrosulfuric and carbonic acids—affect the severity of corrosion. Other influencing factors are flow velocities and the availability of liquid water.
The decomposition of naphthenic and other long-chained acids can also contribute to organic acid quantities. Therefore, high total acid numbers (TANs) may be indicators for risk in overheads downstream of hydroprocessing reactors. Aqueous organic acid corrosion is often smooth, generally appearing to be similar to carbonic or HCl acid attacks. When aqueous organic corrosion occurs, areas of risk are localized and tend to be where water droplets contact the metal surface when water condenses or separates out of a process stream.
Areas where temperatures decrease to the water dewpoint are the primary focus points for integrity monitoring, but other areas of localized attack can be mixing points where process streams containing water and organic acids meet. Velocity and turbulence are also always areas of increased corrosion severity.
The dosage of acid-neutralizing chemicals can be challenged by the described multitude of corrosion mechanisms exacerbating their effects. Issues can arise with periodic changes in the unit’s feedstock and the production of organic acids, and the presence of these low-molecular-weight acids can be masked by other acids.
The system’s pH decreases rapidly in the usually mildly corrosive environments of overhead systems, which can suddenly increase neutralizer demands. Conversely, the overdosage of neutralizers may lead to the formation of amine salts, leading to additional corrosion challenges.
Overhead systems are often designed with austenitic steels to protect against this form of attack, but they are then vulnerable to pitting and stress corrosion cracking with chlorides.
In addition to water and pH sampling, measurements from wall-thickness sensors can help optimize dosage adjustments of neutralizing and filming amines.
Ammonium bisulfide corrosion. Renewable feedstocks contain larger amounts of nitrogen, which are converted into ammonia and, further, into ammonium bisulfide salts in the presence of H2S. Organic sulfur in feedstocks results in the presence or formation of H2S. The presence of sulfur is especially concerning for coprocessing units when high-level sulfur intermediates [e.g., vacuum gasoil (VGO)] are hydroprocessed with renewable feedstocks. VGO precipitates in the reactor effluent when temperatures reach a range of 120°F–150°F (50°C–65°C), thus leading to fouling and plugging.
Under-deposit corrosion can become an issue with salt deposits in overhead systems. Equipment becomes vulnerable to fouling and/or flow-accelerated corrosion in all areas of high flow and turbulence, such as in inlets and outlets to air cooler piping, and in exchanger tubes, effluent separators and air cooler header boxes.
While dry ammonium bisulfide salts are not corrosive, they readily dissolve in process water or water washes to form corrosive, concentrated solutions. Ammonium bisulfide solution corrosion, or alkaline sour water corrosion, affects all equipment downstream of the hydroprocessing reactor, specifically in areas of high velocity and turbulence, leading to high shear.
Process variables influencing corrosion severity are ammonium bisulfide concentration, H2S partial pressure, pH, temperature and flow distributions. Ammonium bisulfide solution concentrations over 2 wt% are considered corrosive for carbon steel in turbulent areas. Oxygen and iron contaminants in the washwater can lead to increased corrosion and fouling.
Hydroprocessing reactor effluent systems are very susceptible to this described localized corrosion, and many failures have been reported. Other areas of concern are those with entrained or condensing sour water present—namely, hydrocarbon line reactor effluent separators and vapor lines from the high-pressure separators, as well as stripper column overheads in, for example, sour water strippers and amine unit systems. Accelerated corrosion is experienced with high concentrations of ammonium bisulfide and the presence of cyanides.
Flow regime control is key for this type of corrosion because high flow areas will experience general wall loss with a very high level of localized corrosion in turbulent sections. Low flow leads to under-deposit corrosion when washwater cannot dissolve salt precipitations sufficiently. The resulting plugging and fouling are prime concerns for all heat exchangers. Velocities should be kept between 2 ft/sec (0.6 m/sec) and 5 ft/sec (1.5 m/sec) for carbon steel, and between 2 ft/sec (0.6 m/sec) and 10 ft/sec (3 m/sec) for stainless steel. Areas with flows over 20 ft/sec (6 m/sec) will require upgrades to duplex stainless steel. Hydraulically balanced and symmetrical flows should be established and maintained, and retrofitted plants may have to undergo detailed redesign considerations, such as flow regime assessments and damage mechanism reviews.
Monitoring of the alkaline sour water concentration is another crucial factor for corrosion management. It should ideally be kept under 2 wt%, and concentrations over 8 wt% should be avoided.
Ammonium bisulfide corrosion is very localized in its nature and can be easily missed, so ultrasonic testing instruments and corrosion probes should be placed in areas of high turbulence and velocity. Injection points of waterwashes, implemented to mitigate corrosion, are other areas of potential integrity risk and should receive monitoring. Ultrasonic test measurements downstream of control valves are recommended when ammonium bisulfide concentration is high in the process stream.
Other sources for integrity challenges are halogens, specifically chlorides. Chlorides can enter the hydroprocessing unit as an inorganic or organic chloride in the renewable hydrocarbon feed, or with the recycled hydrogen, and then react with hydrogen to form hydrochloric acid, which is highly corrosive.
HCl acid corrosion. Chlorides present in the feedstock will be converted into HCl acid in the hydrotreating reactor, which can cause corrosion in both the reactor effluent stream and in the downstream units, such as the sour water stripper.
In addition to under-deposit corrosion by chloride salts, HCl acid in an aqueous solution is a concern across wide ranges of concentration, and it often causes general and localized corrosion in carbon steel, with stainless steels subject to pitting attack.
Hydrogen chloride gas is not corrosive, but it readily forms HCl acid with available water and with process streams through fractionation sections, which can cause severe dewpoint corrosion. The first droplets of water at dewpoint lead to very high corrosion rates due to very low pH and high acidity. This phenomenon is seen throughout all overhead sections with declining process temperatures.
In general, corrosion rates will be greatest where high concentrations of hydrogen chloride are exposed to high temperatures, which greatly increases the risk of dewpoint corrosion. All carbon-steel sections exposed to process media under a pH of 4.5 are at risk, and corrosion rates increase with the presence of oxygen and other oxidizing agents. Units with low nitrogen feedstocks are particularly at risk.
Transitional components (such as elbows, fittings and dead legs) require increased attention to corrosion monitoring—e.g., using wall-thickness monitoring sensors. Corrosion probes can provide additional information regarding damage severity, and chloride and iron content may also be monitored.
Ammonium chloride and amine hydrochloride corrosion and salting. All hydroprocessing effluent piping and equipment are subject to this localized corrosion mechanism, which often presents as pitting. It usually occurs under deposits of ammonium chloride, even without the presence of a free water phase.
Ammonium chloride salts can form where ammonia and HCl acid are present and there is water available to condense. Various parts of the unit are susceptible, especially the effluent side of the hot feed/effluent exchangers when there is water in the effluent train.
The precipitation of ammonium chloride salts from high-temperature streams can increase at temperatures of about 400°F (205°C), well above the water dewpoint. System overheads and top pumparounds are especially at risk. The severity of corrosion depends on the concentrations of ammonia, HCl acid and amine salts, and corrosion rates generally increase with increasing temperature.
Other factors to consider are water availability and the hygroscopic nature of ammonium chloride salts, which readily absorb water. Very aggressive corrosion of more than 100 mils/yr (2.5 mm/yr) has been observed due to the presence of very small amounts of water because ammonium chloride readily dissolves in water into a highly corrosive and acidic solution. Neutralizing amines can also react with hydrogen chloride to form amine hydrochlorides that can act in a similar fashion. To prevent this type of corrosion when chlorides in feedstocks cannot be limited, waterwashes may be required to limit salt formation and wash-formed salt deposits.
Neutralizing amines may form ammonium chloride salts with HCl acid. Ammonium chloride salts can be mobile and follow process streams and gravity. Temperature monitoring can be most beneficial for salt precipitation control. Strategically placed wall-thickness sensors can be used to detect localized corrosion, and corrosion probes may be placed in known areas of salt precipitation and accumulation.
This corrosion mechanism is particularly susceptible to producing irregular patterns on the metal surface. Many continuous ultrasonic thickness monitoring sensors would struggle in these conditions because the ultrasonic reflections are badly distorted upon return (FIG. 5). The result is typically poor repeatability and slow response times, making timely decisions impossible.
A patented ultrasonic signal processing measurementc from the author’s company significantly improves the accuracy of the wall thickness and corrosion rate calculation. It works by comparing ultrasonic signals and dynamically adjusting their alignment based on the previous signals. This technique is particularly useful in cases of severe corrosion—such as those presented by chlorides—where it significantly improves measurement accuracy by eliminating the effects of noise.
This ultrasonic signal processing measurementc can achieve a repeatability of up to 2.5 microns (0.0001 in.) in field conditions, resulting in the fastest response time of any ultrasonic thickness monitoring solution. Furthermore, this ultrasonic signal processing measurementc offers a unique visualization of the rate of change via a color bar for each sensor, enabling quick and easy identification of areas with high rates of change on the inside surface of the pipe or vessel.
Amine corrosion. Amine corrosion refers to corrosion mechanisms in the amine treating unit. Amines themselves are not corrosive, but they readily react with the process fluid—forming heat-stable salts and corrosion, and accelerating degradation byproducts. In addition, corrosive process gas stream components (such as CO2 and H2S) may be present and dissolved in amines.
Amine corrosion is dependent on process temperatures, contaminants and the type of amine. Listed in order of corrosion severity influence, the following amines are commercially applied: monoethanolamine, diglycolamine, diisopropylamine, diethanolamine and methyl diethanolamine. Flow velocities and operating practices largely influence the severity of amine corrosion.
Low-flow velocities may lead to uniform corrosion, whereas turbulent, high-velocity areas experience localized attacks. Process flow velocities should be limited to 3 ft/sec–6 ft/sec (1 m/sec–2 m/sec) for rich amine, and approximately 20 ft/sec (6 m/sec) for lean amine service.
Rising process temperatures will increase corrosion rates, especially for rich amine lines and equipment. At approximately 220°F (105°C), severe localized corrosion may occur with acid gas flashing.
Root causes of challenged amine systems are often poor operating practices, faulty process design or solvent contaminations. Therefore, corrosion control in amine units is best facilitated by establishing and maintaining proper operating conditions, which may be challenging with alternating process feedstocks. Acid gas loading areas may require special attention, and appropriate process temperatures should be maintained to avoid degradation of amines. Pressure should be controlled to avoid flashing and to minimize buildup of heat-stable salts.
A lean amine solution should experience low corrosion rates due to its low conductivity and high pH, but with accumulations of heat-stable salts. Over-stripped solutions may compromise stable and protective iron sulfide scales. Areas of localized corrosion may be liquid/vapor interfaces, flow impingement and turbulent flow areas.
In general, amine units experience integrity challenges in hot and turbulent areas, such as the regenerator and reboiler, including feed and return lines. Acid gas corrosion may be caused by excessive regeneration in the reboiler. Regenerator overhead systems may also experience corrosion, accelerated by the presence of ammonia, H2S and hydrogen cyanide.
Other areas requiring special attention are rich amine heat exchange service, hot sections for lean services, overhead condensers and areas downstream of pressure letdown valves.
Monitoring iron content may be beneficial for assessing the amine degradation level.
Wall-thickness sensors, in combination with corrosion probes, are beneficial in areas of known corrosion to control dosing of corrosion inhibitors.
Case study. As part of a European refiner’s commitment to decarbonization, it repurposed a hydroprocessing unit to use renewable feedstocks, such as vegetable oils and used cooking oils. Several adaptations were made to make the unit safe and suitable for this use, including upgrading metallurgy and piping system configuration changes.
Corrosion was one of the major concerns during the switchover to biofuel refining because the acidic and abrasive nature of some of the feedstocks (e.g., used cooking oil and waste animal fats) were expected to cause corrosion. Additionally, the high temperatures and pressures required during the refining process were known to accelerate corrosion. An online corrosion monitoring solution from the author’s company was installed to mitigate the risk of corrosion occurring in catalysts, heaters and transfer lines. The system’s sensors wirelessly sent wall thickness data twice per day to monitoring software, which provided insights into plant health via real-time asset monitoring—thus enabling safe and continued operation of the facility, while limiting expensive metallurgy upgrades during conversion projects to process biofuels.
Following a successful trial period of blended renewable and crude feedstocks, 100% recycled oil is now used as feedstock. The project demonstrated that repurposing old units can be an effective way to achieve decarbonization goals, while reducing costs and minimizing waste.
By using this online corrosion monitoring solution, the refiner successfully mitigated the increased corrosion risk associated with renewable feedstocks, allowing it to achieve its sustainability goals without compromising equipment integrity.
Takeaways. The increased use of biofuel feedstocks by refiners is driven by a variety of factors, including regulatory compliance, sustainability and diversification of their supplier base. However, the introduction of these feedstocks poses significant risks due to their chemical differences compared to traditional crude feedstocks.
To address these risks, many refiners have undertaken costly conversion projects to protect their plants from corrosion caused by biofuels. These refiners are increasingly turning to online integrity sensors to quickly detect corrosion and mitigate risk by ensuring critical assets remain healthy and reliable. With these strategies in place, refiners can effectively manage the challenges of incorporating biofuel feedstocks into their refining processes, while ensuring the safety and longevity of their equipment.
While some focus on greenfield biofuel refineries, there is a drive for conversion of existing crude-based refineries. Renewable feedstocks can also be blended with traditional crude to create a product fit for refining in existing refineries. However, challenges arise with legacy configurations, as even small amounts of alternate feedstocks can be problematic.
When not handled properly, renewable feedstocks can quickly cause significant damage through rapid corrosion mechanisms brought on by chemical elements in the feedstocks. Refiners are already experienced in corrosion mitigation caused by traditional crudes and are increasingly using wall-thickness monitoring sensors to track corrosion. With wall-thickness measurements typically available twice daily, it becomes possible to correlate any unexpected corrosion against feedstock and process changes.
It is critical to choose the right supplier for these efforts—the supplier should have a broad corrosion and erosion measurement portfolio, including the software ecosystem required to deliver data where it is needed. The selected supplier should also exhibit a comprehensive knowledge of corrosion and erosion risks, and an up-to-date understanding of how refineries are coping with these risks. HP
NOTES
b Rosemount Wireless Permasense ET410 sensor
c Adaptive cross-correlation (AXC)
WILLIAM FAZACKERLEY is a Global Product Manager in Emerson’s Corrosion and Erosion business unit. He has more than 10 yr of experience in information technology (IT) and software development, and specializes in digital transformation, working closely with customers to guide the strategic direction of Emerson’s product portfolio. Fazackerley studied computing and applied information and communications technology (ICT) at Central Sussex College in the UK.