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.
One area considered critical to profitable and successful process adoption is plant integrity to deliver continuous production with limited downtime. This requires corrosion management, which can be difficult because most refiners have a limited operational track record or a lack of long-term documentation of occurring corrosion mechanisms. These stores of information serve as a knowledge basis for traditional integrity programs for fossil fuel refineries, but they are not widely available for biofuel refining.
This article provides a holistic overview of renewable fuel processing equipment and associated corrosion mechanisms, and it shows how corrosion monitoring can be used to mitigate issues.
Renewable feedstocks. There are multiple feedstock options for renewable fuels, with many varying by region and season. ESG pressures can influence feedstock selections and may lead to variations throughout a plant’s service lifecycle. Retrofits of existing processing units are often required to match unit designs and materials to changing process conditions and corrosive contaminants.
Fresh vegetable oils were a common feedstock in first-generation biofuels, with refiners converting them into fatty acid methyl esters. Fueled by incentive programs, this well-researched transesterification process required relatively low capital expenditures, leading to the conversion of many traditional crude oil refineries into biodiesel plants throughout the early 2000s. Recently, concerns around fuel blending and engine compatibility have led to the development of hydrotreated processes instead of transesterification.
These types of processes produce drop-in fuels that are chemically nearly identical to fossil-based fuels, and their use is less limited by restrictive blending limits. For example, hydrotreated vegetable oils are straight-chain paraffinic hydrocarbons that are free of aromatics, oxygen and sulfur. They also have high cetane numbers and do not exhibit any of biodiesel’s concerning effects at end-use points, such as increased nitrogen oxide emissions, poor cold-operation properties, deposit formation, storage stability issues and more rapid aging of engine oil. However, societal questions regarding the agricultural use of energy crops in competition with food crops remain an issue.
These concerns have led to second-generation biofuels, referred to as green or renewable diesel and sustainable aviation fuel (SAF). Novel catalysts allow advanced, sustainable feedstock (e.g., tallow oil from bacon production) to be hydroprocessed into drop-in fuels. Used and rendered fat and grease, collected in traps as waste products, are another primary area of investigation for sustainable feedstocks. Tax credits and avoided landfill costs can create a lucrative revenue stream, boosting the profitability of a renewable fuel production unit.
However, as with all waste products, there are challenges of consistent feedstock quality and reliable supply chains. Polyethylene packing impurities are typically found in animal fats, resulting in process challenges with catalyst deactivation, fouling concerns with heat exchangers, and flow constraints and catalyst bed pressure drops triggered by plugging. In general, these types of waste oils require heat-traced feed piping due to their lowered cloud point.
Compared to vegetable oils, animal fats (such as tallow oil) tend to have larger amounts of free fatty acids (FFAs) (TABLE 1). While organic sulfur components in renewables are decreased compared to petroleum feedstocks, the increased influx of organic chlorides and nitrates creates challenges with process equipment and piping integrity downstream of hydrotreating units.
In addition to these and other corrosion-accelerating substances, the presence of water facilitates corrosion mechanisms by providing an electrolytic pathway. Water solubilizes organic and inorganic acids, creating carbon dioxide (CO2) via hydrodecarboxylation, which turns organic chlorides into hydrochloric acid (HCl) and promotes microbiologically influenced corrosion (MIC). Water forms in the hydroprocessing reactor section, and it is a decomposition product of renewable feedstocks in tanks and pretreatment sections. In addition, biofuel feedstocks are often hygroscopic and will attract humidity from the environment into process streams.
Biofuel refining facilities around the world are addressing these processing issues by proactively deploying permanently installed and continuous wall-thickness monitors to track corrosion in critical locations. Tighter monitoring enables cost-effective tracking of corrosion in areas of concern, and enables refiners to pinpoint specific feedstocks or process operations that result in accelerated corrosion rates. This information facilitates the optimization of corrosion mitigation strategies online, along with the validation of the effectiveness of these mitigation strategies, so that timely and evidence-based integrity management decisions can be made most effectively.
Renewable fuel production processes. With wide-ranging recent developments, various novel processes have been researched, engineered and patented. As a general overview, this article will define a generic process scheme to assess dominant concerns of corrosion and corresponding risk to plant integrity. Drop-in fuel-grade production processes require advanced phases of chemical conversion involving purification, deoxygenation and novel catalysts.
FIG. 1 depicts and identifies key units, defining specific corrosion mechanisms in each. Like traditional refinery hydroprocessing units, base feedstocks and intermediates are first pretreated, blended and stored in separate pretreatment units and tank farms. However, hydrogen consumption with alternative feedstocks has significantly increased.
Storage and tank farms may experience corrosion from feedstock degradation products and as low-temperature environments promote MIC. Pretreatment steps may include the separation of solid particles, pH adjustments or a liquefaction step for solid feedstocks into bio-oils. Bio-oils usually have an aqueous and lipid phase, and aqueous phase processing and storage equipment may experience acidic corrosion from FFAs.
The pretreated feed is passed through a bio-oil heater or heat exchanger to raise its temperature to 315°C–400°C (600°F –750°F), and it is subsequently injected with hydrogen, which is typically a major shifting point for increased corrosion and degradation mechanisms.
Depending on licensors, renewable feedstocks and final fuel products, the degree of process cracking severity will differ, and hydrogen may be combined with the renewable feedstock in a central mixing point or dispersed over multiple reactor quenches. Nonetheless, when hydrogen is added, corrosion mechanisms will change with the presence of competing hydrogenation reactions.
Process designs may incorporate one or multiple reactors, depending on feedstock preparation, contaminations and process product output requirements.
The first is commonly referred to as the hydrodeoxygenation reactor. This stage is used for feedstock cleanup (capturing contaminants such as metals, particles and scales) to mitigate catalyst deactivation and clogging. Simultaneously, hydrocarbon hetero atoms (such as oxygen, sulfur and nitrogen) are eliminated to create hydrocarbons suitable as drop-in fuels. Unsaturated hydrocarbons with double bonds—commonly referred to as olefins—are converted into straight-chain hydrocarbons.
For corrosion mechanism assessment, it is pertinent to note the formation of ammonia from organic nitrogen components, water from oxygen and hydrosulfuric acid from sulfur components in renewable feedstock.
HCl is another corrosive hydrotreating byproduct, and it is best controlled by feedstock monitoring and the implementation of potential corrosion mitigation strategies. Additionally, the presence of chlorides and amines will lead to salting issues.
The next unit is a hydro-isomerization or dewaxing reactor, or a hydrocracker phase, depending on processed feedstocks and desired end products. These units produce branched hydrocarbons with improved cold flow properties for renewable diesel products—whereas, more severe hydrocracking stages are required to produce SAF.
While these reactor stages may experience decreased corrosion after the initial removal of contaminants, they may also experience other severe degradation mechanisms due to increased temperatures and to system and hydrogen partial pressures.
A series of high- and low-pressure separators and strippers typically connects the two reactor stages, usually with acid-removal stages like traditional amine units and sour water strippers. These systems are challenged by strong acid loads that may fluctuate dramatically with feedstock variations and inconsistent input qualities.
Major integrity concerns arise in the separation section due to the presence of hydrogenation reaction side products mentioned in the preceding paragraphs. The safe operation of this section depends on monitoring systems to trigger appropriate corrosion mitigation measures.
Sour water byproducts are further treated in wastewater treatment facilities that are often challenged by novel corrosion severity. In traditional refining, material grades chosen for this type of service experience higher corrosion due to very low pH water phases and MIC.
Common corrosion monitoring technologies. For the past 60 yr, ultrasound has been used to measure metal wall thickness. This involves manually placing a transducer directly onto the metal surface to generate ultrasound, which then travels through the metal until it reflects off the inner metal surface. By recording the reflected ultrasound signal and calculating the time difference between the sending and reflected signals, the wall thickness can be measured.
However, completing a full set of measurements for a medium-sized refinery with > 80,000 corrosion measurement points can be extremely time consuming and labor intensive. As a result, the wall thickness at low-level to medium-level risk points may only be measured every 2 yr–3 yr. This makes it challenging to obtain data frequently enough to determine corrosion rates with confidence, or to link periods of high wall loss to specific feedstocks or process operations, with the latter requiring daily measurements.
Despite being relatively simple, manual ultrasound methods have two other main disadvantages. Repeatability and reproducibility errors are common, as it is highly unlikely that consecutive measurements will be taken in precisely the same location by the same technician. In addition, the equipment used and the skill level of the technician can vary between measurements, thus introducing high variability. FIG. 2 shows manual measurements at a single location over an 11-yr period. Different conclusions regarding wall thickness and corrosion rates can be drawn over time. From such data, it could be inferred that the accuracy of manual ultrasound is ± 0.5 mm–1 mm.
The technician needs access to the equipment at the measurement locations of interest; therefore, scaffolding (possibly permanently installed) and the stripping of insulation to expose the metal work to make the manual measurements are required.
Permanently installed ultrasonic wireless wall thickness monitoring sensors (FIG. 3) address these and other issues, making them the best option for most high-temperature corrosion monitoring applications.
These sensors can measure small changes in wall thickness and exhibit robustness to extreme plant conditions, while also having extended battery life to provide reliable operation over the entire cycle between turnarounds. Additionally, they are simple and cost effective to install at scale and have been field proven in thousands of applications worldwide over the past few decades.
The following will examine how these and other types of sensors can be used to manage corrosion in the different processes required for biofuel refining.
Pretreatment, storage and reactor feed. FFAs can cause severe corrosion to the piping and equipment upstream of the hydrogen mixing point. Similar to past experiences with opportunity crudes and naphthenic acid corrosion, this mechanism is sparsely documented due to the varying feedstock scenarios and the limited availability of research or case studies.
A biofuel feedstock’s acidity is described by its total acid number (TAN), which is a measure of acidity but not direct corrosivity. Beyond the hydrogen mixing point in the reactors, the FFAs are converted into water and CO2, aided by the hydrotreating catalyst.
The following processes typically experience the following types of corrosion.
Acidic corrosion. Renewable feedstocks contain a mix of fatty acids, long carbon chains with one or multiple double bonds, and more branched acidic components, such as resin acids.
TANs in biofuel processing are very high in comparison to fossil fuel feedstocks, varying between 0 mg KOH/g and 200 mg KOH/g feed. In addition, the decomposition of triglycerides will lead to an additional acid load in processing units, which is not detected with TAN testing in feedstocks.
The acidic corrosion mechanism causes localized metal thinning, which increases with process temperatures and flow velocities. While temperatures > 230°C (446°F) are considered susceptible for fossil feeds, this threshold is reduced to 150°C (302°F) with renewable feedstocks due to high levels of acidity. The formed iron salts are highly soluble in oil and do not form protective scales and deposits in the catalyst bed, causing pressure drop concerns and catalyst clogging.
FFAs are no longer a concern after entering the hydrotreating section, but this process results in the formation of CO2. Carbonic acid may be present in the storage section through feedstocks or their degradation processes, or it can be formed in the reactor effluent due to the presence of water and CO2. Carbonic acid corrosion will be described in the reactor effluent section of Part 2 of this article.
Renewable diesel feedstocks may also contain contaminants such as metals and chlorides, leading to known corrosion challenges.
MIC. Metabolic products of living organisms (e.g., bacteria, algae, fungi) cause localized corrosion in the form of distinctive pitting and tubercles, or crevice corrosion, often under bio-film deposits. All aqueous environments are affected, even when water is only intermittently present. All low-temperature areas are affected, from feedstock handling and tank farms to air coolers in processing units to final wastewater treatment facilities.
Low-flow and stagnant conditions promote the growth of these microorganisms and corresponding MIC. This multitude of organisms will allow populations to be present in all conditions and nutrients (such as inorganic substances like sulfur, ammonia, iron and sulfate compounds), as well as hydrogen sulfide, organic hydrocarbons and acids. The presence of carbon, nitrogen and phosphorus are required and available in higher concentrations with biofuel processes—there are also aerobic and anaerobic organisms, depending on the presence of oxygen. Organisms can be found in pH ranges of 0–12 and in temperatures from –17°C–110°C (0°F–230°F).
As MIC damage is very localized, it is often detected with corrosion coupons and timely sampling. Frequent flushing and biocide application may control organism colonies. Established colonies may build up protective sludge layers, complicating organisms and MIC control.
Part 2 will be featured in the October issue of Hydrocarbon Processing. HP
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a Rosemount™ Wireless Permasense WT210 sensors
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.