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Alkaline Sour Water Corrosion

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Amine Corrosion

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General Information

Removal of acidic compounds (H₂S, CO₂, COS etc.) from hydrocarbon streams, both liquid and gaseous, is a critical aspect of refinery operations. The purification of hydrocarbon streams from acidic compounds is commonly achieved through the absorption-desorption process, employing various alkanolamine-based solvents.

Figure 1 illustrates a typical amine unit configuration with a simple absorber/contactor – regenerator setup. However, variations of this arrangement are also possible, depending on factors such as treatment type, the solvent used, or the type/concentration of acid compounds.

Amine Corrosion

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Amine Unit

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Corrosion Monitoring In Amine Unit

The importance of corrosion monitoring in amine units appears to have diminished over the last two decades. Several factors contribute to this trend. First, there has been a general shift toward upgrading metallurgy from carbon steel to stainless steel or higher alloys in the most critical areas, such as the hot lean outlet from the regenerator and the lean/rich exchanger. Second, the increased use of proprietary solvent mixtures with enhanced anti-corrosion properties and improved resistance to decomposition has played a significant role. Lastly, most corrosion damage in these systems is more often associated with localized amine stress corrosion cracking, flow-induced corrosion, or erosion-corrosion phenomena.

Ammonium Bisulfide Corrosion

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General Information

Ammonium bisulfide corrosion, also known as alkaline sour water corrosion, is a prevalent issue in hydroprocessing units, which encompass hydrocracking (HC), hydrotreating (HT), and hydrodesulfurization (HDS). Catalytic hydroprocessing involves desulfurization and denitrification reactions (see Equations 1 and 2), resulting in the production of ammonia (NH ₃) and hydrogen sulfide (H₂S). These compounds readily react to form ammonium bisulfide, or formally, ammonium hydrosulfide (NH₄HS), through a simple, reversible reaction as shown in Equation 3.

Ammonium Chloride Corrosion

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General Information

NH₄Cl corrosion is virtually present at any refinery process unit where gaseous HCl and NH₃ are stream components. Table 1 shows most common areas affected by NH₄Cl corrosion.

Table 1 Potential locations for NH₄Cl corrosion in process units.¹ ² ³ ⁴ ⁵

Process Unit	Affected Area
Crude Distillation Unit (CDU)	Atmospheric tower top Atmospheric tower overhead (OVHD pipelines and commonly 1st stage exchangers)
Catalytic Reforming Unit (CRU)	Product separator Debutanizer section (OVHD)
Fluid Catalytic Cracking (FCC)	Main fractionator top section and OVHD system Stripping columns
Hydroprocessing Hydrotreating/Hydrocracking	REAC and surrounding pipelines (inlet, REAC tubes, outlet manifold) HP/LP separators Recycle Hydrogen lines
Delayed Coking Unit (DCU)	Fractionator OVHD section Coke drums blowdown system

The primary effect of NH₄Cl is deposition, which leads to fouling or plugging. This issue significantly impacts process operations by increasing pressure drops across the exchangers and disrupting heat flux. The secondary problem arises as a consequence of the first; when the solid deposit (which is virtually noncorrosive - if dry) becomes wet. In this scenario, the area beneath the deposit becomes “enriched” with Cl^- and H⁺ from the dissociation of NH₄Cl and water. As a result, under-deposit HCl corrosion is initiated, leading to the rapid degradation not only of carbon steel but also a wide range of corrosion resistant alloys (CRAs).

Ammonium Chloride Corrosion

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Carburization

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General Information

Carburization is a form of metallurgical failure/degradation commonly observed in environments containing carbon at elevated temperatures. This type of degradation is frequently associated with metals and alloys exposed to carburizing conditions, where carbon diffuses into the material at high temperatures, leading to the formation of carbides.¹ This process can compromise the material’s mechanical properties and structural integrity. Furthermore, it may escalate to metal dusting, particularly when carbon activity exceeds unity, resulting in highly localized carburization and causing catastrophic damage.² ⁴ Carburized steel tends to become brittle and may exhibit spalling or cracking .² Notably, carburization is of significant concern in industries such as refining, petrochemicals, and power generation.

CO₂ / H₂S Corrosion

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General Information

CO₂ corrosion in oil and gas production and transmission systems has been extensively studied over the last decades. The effects of various key parameters, such as temperature, pH, CO2 partial pressure and the presence of H₂S etc., have also been examined and, in many cases, these findings are used to assess and predict system corrosivity. The following chapter provides a general overview of CO₂/H₂S corrosion, the impact of these parameters and corrosion modelling approach.

Corrosion coupons

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General Info

The exposure of corrosion coupons is one of the oldest techniques for corrosion monitoring and, despite several drawbacks, it remains popular and widely used in various applications.

In the refining industry, coupons are mostly used in cooling water systems and overhead (OVHD) systems in crude distillation. Sometime they can also be used in amine units (various locations on rich and lean amine and regenerator OVHD), sour water (SW) strippers (mostly stripper OVHD), and other applications where multiphase, condensing systems with potential for deposition are encountered.

Corrosion Under Insulation

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General Information

Corrosion under insulation (CUI) stands out as a widely acknowledged issue across various industries; paradoxically, it remains one of the most inconspicuous challenges. This problem manifests beneath the layers of insulation, making it elusive and often undetected until substantial damage has occurred.

The primary driver of CUI is the presence of water – essentially, where there is no water, there is no CUI. Unfortunately, it is nearly impossible to prevent water ingress into the insulation. Even seemingly dry hot insulation systems may experience moisture ingress, for example, during equipment cooldown, physical damage to insulation jacketing, or joint caulk seal failures. The severity of Corrosion Under Insulation (CUI) is influenced by several factors, including the duration of moisture exposure, the insulation’s capacity to absorb and retain moisture, the cyclic nature of moisture, and the temperature of the substrate.¹ ² ³ ⁴ ⁵

Creep and Stress Rupture

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General Information

Under applied or internal stress and at elevated temperatures, the polycrystalline structure of metal tends to dislocate along the grain boundaries, resulting in the formation of grain boundary voids. These voids weaken the metal’s overall structure, leading to a reduction in its strain properties. This deterioration in mechanical properties can occur even when the stress levels are below the material’s elastic yield stress. The elastic yield stress is the point at which a material begins to deform plastically and will not return to its original shape when the applied stress is removed. When grain boundary voids form, the metal can no longer withstand the same level of stress without deforming, compromising its integrity and performance. Temperature plays a critical role in determining the creep rate, and below a specific level – which varies for different materials – it is generally assumed that creep will not progress, or its rate can be neglected. Table 1 shows some creep threshold temperatures for popular materials.¹

Crude Unit

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Atmospheric (Crude) Distillation Unit (CDU)

Corrosion monitoring in crude distillation units traditionally focuses on the atmospheric tower’s overhead section (OVHD). While there are no fixed guidelines specifying exact locations for corrosion monitoring, there is some consensus on key focus areas, such as the OVHD main line and cooler outlets. The proper assessment of monitoring locations and the number of monitoring points will depend primarily on the type of OVHD system, considering its operating regime (1-drum, 2-drums) and the cooler piping system (balanced, unbalanced). Below, you will find guidelines for monitoring locations based on generic OVHD system types: 1 drum – balanced coolers; 1 drum – unbalanced coolers and 2 drums – balanced coolers.

Electrical resistance (ER)

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General Info

Electrical Resistance (ER), along with corrosion coupons, is one of the oldest industrial corrosion monitoring techniques. However, the popularity of ER systems has diminished over the last decades in favor of non-intrusive, online ultrasonic thickness monitoring (UT). Nevertheless, ER still possesses certain advantages and, when used properly, can provide accurate and reliable information about process stream corrosivity.

Installation

Similar to LPR, the retractable system is also the most popular solution for installing ER probes in refining environments. The recommended mounting system consists a flange connection (see Figure 1). Threaded probe mounting, often using a 1" NPT nozzle, is not always recommended, as vibrations from process pipes or equipment can loosen the threaded connection .

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Flow Model

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Fundamentals of Flow Modeling

Understanding flow characterization is essential for predicting and assessing the corrosivity of systems. Over time, significant progress has been made in studying the relationship between flow dynamics and corrosion. To support these efforts, various flow models have been developed, each tailored to specific conditions. Among them, the single-phase flow model stands out for its simplicity and well-defined structure, making it a fundamental tool in flow characterization studies.

High Temperature H2-H2S Corrosion

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General Information

High-temperature H₂-H₂S corrosion represents a more aggressive form of traditional sulfidation. In this process, various sulfur species directly interact with the metal surface, forming corresponding sulfide scales. While H₂-H₂S corrosion also results in the formation of metal sulfide scales, the presence of hydrogen distorts this process, ultimately leading to higher corrosion rates compared to sulfidation without H₂. For details on sulfidation, please refer to the Sulfidation Chapter.

It is worth noting that H₂-H₂S corrosion has not been the subject of as extensive research as sulfidation without H₂. The primary investigations into H₂-H₂S corrosion were conducted over 50 years ago, leading to the formulation of what is known as the Couper-Gorman curves.¹ ² ³ These curves, following subsequent adjustments, establish correlations among H₂S concentration, temperature, and the corrosion rate of diverse materials. While the Couper-Gorman curves reasonably predict corrosion rates in specific scenarios, in others, particularly at very low H₂ concentrations, the predicted rates are lower than those observed in practical settings.⁶ ⁷

High Temperature H2/H2S Corrosion

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High Temperature Hydrogen Attack

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General Information

At high temperatures and elevated partial pressures, hydrogen can attack carbon and low-alloy steels by reacting with carbon and/or carbides to form methane. These reactions may occur either on the metal surface or within the metal lattice, leading to decarburization (surface reactions) and the formation of microcracks or blisters (internal reactions). Internal defects like cracks, blisters, or voids can significantly weaken the steel’s mechanical properties, potentially resulting in catastrophic failure. ¹ ^,²

Hydrochloric Acid Corrosion

Mon, 01 Jan 0001 00:00:00 +0000

General Information

Hydrochloric acid finds widespread use across various industries, serving as a crucial component in chemical manufacturing, food production, pharmaceuticals, rubber manufacturing, metal cleaning, and well activation (acidizing), among others. In the refining industry, HCl typically emerges as a by-product during the decomposition reactions of both inorganic and organic chlorides in the crude distillation process, impacting the integrity of the overhead (OVHD) section of the atmospheric distillation tower. Additionally, HCl is present in reforming and isomerization units where it either emanates from Cl-containing catalysts or forms during the regeneration of catalysts through the addition of chlorinated compounds. Moreover, HCl is also employed as a bulk chemical, serving as a neutralizing agent in tasks such as water treatment plants or within caustic treatment units.

Hydrochloric Acid Corrosion

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Hydrofluoric Acid Corrosion

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General Information

Hydrofluoric acid (HF) finds application in diverse industrial processes, serving as a crucial component in the production of fluorinated compounds. Moreover, it plays a key role in the electronics industry, where it is employed for the precision etching of glass and silicon. Additionally, HF is instrumental as a catalyst in specific chemical reactions, particularly in the alkylation process. The following chapter is mostly oriented to refining applications (alkylation), however some information is common for other process industries.

Hydrofluoric Acid Corrosion

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Hydroprocessing

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Corrosion Monitoring Hydroprocessing (hydrotreating/hydrocracking)

Corrosion monitoring in hydroprocessing units (such as hydrotreating and hydrocracking) is relatively uncommon. The core processes, hydrogenation and/or cracking, occur in a water-free environment at elevated temperatures, making typical uniform electrochemical corrosion unlikely. Corrosion generally takes place in the cooling-separation section of the unit and is often driven by the presence of alkaline sour water (ammonium bisulfide solution).

Common areas of corrosion include the reactor effluent air-cooler (REAC), sour water lines from cold separators, product strippers/stabilizers and fractionation. Even so, corrosion monitoring is not always recommended by process licensors, as proper design and material selection effectively mitigate the risks of elevated corrosiveness. When the concentrations of sulfur, nitrogen, and oxygenates in the hydroprocessing feed exceed the original design conditions, whether due to bio-feed co-processing or the use of high-sulfur side-cuts, corrosion can intensify and demanding stricter monitoring.

Linear Polarization Resistance (LPR)

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General Info

Linear Polarization Resistance (LPR) is a technique that provides near real-time corrosion measurements. Modern LPR technologies, which often incorporate additional electrochemical techniques (e.g., Harmonic Distortion Analysis or Electrochemical Noise) within a single instrument, can provide accurate monitoring not only in traditionally LPR-applicable systems like cooling water but also in more challenging environments such as sour water, lean amine, and even condensing overhead (OVHD). These modern LPR systems allow for measurement intervals as short as minutes, making it well-suited for online process-corrosion correlation.

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Naphthenic Acid Corrosion

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General Information

Historically, the term ’naphthenic acids’ referred to organic acids featuring saturated aliphatic rings with a carbon atom count ranging from 6 to 20, primarily found in crude oil and distillation side cuts. However, its definition has evolved to encompass all types of organic acids, including those with both saturated and unsaturated rings, some with structures containing up to 50 carbon atoms (see Figure 1). The molecular weight (MW) of these acids varies approximately from 100 to nearly 600-700 atomic units (au).

Napthenic Acid Corrosion

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Oil&Gas-Corrology

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Brief Summary of the Model

Corrosion due to the combined presence of carbon dioxide (CO₂) and hydrogen sulfide (H₂S) is a well-known challenge in oil and gas production and transmission systems. These acidic gases create an aggressive environment that can lead to severe degradation of commonly used carbon steel infrastructure. The corrosion resulting from these gases and associated contaminants poses a significant threat to the integrity of production and transmission equipment.

pH Model

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Background

Understanding in-situ pH is essential for assessing and managing corrosion in oil and gas systems. In simple CO₂-H₂O systems, pH is mainly controlled by CO₂ partial pressure.¹ ^- ³ A general relationship between pCO₂ and pH (at constant temperature) is presented in Figure 1.

Figure 1: Generic representation of pCO₂-pH relation. ^after ¹

As the corrosion reaction between iron and carbonate ions progresses, the pH of the fluid increases along with the concentrations of Fe²⁺ and CO₃²⁻ ions. When their solubility limit is exceeded, iron carbonate (FeCO₃) begins to precipitate, forming a protective layer on the steel surface, which can eventually reduce the corrosion reaction rate to some extent. The corrosion protection effectiveness of this layer depends on several factors, with pH, temperature, and ion concentrations being the most prominent.

Sour Water Stripping

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Corrosion Monitoring In Sour Water Stripping (SWS) Unit

Ammonium bisulfide corrosion (also known as alkaline sour water corrosion) is the primary damage mechanism and occurs in almost all parts of the SWS unit. However, its intensification is typically observed in the stripper’s overhead (OVHD) line and coolers, and rarely in the hot sour water (SW) feed line. In the stripper reboiler loop (if a reboiler is present), alkaline sour water corrosion is a rare phenomenon but may still occur depending on the unit’s operating regime and loading. Hot stripped sour water and cold sour water feed do not pose a serious corrosion threat.

Sulfidation

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Sulfidation (w/o H2)

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General Information

High temperature sulfidation, or simply sulfidation, results from reactions between various sulfur species and metallic materials, typically occurring at temperatures above 230°C (446°F). Sulfidation has been a presence in the refining industry since its inception; however, over the last 30 years, intensified processing of sour crudes has amplified the scale of the problem. Often exacerbated by naphthenic acid corrosion, sulfidation is considered a key and active damage mechanism that critically impacts refinery operations.

Sulfuric Acid Corrosion

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General Information

Sulfuric acid has been well-known for centuries, with the earliest documented information dating back to the Sumerian period (2000-3000 years BC). Its significance in modern times, particularly during the 19th and 20th centuries, led to numerous extensive studies on its chemical properties, such as reactivity in processes like electrophilic aromatic substitution, as well as its corrosion reactions with common construction materials such as carbon steel, stainless steels, and high chromium and molybdenum alloys.

Sulfuric Acid Corrosion

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Polythionic Acid Stress Corrosion Cracking

Mon, 01 Jan 0001 00:00:00 +0000

General Information

Polythionic Acid Stress Corrosion Cracking (PTASCC) is a form of intergranular cracking that requires coexistence of three elements: a susceptible material (e.g. sensitized austenitic stainless steels and some Ni alloys), presence of polythionic acids and stress.¹ ² Therefore, PTASCC occurs commonly in areas typically operating in range of 370-843°C (700-1550°F) where sensitization of austenitic materials will progress.² ³ ⁴

Polythionic acids, the second element, are typically formed during shutdown or process upset events when oxygen and water/moisture ingress may take place. Stress, the third necessary element for PTASCC and typically arises during cold and/or hot mechanical operations such as welding and bending. The interaction of these three elements is schematically shown in Figure 1.

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Stress Relaxation Cracking

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General Information

Interest in Stress Relaxation Cracking, sometimes referred to as Reheat Cracking, Stress Relief Cracking, or Strain Oxidation Cracking, began to rise approximately 20-30 years ago. This increase coincided with a growing number of “mysterious” failures observed in austenitic stainless steels and nickel alloys operating within theoretically safe temperature ranges. Failures of welded pipelines and equipment made from high-temperature stainless steels (such as 321ss - UNS S32100) or nickel alloys (such as 800H - UNS N08810), characterized by an intergranular cracking pattern, were often attributed to modes such as creep cracking assisted by oxidation.¹ ² ³ Studies by van Wortel and others have confirmed that the relaxation of accumulated stress, particularly in cold-worked areas such as bends or near welds’ Heat-Affected Zones (HAZ), aided by high temperatures (typically below the maximum service temperature limits for the given steel), is the primary driver for SRC.⁵

Diagnostics

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Unit Converter

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Remaining Service Life

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Amine Unit

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Reducing sulfur emissions is a crucial goal for every refinery, driven by stringent environmental regulations and the need to minimize air pollution. Hydrogen sulfide (H₂S), a significant contributor to sulfur emissions, is generated during various refining processes, including hydroprocessing and cracking. The amine unit serves as the primary stage for removing H₂S, along with other sulfur-containing compounds such as carbonyl sulfide (COS) and carbon disulfide (CS₂). Key areas prone to corrosion include equipment such as amine absorbers, regenerator columns with reboilers, heat exchangers, and associated piping, where exposure to hot, rich, and lean amine streams can initiate damage mechanisms. Proper material selection, continuous process monitoring, and effective chemical control are essential to mitigate these risks and ensure reliable operations.
#Amine Corrosion; #Corrosion Monitoring in Amine Units

Catalytic Reforming

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Catalytic reforming, in conjunction with Isomerization and Alkylation, plays a pivotal role in producing high-octane gasoline blends. Furthermore, hydrogen, a by-product of reforming reactions, holds significant importance in refinery hydrogen production, alongside steam reforming. Reformate, enriched with aromatic compounds, serves as the primary source for BTX (benzene-toluene-xylene) production. From a corrosion standpoint, catalytic reforming is generally regarded as a low-risk unit for corrosion-related issues. The typical damage mechanisms that may be present are associated with high-temperature operation and exposure to hydrogen e.g, Carburization or Stress Relaxation Cracking. In the low-temperature sections (fractionation), there is a potential for HCl Corrosion and NH₄Cl Corrosion.
#High Temperature Corrosion; #Metallurgical Failures; #HCl Corrosion; #NH₄Cl Corrosion

Caustic Treatment

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Caustic treatment, specifically Gasoline/LPG Sweetening using caustic, stands as a popular method for removing traces of H₂S and mercaptans from these process streams. Several variants of this process exist, with one of the most common involving caustic washing followed by catalytic oxidation of sulfides and thiosulfates, thereby returning regenerated caustic to the process. This chapter highlights key process parameters and areas prone to caustic-related corrosion.

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Crude Oil Distillation (CDU/VDU)

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The crude oil distillation unit, encompassing both atmospheric and vacuum sections, is one of the most critical process units in a refinery. With the increasing sulfur and acid content in processed crude slates, it becomes essential for the distillation unit to remain adaptable and flexible enough to handle a wide range of feedstocks. However, such variability in feed composition can exacerbate corrosion damage mechanisms, including sulfidation, naphthenic acid corrosion, and under-deposit corrosion, particularly in high-temperature zones such as furnace tubes, transfer lines, and vacuum resid sections. Additionally, areas such as column overhead lines and overhead condensers are susceptible to acidic corrosion caused by hydrogen chloride, or under-deposit corrosion originating from ammonium chloride or amine hydrochloride deposits.
#Corrosion Monitoring in CDU;#Sulfidation; #NAP Acid Corrosion; #HCl Corrosion; #NH₄Cl Corrosion

Delayed Coking Unit (DCU)

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Delayed coking, along with steam cracking, visbreaking, and thermal cracking, is a thermal refining process in which hydrocarbons are converted through thermally initiated radical reactions. Delayed coking primarily produces petroleum coke from heavy fractions, with gasoline and lighter fractions as by-products. As a downstream unit, the delayed coking unit (DCU) processes residual feedstocks from upstream refining. These feeds, which are rich in sulfur species, heavy metals (e.g., vanadium and nickel), olefins, and nitrogen compounds, tend to accumulate contaminants that exacerbate operational challenges and accelerate equipment degradation. In the high-temperature sections of the DCU, common damage mechanisms include creep, thermal fatigue, and temper embrittlement. Additionally, low-temperature areas, such as the overhead systems of the main fractionator, are prone to corrosion caused by sulfur or chloride compounds.
#High Temperature Corrosion; #Sulfidation; #HCl Corrosion; #NH₄Cl Corrosion

Fluid Catalytic Cracking (FCC)

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Fluid catalytic cracking (FCC) is one of the most pivotal catalytic processes in modern refineries. Fixed-bed catalytic cracking was developed in the early 20th century, while its fluidized-bed variant emerged later, gaining prominence in the 1950s. The FCC process exists in various forms, utilizing diverse catalysts and feedstocks, resulting in varying effluent compositions. Alongside crude distillation units (CDU), vacuum distillation units (VDU), hydrotreating, and catalytic reforming, FCC remains a cornerstone of modern refining operations. FCC units are subject to a variety of corrosion damage mechanisms. In the pre-heat section, sulfidation and naphthenic acid corrosion are prevalent due to the characteristics of the feedstocks. High-temperature sections are vulnerable to damage mechanisms such as creep, thermal stress cracking, and carburization. In the fractionation and wet gas compression sections, common corrosion challenges include carbonate stress corrosion cracking, wet-H₂S cracking, and ammonium bisulfide corrosion.
#High Temperature Corrosion; #Sulfidation;#NH₄HS Corrosion

HF Alkylation

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Utilizing hydrofluoric acid as the catalyst for alkylation constitutes the alternative method for producing high-octane hydrocarbon streams essential for gasoline blending. HF alkylation offers several advantages compared to sulfuric acid alkylation, such as reduced acid consumption and the absence of a refrigeration section required in the H₂SO₄ process to maintain lower process temperatures. However, the primary drawback of employing HF is associated with process safety due to its highly corrosive and toxic nature.
#HF Corrosion

Hydroprocessing

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Hydroprocessing, including hydrotreating and hydrocracking, accounts for nearly half of a refinery’s capacity. The main difference between them is feed conversion: hydrocracking converts up to 90%, while hydrotreating operates at 0.5–5% to preserve valuable feedstocks like gasoline. Hydroprocessing units face several corrosion risks. High-temperature H₂S/H₂ corrosion affects areas such as feed pre-heaters, reactor effluent systems, and recycle hydrogen streams. Before hydrogen injection, sulfidation can occur. Sour and acidic crude feedstocks increase the risk of naphthenic acid corrosion (NAC), while ammonium chloride and bisulfide corrosion are common in fractionation sections. Chlorides from recycled hydrogen and ammonia/H₂S in post-process streams contribute to these issues. Effective material selection, feed treatment, and corrosion monitoring are crucial for ensuring unit reliability.
#Corrosion Monitoring in Hydroprocessing; #NH₄HS Corrosion; #Sulfidation; #NAP Acid Corrosion; #NH₄Cl Corrosion .

Isomerization

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Isomerization, along with Catalytic Reforming and Alkylation, constitutes one of the processes used to enhance the octane number of gasoline by transforming straight-chain (n-paraffinic) hydrocarbons (C4-C6) into their branched (iso) counterparts. The isomerization unit operates within a relatively straightforward, hydrocarbon-dominant process environment, where HCl and caustic eventually act as the primary corrosive agents.

Unit Operation Description

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Sour Water Stripping (SWS)

Mon, 01 Jan 0001 00:00:00 +0000

Many refinery process units, such as crude distillation, Hydroprocessing, the amine unit, or delayed coking unit, generate sour wastewater streams that typically contain dissolved NH₃, H₂S, and NH₄HS. Proper treatment of these sour water streams is a crucial aspect of refinery water management. It enables the return of some water to the process, reducing the operational costs of water treatment plants and overall water consumption. The sour water stripping unit is particularly prone to issues such as Ammonium Bisulfide Corrosion and the phenomenon of Wet H₂S Cracking.
#NH₄HS Corrosion; #Corrosion Monitoring in SWS Units

Steam Reforming

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A modern refinery necessitates significant quantities of hydrogen to satisfy the growing demand for cleaner fuels, particularly in hydro-desulfurization processes. Conventional hydrogen sources, such as catalytic reforming, often fall short of meeting the required hydrogen volumes. Therefore, to offset this hydrogen deficit, the industry commonly adopts steam reforming as a supporting unit for hydrogen production. Steam reforming serves as the primary source of hydrogen, not only within the refining sector but also in petrochemical, automotive, and energy production industries. When used in energy or automotive contexts, it is commonly termed ‘brown’ hydrogen, while the term ‘grey’ is used when CO₂ from the process is captured and stored.

Sulfur Recovery Unit (SRU)

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Hydrogen sulfide (H₂S), along with other sulfur compounds such as COS, CS₂, etc., are byproducts from various refinery processes. Their removal and conversion into elemental sulfur, a valuable commercial product, is crucial not only for economic reasons but, more significantly, for environmental purposes. The sulfur recovery unit, specifically the Claus Sulfur Recovery Unit, assumes a pivotal role in a refinery’s sulfur management. Supported by additional units like tail-gas treating, it enables the refinery to adhere to the highest environmental standards concerning the emission of sulfur-containing gases.

Sulfuric Acid Alkylation

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Sulfuric acid alkylation represents one of the two common processes (second is HF alkylation) used in the refining industry to produce high-octane products for gasoline blending. This process involves the reaction of isobutane with olefins, primarily propylene or butylene, resulting in the formation of branched, long-chain paraffins. Alkylate boasts not only a high-octane number but also possesses a low vapor pressure, making it a highly valuable component in gasoline blending.
#H₂SO₄ Corrosion

Visbreaking Unit (VBU)

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Visbreaking is a mild, non-catalytical thermal cracking process, employed to treat high-viscosity products particularly vacuum residue, to produce lower-viscosity fractions. It’s important not to confuse Visbreaking with Thermal Cracking, which usually involves processing atmospheric residue at higher temperatures than Visbreaking, thereby intensifying cracking reactions.

Unit Operation Description

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About the Knowledge Library

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About the Knowledge Library

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