Oil & Gas Refining on Knowledge Library

Amine Unit

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

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

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

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

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

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.

Unit Operation Description

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Crude Oil Distillation (CDU/VDU)

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

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)

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

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)

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

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

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

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

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

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

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

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

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

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)

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

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

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

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)

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

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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