Corrosion Management in High-Pressure Heat Exchanger Tube Bundles for Heavy Oil Processing

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As the refining industry shifts its focus from fuel production to chemical feedstock production, heavy oil hydroprocessing units are playing an increasingly important role in upgrading petroleum products. Their operational stability directly affects refinery safety and economic performance. High-pressure heat exchangers are critical to heat recovery and transfer in these units, but their tube bundles operate under demanding conditions involving:

High temperatures and pressures

Hydrogen-rich atmospheres

Highly corrosive process media

Under these conditions, corrosion-induced tube bundle failures have become an increasingly serious concern. Such failures can reduce heat transfer efficiency and cause leakage, potentially leading to unplanned shutdowns or even safety incidents. Identifying the underlying corrosion mechanisms and establishing a systematic framework for corrosion prevention and control are therefore essential to effective equipment management. This article focuses on the tube bundles of high-pressure heat exchangers in heavy oil hydroprocessing units. It systematically examines their operating conditions, corrosion mechanisms, and protective measures, with the aim of providing practical guidance for ensuring their long-term, reliable operation.

Operating Conditions: The Harsh Environment Facing Heat Exchanger Tube Bundles

From a process engineering perspective, tube bundles in high-pressure heat exchangers used in heavy oil hydroprocessing units typically operate at pressures of 10–18 MPa and temperatures of 280–420 °C, creating a typical high-temperature, high-pressure, hydrogen-rich environment. The process media also contain a range of corrosive substances and impurities, including:

Active corrosive components, such as sulfur- and nitrogen-containing compounds in heavy oil feedstocks

Impurities, such as naphthenic acids, chlorides, and heavy metals

These substances, together with the high flow velocities of the process media, can cause continuous erosion and corrosion of the tube walls. In addition, heavy oil hydroprocessing reactions generate corrosive byproducts, including hydrogen sulfide (H₂S), ammonia (NH₃), and hydrogen nitride. These substances can react with water in the process stream to form corrosive environments, such as aqueous hydrogen sulfide and ammonium chloride solutions, further accelerating tube bundle corrosion.

Although commonly used tube bundle materials, including 20# carbon steel, 16MnR, and various grades of stainless steel, offer a certain degree of resistance to high temperatures and pressures, they remain susceptible to corrosion under the combined effects of these demanding operating conditions.

Mechanism Analysis: Four Types of Corrosion Affecting Heat Exchanger Tube Bundles

Corrosion in high-pressure heat exchanger tube bundles used in heavy oil hydroprocessing units involves several interacting mechanisms. The four main types are:

Wet hydrogen sulfide (H₂S) corrosion

Ammonium chloride under-deposit corrosion

Naphthenic acid corrosion

Erosion-corrosion

The occurrence and severity of these corrosion mechanisms depend on specific operating conditions, and their effects may interact or reinforce one another.

Wet H₂S corrosion is a major degradation mechanism, primarily caused by the presence of hydrogen sulfide and free water in the process medium. During hydroprocessing, organic sulfur compounds in the heavy oil feedstock are converted into hydrogen sulfide. Under fluctuating operating conditions, such as temperature variations, condensation of the process medium, or water ingress, a free-water film may form on the tube surfaces. Hydrogen sulfide then dissolves in this film, creating an acidic aqueous environment that attacks the tube walls.

During hydroprocessing, organic sulfur compounds in the heavy oil feedstock are converted into hydrogen sulfide. Under fluctuating operating conditions, such as temperature variations, condensation of the process medium, or water ingress, a free-water film may form on the tube surfaces. Hydrogen sulfide dissolves in this film, creating an acidic aqueous environment that corrodes the tube walls. Hydrogen ions generated during this process can enter the steel and diffuse toward grain boundaries or other microstructural defects, where they recombine to form molecular hydrogen. The resulting internal pressure can cause cracking.

In sulfide stress corrosion cracking (SSCC), the combined effects of tensile stress and an H₂S-containing environment can damage the protective iron sulfide film on the tube surface. The exposed metal may then undergo localized anodic dissolution, promoting crack initiation and propagation. Unlike general corrosion, SSCC can cause sudden and catastrophic failure, posing a significant threat to equipment integrity.

Ammonium chloride under-deposit corrosion is a typical form of localized corrosion that occurs beneath deposited salts. In hydroprocessing environments, organic chlorides in heavy oil feedstocks decompose to form hydrogen chloride (HCl), which reacts with ammonia generated during the process to produce ammonium chloride vapor. As the temperature decreases, the saturated vapor pressure of ammonium chloride also decreases. Consequently, when the high-temperature vapor enters the heat exchanger tube bundle and undergoes rapid cooling below the salt deposition temperature, ammonium chloride deposits form on the tube surfaces, creating a dense deposit layer.

The deposit layer isolates the tube surface from the bulk process stream, creating a localized, confined environment. Condensed water gradually accumulates beneath the deposits and dissolves the ammonium chloride, forming a highly concentrated and highly corrosive solution. This solution promotes sustained electrochemical attack on the tube material. In addition, the deposits impede the removal of corrosion products and restrict convective heat transfer, resulting in the accumulation of corrosion products and increased local hydrogen ion concentrations. These effects accelerate corrosion, leading to pitting and eventual perforation of the tube walls.

Salt deposition also reduces heat transfer efficiency and increases energy consumption. The combination of salt deposits and corrosion products is difficult to remove, further aggravating the corrosion process. This type of corrosion frequently occurs near the tube bundle baffles, with the tube-side inlet region being particularly susceptible to salt deposition and under-deposit corrosion.

Heavy oil also contains naphthenic acids, whose corrosivity increases with temperature. The high-temperature regions of the tube bundle, typically operating at 320–400 °C, are therefore particularly susceptible to naphthenic acid corrosion. This corrosion process involves two main mechanisms:

1. Direct chemical corrosion: Naphthenic acids react directly with metallic iron to form iron naphthenates, resulting in progressive tube wall thinning. Because iron naphthenates do not form a stable, protective film on the metal surface, they are readily carried away by the flowing process medium, exposing fresh metal to further corrosion.

2. Synergistic erosion-corrosion: At high flow velocities, the process medium continuously erodes the tube surfaces, damaging fragile oxide films and removing corrosion products formed by naphthenic acid attack. This exposes fresh metal to the corrosive medium, accelerating material loss through the combined effects of corrosion and erosion.

Severe naphthenic acid corrosion is characterized by elongated grooves and streamlined pits on metal surfaces. It typically occurs near tube bundle inlets, at elbows, and in regions of turbulent flow. The corrosion rate is closely related to the naphthenic acid content of the heavy oil, the flow velocity of the process medium, and the operating temperature. In stainless steel tubes, naphthenic acid corrosion may also cause intergranular attack, weakening the grain boundaries and compromising the mechanical integrity of the tubes.

Erosion-corrosion, a synergistic process involving both mechanical erosion and electrochemical corrosion, is a common degradation mechanism in heat exchanger tube bundles. Heavy oil process streams often contain small amounts of solid particles, such as catalyst fines and metallic corrosion products. Driven by high operating pressures, the process medium flows at high velocities through the tube bundles, carrying these particles, which continuously erode the tube walls. This process enhances the transport of corrosive species to the metal surfaces while removing protective corrosion product layers, thereby accelerating material degradation.

Damage to the oxide films and corrosion product layers exposes the underlying metal. The exposed areas act as anodes, while the surrounding intact surfaces serve as cathodes, promoting localized electrochemical corrosion. Meanwhile, corrosion pits alter the local flow field, potentially increasing flow velocities and further intensifying erosion-corrosion. This type of damage is particularly common in regions where the flow direction or velocity changes abruptly, such as tube bundle inlets and tube-to-tubesheet junctions. Continued material loss in these areas causes progressive tube wall thinning and may eventually lead to perforation.

Factor Coupling: The Driving Force Behind Accelerated Corrosion

Corrosion in heat exchanger tube bundles results from the combined effects of multiple interacting factors. These factors can be broadly classified into process conditions, process medium composition, and equipment-related factors. Their respective mechanisms of action and associated corrosion types are summarized in Table 1.

Table 1 Key Factors Influencing Corrosion in High-Pressure Heat Exchanger Tube Bundles Used in Heavy Oil Hydroprocessing

Precision Corrosion Prevention and Control: Establishing an End-to-End Management System

Source Control: Reducing Corrosive Components in the Process Medium

Source control is a key measure for mitigating corrosion in heat exchanger tube bundles. It focuses on reducing the concentrations of corrosive components in heavy oil feedstocks and reaction products, thereby minimizing corrosion risks at their source.

During production, raw material specifications must be strictly controlled. Heavy oil feedstock entering the facility should undergo pretreatment, including desulfurization, dechlorination, and deacidification, to ensure that it meets the following limits: sulfur content ≤ 1.0%, chlorine content ≤ 1 µg/g, and total acid number (TAN) ≤ 0.3 mg KOH/g.

Meanwhile, the hydroprocessing reaction should be optimized using intelligent control technologies to precisely regulate the reaction temperature, pressure, and hydrogen-to-oil ratio. This helps improve the extent of hydrogenation, reduce residual organic sulfur and chlorine compounds, suppress side reactions, and minimize the formation of corrosive byproducts.

Effective dehydration is also essential. Installing dehydration units at heat exchanger inlets and regularly removing free water from the system can prevent water films from forming on tube bundle surfaces, thereby reducing the conditions that promote corrosion associated with nitrogen compounds and salt deposits. In addition, the targeted use of high-efficiency desulfurizing and dechlorinating agents during feedstock pretreatment can further improve the removal of corrosive components. Strict control of solid impurities in the feedstock also helps reduce erosion and wear of the tube bundles caused by particles carried in the process stream.

Material Upgrading: Selecting Corrosion-Resistant Materials

Given the varying operating conditions and corrosion mechanisms affecting different heat exchanger components, materials must be carefully selected to suit their specific service environments. In low-temperature zones susceptible to wet hydrogen sulfide (H₂S) corrosion, HIC-resistant carbon steels such as 20R and 16MnDR can be used. By strictly controlling the contents of elements such as sulfur and phosphorus, these materials achieve improved grain-boundary purity, thereby enhancing their resistance to hydrogen-induced cracking (HIC) and sulfide stress corrosion cracking (SSCC).

In high-temperature zones susceptible to naphthenic acid corrosion or ammonium chloride under-deposit corrosion, stainless steels such as 316L and 2205 duplex stainless steel are suitable options. The chromium and nickel in these alloys promote the formation of a protective passive film on the metal surface, improving resistance to pitting and intergranular corrosion. 2205 duplex stainless steel, in particular, combines high corrosion resistance with high mechanical strength, making it suitable for high-temperature, high-pressure environments where erosion-corrosion is a concern.

For areas exposed to particularly severe corrosive conditions, nickel-based alloys such as Inconel 625 may be considered. These alloys offer good resistance to naphthenic acid and hydrogen sulfide corrosion, making them suitable for environments with high total acid numbers (TANs) and high H₂S concentrations. However, their high procurement costs should be taken into account when evaluating their application.

Process Optimization: Preventing Conditions That Lead to Corrosion

Process optimization focuses on adjusting operating parameters and equipment design to avoid conditions that promote corrosion. Strategies include reducing the concentration of corrosive agents, minimizing the duration of stress on tube bundles, and lowering the intensity of corrosion-promoting factors. Effective temperature control within the operating system is essential. The surface temperature of the tube bundles must be kept outside the ammonium chloride deposition range. This can be achieved by precisely controlling the inlet and outlet temperatures of the heat exchanger to prevent ammonium chloride vapor from depositing on the tube surfaces. In addition, temperatures in high-temperature zones should be adjusted to a range in which the materials are less susceptible to naphthenic acid corrosion, thereby mitigating its effects. The flow velocity of the process medium should also be controlled by optimizing the tube bundle diameter and the number of tube passes, and strictly maintained within the range of 1.0–1.5 m/s. This ensures efficient heat transfer while keeping the flow velocity sufficiently low to prevent excessive erosion-corrosion.

Equipment Optimization and Maintenance: Reducing Corrosion Risks

Optimize the equipment structure by rounding off sharp transitions in the flow path, particularly at tube bundle inlets and outlets and around baffles, to reduce turbulence and fouling. In addition, install anti-erosion baffles within the tube passes to protect tube bundle inlets from solid particle impact, thereby reducing the risk of erosion-corrosion. Regular descaling should also be performed using methods such as chemical cleaning or high-pressure water jetting to remove ammonium chloride deposits and corrosion products from tube bundle surfaces and prevent the progression of under-deposit corrosion. The cleaning frequency should be determined based on changes in heat transfer efficiency and corrosion monitoring data. Furthermore, an optimized online ammonia and water injection system should be implemented. Precise ammonia injection adjusts the pH of the process medium to help mitigate hydrogen sulfide-induced corrosion, while controlled water injection reduces ammonium chloride salt saturation and minimizes salt deposition. Together, these measures enable dynamic process optimization and real-time corrosion risk management.

Surface Protection: Strengthening the Corrosion-Resistant Barrier on Tube Bundles

Surface protection involves forming a protective barrier on the substrate to isolate it from the process medium. This approach is suitable for both corrosion-protection retrofits of existing equipment and the protection of new equipment. Common surface protection methods include coatings, diffusion coatings, and linings. In practice, tube bundle surfaces must be thoroughly prepared, typically by sandblasting to the Sa 2.5 cleanliness grade, to remove rust, oxide scale, and oil. Proper surface preparation ensures strong adhesion between the protective layer and the substrate, preventing defects such as blistering and delamination caused by surface contamination. For applications requiring high-temperature and corrosion resistance, ceramic-resin composite coatings are a suitable option. These coatings combine the adhesive properties of resin with the corrosion resistance of ceramic materials. They are applied by high-pressure airless spraying, with the coating thickness controlled within 200–300 μm to ensure uniform coverage. After curing, the coating adhesion must be tested, and the component can be put into service only after passing inspection.

For aluminum-chromium diffusion treatment, a vacuum diffusion process is used to form a dense alloyed layer 50–100 μm thick on the tube bundle surfaces, improving their resistance to erosion and naphthenic acid corrosion under high-temperature operating conditions. For stainless steel lining, thin-walled 316L stainless steel is bonded to the carbon steel substrate through a combination of mechanical expansion and welding. This ensures adequate bond strength for high-pressure service while preventing process media from becoming trapped in gaps, which could otherwise lead to crevice corrosion. In areas particularly susceptible to corrosion, such as inlets, outlets, and contact points with baffle plates, a multilayer reinforcement strategy is adopted, combining substrate upgrades with protective surface coatings. In addition, a quality traceability system is established for surface protection, with clearly defined construction procedures, inspection standards, and assigned responsibilities to ensure the proper implementation of protective measures.

Operations and Maintenance (O&M) Control: Establishing a Full-Lifecycle Corrosion Monitoring System

A full-lifecycle monitoring and refined management approach is adopted to ensure the early detection and timely remediation of corrosion-related issues. A comprehensive corrosion monitoring system is established, with corrosion probes and ultrasonic thickness gauges installed at vulnerable locations in the tube bundles. These instruments provide real-time data on corrosion rates and wall thickness, which are integrated into the Distributed Control System (DCS). The system automatically triggers an alert if the corrosion rate exceeds 0.1 mm/year or the wall thickness falls below a specified limit. O&M personnel are also required to conduct regular equipment inspections, including endoscopic examinations of the tube walls every 1–2 years and pressure tests to identify defects such as cracks and corrosion damage. Minor defects should be repaired promptly, while severely damaged components should be replaced.

In addition, O&M records should be improved to include information on tube bundle materials, protective treatments, operating parameters, corrosion monitoring results, and routine maintenance activities. These records provide a basis for optimizing future corrosion protection strategies. Professional training for O&M personnel should also be strengthened to improve their understanding of corrosion mechanisms and protective measures. Furthermore, operating procedures for corrosion protection and daily production should be standardized to prevent improper practices that could increase the risk of tube bundle corrosion. Emergency response plans should also be developed for critical incidents, such as severe corrosion and tube bundle leakage. These plans should clearly define response procedures, repair protocols, and material reserve requirements to minimize potential losses resulting from corrosion-related failures.