Mitigating corrosion with a digital twin
Data-driven engineering helps engineers to identify ways to improve predictions of corrosion. Processing plants depend on assorted metallic equipment and pipelines.
Rodolfo Tellez-Schmill, KBC (A Yokogawa Company)
Ezequiel Vicent, OLI Systems Inc.
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However, like most things, metal does not last forever. It eventually dwindles through corrosion due to water, oxygen, extreme temperature changes, and acidity. It is necessary to take measures to manage corrosion or accept that whatever relies on the metal structure will eventually fail.
The total economic cost of corrosion is massive. NACE estimates the global cost to be 3.4% of global gross domestic product, or $2.5 trillion.1 Approximately 50% of this comprises the direct cost of corrosion — materials and equipment needing repair, maintenance, and replacement, and the services to deal with them. The remainder includes the effects of corrosion, such as environmental damage, waste of resources, loss of production, or personal injury.
Corrosion in oil refining
A typical oil refinery has several process vessels, fractionation towers, miles of horizontal and vertical pipelines, and a large number of shell/tube exchangers and air coolers. Many of these pipelines are inaccessible due to their height or coverings such as insulation, cement, soil, mud, or water. This makes corrosion a major consideration for safe, reliable, and profitable operations.
Controlling the corrosion of oil refining equipment and pipeline systems is complex. Key areas for anti-corrosion measures are composition and phase state, viscosity, flow regime, temperature, pressure, and proper equipment selection to mitigate risk.
In general, engineers can minimise corrosion if they limit variations in operating conditions. However, the industry’s need to frequently change the crude oil or raw materials it processes makes this difficult, if not impossible. Changes in composition, processing, and flow rate through process equipment and piping lead to different distributions and varying degrees of corrosion.
Implementing a corrosion management plan can reduce operating costs and corrective measures. Proper corrosion control measures can help to improve the performance of many operating units (for instance, reducing atmospheric column operating pressures or increasing distillate yields) and possibly reduce the need for heat exchanger bundle changes. Reducing unexpected shutdowns during a refinery’s turnaround schedule would allow the plant to meet and exceed targeted profits.
Embrace the science
KBC and OLI joined forces to create a solution that helps operators manage and mitigate corrosion risk. Combining the Petro-SIM process simulation platform with OLI Alliance Engine electrolyte and water chemistry simulation software creates a digital twin for a broad range of downstream applications to prevent and mitigate corrosion.
Creating a digital twin strengthens a plant’s corrosion management plan by giving process and production engineers total stream properties at their fingertips, including pure as well as pseudo-stream components, covering both ionic and non-ionic systems.
Engineers can determine the current state of corrosion, manage chemical additives management, and assist in proper equipment selection. This delivers enhanced model fidelity and engineering efficiency for holistic measurement, prediction, and mitigation of corrosion, scaling, and fouling in aqueous environments.
Petro-SIM’s open architecture collects real-time operations data from the site historian. It then delivers virtual representations of hydrocarbon molecule transformation and associated plant operating conditions. The digital twin provides a single source of the truth for what is going on inside the plant at a molecular and asset level.
Distillation units and the preheat train
The presence of acids and chlorides in the atmospheric distillation unit (CDU) and vacuum distillation unit (VDU) overhead systems can cause corrosion. Some crude oil physical properties, such as total acid number (TAN), total sulphur content, water, and chlorides are carefully monitored. If they exceed allowable limits, corrosion can be a problem.
With changeable crude diets and throughput rates, corrosion in the CDU and VDU vary over time. This can create overhead corrosion hot spots, changing their severity and location. As increased equipment replacement and repairs become necessary, reliability and availability decrease.
To counter this, chemical injection may be effective. Corrosion inhibitors, neutraliser chemicals, or in some instances wash water are useful in controlling corrosion. However, engineers must avoid over-dosing.
Corrosion inhibitor injections can result in sodium contamination of heavier products from the distillation unit. In addition, excess injection of inhibitor may cause formation of inhibitor-related salts on the overhead section of the column.This can affect downstream units such as the coker and visbreaker. Other mitigation measures might also include material selection, protective coating, and cathodic protection.
The primary objective of hydrotreating processes is to remove sulphur and other impurities, such as nitrogen, oxygen, halides, and trace metals. These impurities may contribute toward regulatory emissions, catalyst deactivation, or product specification limits. These processes can take the form of a naphtha hydrotreater, middle distillate hydrotreater, diesel oil deep desulphurisation (hydrofining), or residue hydrotreating. However, proper functioning of hydrotreating units depends on the unit’s feed/effluent exchangers, reactor effluent air cooler (REAC), and associated downstream units. Reactors convert sulphur, chloride, and nitrogen compounds in feedstock to hydrogen sulphide, hydrogen chloride, and ammonia, respectively.
When operating at high pressures and low temperatures, the precipitation of ammonium bisulphide (NH4HS) and ammonium chloride (NH4Cl) in the reactor effluent stream occurs. This results in accelerated corrosion processes around the feed/effluent exchangers and REAC welds, leading to loss of primary containment and, potentially, fires. Hence, water injection upstream from the REAC is necessary to avoid NH4HS and NH4Cl condensation and formation of crystalline solids, which can corrode the REAC. As a result, the hydrotreater REAC is a corrosion hotspot. Several corrosion-related incidents have occurred across the refining industry involving the rupture of air cooler tubes.
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