Wet H₂S corrosion occurs when hydrogen sulfide is present in a process stream together with free water, creating a highly aggressive sour environment capable of rapid metal loss. In this condition, carbon steel and even some corrosion resistant alloys can suffer accelerated degradation through localized pitting, crevice corrosion, and general metal wastage.
Why Wet H2S Corrosion Becomes a Serious Integrity Risk in Operating Assets
In oil and gas facilities, wet H₂S corrosion is commonly described as sour environment corrosion or H₂S sour service. These terms refer to the same operating reality. The presence of water enables acid gas reactions at the metal surface, dramatically increasing corrosion rates compared to dry H₂S service.
Wet H₂S corrosion is particularly damaging because it often manifests as localized attack rather than uniform thinning. This makes early detection difficult and significantly increases the risk of pressure boundary failure if the corrosion mechanism is not brought under control.
IGS technician applying HVTS high-alloy cladding to a sour water stripper shell to prevent H₂S and NH₃ corrosion attack during an unplanned shutdown.
Where Wet H2S Corrosion Occurs in Oil and Gas Facilities
Wet H₂S corrosion affects a wide range of upstream, midstream, and downstream assets wherever sour fluids are processed under elevated temperature and pressure conditions.
Commonly affected equipment includes:
Upstream separator vessels handling multiphase hydrocarbon streams with produced water
Slug catchers exposed to two-phase or slug flow regimes
Amine absorbers and regeneration columns
Amine stripper columns and reboiler sections
Bottom shells, inlet nozzles, manways, and circumferential welds
These assets often operate continuously and are critical to production. Any unscheduled outage caused by sour service corrosion can result in major operational and financial consequences.
Corrosion Mechanisms in Sour H2S Service
In sour environments, corrosion is driven by a combination of chemical and operational factors. The presence of water allows H₂S and CO₂ to form corrosive acids at the metal surface. Elevated temperatures accelerate these reactions, increasing corrosion rates and severity.
In amine systems, corrosion is frequently associated with acid gas breakout, particularly in high-temperature zones such as the bottom of regeneration columns and reboilers. Areas not fully wetted by amine solution may be attacked by water vapor and acidic condensates, leading to localized pitting beneath trays and around inlet nozzles.
In upstream and offshore equipment, wet H₂S corrosion commonly affects liquid zones, bottom shells, drain nozzles, and weld seams. Two-phase flow, flashing, high velocities, and design features that promote turbulence further intensify localized attack.
The result is often deep pitting that rapidly consumes corrosion allowance and threatens vessel integrity.
Why Wet H2S Corrosion Is Difficult to Control
Traditional corrosion mitigation strategies are frequently ineffective in wet H₂S service.
Organic coating systems are often unsuitable due to temperature limitations, chemical incompatibility, and poor long-term durability in sour environments. Weld overlay and component replacement introduce significant operational challenges, including long lead times, extended shutdowns, and the need for post weld heat treatment.
In sour service, PWHT requirements under applicable standards create additional complexity. Performing weld repairs on large pressure vessels may require structural support, cranes, and prolonged outages, all of which increase cost and production risk.
For many operators, the challenge is not simply repairing existing damage, but preventing further metal loss while maintaining safe operation and production continuity.
Proven Mitigation of Wet H2S Corrosion Using HVTS
A proven approach to controlling wet H₂S corrosion is to upgrade the internal metallurgy of the affected asset rather than relying on barrier coatings or structural rebuilds.
High Velocity Thermal Spray technology enables the application of high nobility corrosion resistant alloys directly onto existing carbon steel surfaces in situ. This metallurgical upgrade creates a dense, low-permeability corrosion barrier capable of withstanding aggressive sour service conditions.
Key characteristics of this approach include:
In-situ application without the need for post weld heat treatment
Minimal impact on turnaround schedules
No heat affected zones
Compatibility with high temperature and pressure service
Long-term inspection and verification capability
This approach is particularly effective where asset replacement or weld overlay is impractical due to cost, schedule, or operational constraints.
IGS Experience in Wet H2S and Sour Service Corrosion Control
Wet H2S Corrosion in an Amine Regeneration Column
During a scheduled shutdown inspection at an NGL plant, severe localized corrosion was discovered in the lower section of an MDEA amine regeneration column fabricated from carbon steel. Pitting up to 2.3 mm deep was identified beneath trays, with significant wall thickness reduction.
The root cause was traced to tube failure in an upstream reboiler, which resulted in localized acid gas attack where the reboiler feed entered the column. A third-party fitness for service engineering analysis confirmed the column remained within allowable limits but required immediate corrosion control to prevent further metal loss.
Internal view of an amine stripper column following HVTS application, showing a uniform corrosion-resistant metal alloy upgrade to protect the substrate.
A bespoke corrosion resistant alloy was applied by IGS using High Velocity Thermal Spray to freeze the existing condition without PWHT. After multiple years in service, repeat inspections confirmed that wall thickness remained unchanged. The solution eliminated the need for column replacement and avoided an extended shutdown, delivering combined capital and operational savings of approximately $40 million.
At a large gas plant processing sour gas, corrosion developed in the amine stripper column shortly after commissioning. HVTS cladding was selected to protect the internal surfaces of the column under aggressive sour service conditions.
The project was executed in two phases. Area from Tray 1 to 7 was protected in 2014, followed by area from tray 7 to 18 and reboiler vapor line inlet nozzles in 2020. Inspections conducted in 2020 and 2024 confirmed that both application phases remained intact and in excellent condition.
After ten years in service, the cladding demonstrated sustained protection with thickness measurements within specification. This long-term evaluation validated the reliability of HVTS technology for wet H2S corrosion control in amine stripper service.
On an offshore production platform, slug catchers handling oil, gas, and produced water exhibited pitting corrosion in the original 316 stainless steel weld overlay. The temperature and pressure conditions precluded the use of polymeric coatings, and vessel replacement was not viable.
High Velocity Thermal Spray was selected as an alternative to a second weld overlay, enabling the internal surfaces to be protected within the original turnaround schedule. Small bore nozzles were simultaneously protected using automated bore welding procedures designed to avoid PWHT.
Subsequent inspections after two and four years of service showed no evidence of corrosion, blistering, or delamination. The project was completed without extending the shutdown and established a repeatable solution for similar offshore sour service applications.
An upstream separator vessel experienced deep pitting corrosion up to 8 mm in the bottom shell, circumferential welds, drain nozzles, and manholes. The corrosion was caused by an acidic process feed containing hydrocarbons, water, and H₂S at elevated temperatures.
IGS HVTS technology was applied in situ to upgrade the internal metallurgy of the vessel, protecting both shell areas and selected nozzles. The project was executed during the COVID-19 pandemic under full quality control compliance.
Inspection after three years in service confirmed that the H₂S corrosion mechanism had been permanently mitigated, with no new corrosion or metal loss observed. Following this validation, the asset owner adopted HVTS as a standard solution for similar high temperature acidic environments.
Why Asset Owners Rely on IGS for Sour Service Corrosion Control
Across upstream, offshore, and downstream facilities, IGS has demonstrated the ability to permanently arrest wet H₂S corrosion in mission-critical assets. The combination of metallurgical expertise, in-situ application capability, and long-term inspection data provides asset owners with confidence in both performance and execution.
By freezing existing corrosion conditions and preventing further metal loss, this approach extends asset life, reduces maintenance scope, and minimizes production risk in some of the most aggressive operating environments in oil and gas processing.
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