Apr-2025

Resolving FeS contamination and poor filtration in a liquid treating system

Efficient operation of amine treating systems allows maximised throughput of off-specification condensate.

Nicholas Brownrigg Howard Energy Partners
Orbie Harris IV Transcend Solutions, LLC

Article Summary

The removal of hydrogen sulphide (H₂S) and carbon dioxide (CO₂) from natural gas and other hydrocarbon streams is a crucial process known by various names such as gas sweetening, acid gas removal, or amine gas treating. The process’s intent is to reduce the concentrations of acid gases (H₂S and CO₂) to meet environmental standards, improve gas quality, and protect downstream equipment. However, despite its importance, several operational issues can complicate the efficient operation of amine treating systems.

Foaming, iron sulphide (FeS) contamination, erosion- corrosion, improper loading, or amine carryover are a few of the issues that operators are confronted with when trying to maintain an optimised amine treating system that allows maximised throughput. The amine treatment process requires strict adherence to maintain a delicate chemistry and purity balance to work as intended. A change in composition or concentration in the amine or feed stream being treated can easily upset the process, causing severe operational issues and inadequate amine treatment.

Upgrading off-spec condensate
A facility located in South Texas is responsible for the collection and processing of off-specification condensate and other hydrocarbon liquids to a 9 psi Reid Vapor Pressure (RVP) product and a Y-grade product that utilises an amine treatment process before reaching custody transfer to the pipeline. The facility is designed with a process capacity of 10,000 bpd of inlet condensate (see Figure 1). The amine system is designed to handle 7,000 bpd of natural gas liquid (NGL) and has a design amine flow rate of 20 gpm.

Truckloads of off-specification condensate are received daily from sources throughout South Texas. Each truckload arrives at the facility at different H₂S concentrations and chemicals contaminations (methanol, oil field chemicals). This off-specification condensate feed produces a varying amount of 9 psi RVP product and NGL depending on inlet condensate composition.

During the first few years of initial start-up and operation, the facility operated both with or without limited use of the amine treating unit. Feedstock was delivered to the facility and required only stabilisation before processing, with the end product meeting all pipeline specifications.

The facility began to see a commercial need for processing feed with higher concentrations of contaminants, H₂S, and CO₂. At that time, the unit was brought into service and operated without major operational issues for several years.

In 2018, the facility began to experience copper strip corrosion test failures, the passing of which is required to meet Y-grade pipeline specifications. With intermittent copper strip corrosion test failures, the facility was confronted with the prospect of being shut off from its Y-grade product pipeline. This would have led to lost revenue and created a bottleneck for upstream producers supplying the facility with off-specification condensate feed.

The facility initially attempted to resolve the issue by switching to a different grade of amine. The process was designed to use a diethanolamine (DEA)-based amine and opted to switch to a formulated amine solvent which selectively removes H2S. The facility believed it was receiving unaccounted for mercaptans species, which were ultimately leading to the copper strip corrosion test failure. Operating with the new amine, the facility had few issues until December 2022.

At this time, a technical service team was onsite to advise on a path forward to help with the copper strip corrosion test failures. The recommendation was to drain the water from the reflux drum on the overhead of the amine still tower and replace it with fresh water to the system. The system did see improvements from this recommendation; each time the reflux drum was drained, the copper strip test passed, and the operational issues in the amine still subsided. However, these gains in performance were temporary, with the operational issues reappearing around five to seven days after the draining of the reflux drum. At this time, operations noted the appearance of black debris in the sight glasses on spent elements. Also, the pre-carbon bed filter housing was full of a stable foam, and the rich and lean amine became a dark amber to brown colour (see Figure 2).

The source of the black debris was unknown at this time, but the facility determined that a shutdown would be required to fully clean the amine still. This led to a month of operation without any issues or failures of the copper strip corrosion test. However, operations soon reported that the previous operational challenges had returned, and the amine still was once again filled with black debris (see Figure 3).

The facility began a full troubleshooting campaign that ultimately concluded that the source of the black material was most likely FeS created during the reaction between the amine and H₂S present in liquid NGL. In this process, the sulphur ions released from H₂S during the reaction with the amine solvent react with the iron ions present in the steel used in the piping and vessels of the amine system to form FeS solid particulates.

In many treating systems, these FeS particles form on the sides of vessels and piping in the amine system, creating a protective layer against corrosion. However, if the velocities of fluid moving through the vessels/piping are high enough, the FeS particles can be washed away or not allowed to deposit. This causes them to circulate throughout the system, contaminating amine and leaving the steel prone to potential sulphur corrosion. The facility’s team concluded that one of two issues was occurring in the system:
- Foaming in the amine still led to improper regeneration of the amine and a failure to properly treat H₂S in the amine contactor, ultimately leading to a failed copper strip corrosion test.
- Foaming in the amine contactor led to the carryover of rich amine into the downstream treated NGL. The downstream NGL filter, which is designed to remove trace amounts of amine, was being overwhelmed with amine volumes exceeding design, leading to a failed copper strip corrosion test due to high concentrations of rich amine in the NGL post-filtration.
At that time, the facility requested assistance with system diagnostics and recommendations for its filtrations and separation challenges.

System evaluation
Once onsite, Transcend Solutions collected samples of the solid black debris from the facility’s amine system, as well as several of the spent pre-carbon filter elements. The solids and elements collected underwent a variety of tests at Transcend’s lab to determine their composition.

A solvency test, magnetic separation test, scanning electron microscopy (SEM, see Figure 4), and energy dispersive X-ray spectroscopy (EDS, see Figure 5) were performed to help determine the composition of the unknown material in the system. The solvency test and magnetic separation test indicated that the samples were inorganic and had an affinity for a magnetic source. However, the SEM and EDS  analyses concluded that the sample was a form of ferrous sulphide with an elemental composition of sulphur (S) and iron (Fe) at atomic percentages of 66.3% and 33.7%, respectively. The SEM analysis indicated that the amine contained particles ranging in size from 2 microns to greater than 10 microns.