Gas 2025 Issue

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

T he removal of hydrogen sulphide (H₂S) and carbon dioxide (CO₂) from natural gas and other hydrocar- bon 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 concen- trations of acid gases (H₂S and CO₂) to meet environmental standards, improve gas quality, and protect downstream equipment. However, despite its importance, several oper- ational 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 try- ing 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 com- position or concentration in the amine or feed stream being treated can easily upset the process, causing severe opera- tional issues and inadequate amine treatment. Upgrading off-spec condensate A facility located in South Texas is responsible for the col- lection 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 trans- fer 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 process- ing 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 cop- per 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

O-gas dehydration

Off-gas to pipeline

Waste gas to flare/vent

Off-gas

Sulfagard

Υ-grade product

O-spec condensate storage

Liquid truck to L ive O ak

Truck unloading

Υ-grade to pipeline

Amine treating

Stabilisation

9# RVP product

9# RVP to truck

9# RVP storage

Truck loading

Amine r egeneration

Figure 1 Block flow diagram of facility

Gas 2025