The objective of the Amine Treating Unit is to remove H2S, CO2 and mercaptan compounds from various gas streams, such as recycled gas in hydrotreating and hydrocracking processes, hydrogen plant feed, and fuel gas systems. The H2S recovered is used as feed for the Sulfur Recovery Unit (SRU). Gas containing hydrogen sulfide (H2S) is generated as a result of the hydrotreating process. Amine is used for selective removal of H2S often referred to as "Acid Gas."

Acid gas is introduced to the bottom of the absorber (contact tower) while an amine/water combination is introduced at the upper section of the contactor. As the streams circulate and come into contact with one another, the amine removes the acid gas by absorption. The rich amine is then fractionated to separate and remove the hydrogen sulfide. The lean amine, which is stripped of the hydrogen sulfide, is recycled back to the contact tower.

Commonly used as Feed Preparation Units for downstream Catalytic Processes. Hydrotreating Processes remove impurities such as Sulfur and Nitrogen from Distillate Fuels (Naphtha, Kerosene and Diesel) by treating the feed with Hydrogen at an elevated temperature and pressure in the presence of a catalyst. Hydrotreating has been extended in recent years to atmospheric residuals to reduce the sulfur and metal content of residuals for producing low sulfur fuel oils. The principal impurities removed by this unit are Sulfur, Nitrogen, Oxygen, Olefins, Aromatics, Halogens, and Metals.

All Catalytic Processes such as CCR (Catalytic Reforming), HCU (Hydrocracker Unit), FCC (Fluid Catalytic Cracking), ISOM (Isomerization), ALKY (Alkylation) need the feed to be treated in a Hydrotreater.

The objective of a Glycol (TEG) Dehydration system is to remove water (H2O) from Natural Gas. Natural Gas typically contains a high concentration of water. Water in the gas stream can cause many issues if not removed shortly after being withdrawn from the well bore. Without dehydration, dissolved water can drop out of the gas phase forming free water causing upsets, fouling, and corrosion in downstream process equipment. Depending on the gas composition, dissolved water mixed with the gas can form hydrates at varying pressures and temperatures plugging off equipment and causing costly failures. To protect against these potential issues, most customers require the water moisture content not to exceed 7 lbs/MMscf.