In USA tight oil production, H2S remediation begins at the wellhead, where associated gas is released from the well, captured, processed and fed into pipelines for transmission to natural gas processing centers. Maximum allowable H2S content of the gas fed into transmission systems is 2 ppm. This limitation poses a challenge to wells that contain high levels of H2S. There are two technologies that are in common use at the wellhead: adsorbers, such as Schlumberger’s ferric oxide granules in lead/lag cylinders, and absorbers, such as the Ecolab Ultrafab® system that utilizes a liquid triazine scavenger. Adsorbers have high capital expenditures (capex) and high operating expense (opex), require significant maintenance, and have pressure/heat parameters that limit its suitability. Absorbers, have moderate capex, high opex, moderate maintenance requirements, but have disposal and logistical issues, and cannot operate in temperatures below 8°C. These systems also are limited in economics (in the USA) to less than 0.2% H2S content. Large scale H2S removal/disposition can be achieved using amine-based absorber systems combined with the Claus system, which converts H2S into sulfur and water. Amine solvent systems have high capex, moderate opex, but only capture the H2S, and the resultant gas must be neutralized. Refineries use Claus sulfur recovery systems, which have very high capex and high maintenance costs. Claus systems are not economical below the refinery scale level.