Spartan Energy and UCC Dry Sorbent Injection (UCC DSI) have worked together over the last two years to develop a novel, cost-effective solution to reducing sulfur dioxide emissions associated with the oxidization of hydrogen sulfide (H2S) extracted from a natural gas stream using an amine system. Emissions of H2S from a natural gas production facility are typically highly regulated by state environmental agencies and the Environmental Protection Agency. In large enough quantities, hydrogen sulfide must be oxidized - through the use of a flare or thermal oxidizer - and converted into sulfur dioxide (SO2). Various permitting requirements exist depending upon the amount of SO2 emissions. These permits can be costly and can require a significant amount of time (in some cases, greater than 18 months) to obtain. Using the Dry Sorbent Injection (DSI) process can reduce emissions of SO2 by up to 90%. The Spartan/UCC DSI developed process incorporates a traditional amine unit, a thermal oxidizer, and a dry sorbent injection system to remove SO2. Amine units and thermal oxidizers are widely used in the oil and gas industry. Dry sorbent injection is widely used in the power generation industry as a way to control emission of pollutants. The process works as follows: 1. The H2S acid gas is produced from the regeneration column of the amine plant. 2. The H2S acid gas is oxidized in a thermal oxidizer to convert the H2S into SO2. 3. The SO2 is then cooled and fed into a mixing duct where it is mixed with a dry sorbent such as sodium bicarbonate, trona, or others. 4. The sorbent reacts with the SO2 to form a solid byproduct, which is then routed to a filtration system. 5. The filtration system captures the spent sorbent and collects it in a bulk handling system. 6. Once captured, the spent sorbent can be hauled off-site for disposal. This process was developed for high H2S applications, with limited access to sour gas infrastructure, as a way to minimize pollution and reduce costs associated with chemical scavengers. Applications have been identified in shale plays in Texas and Louisiana. The combination of amine treating and DSI represents a middle ground between high variable cost/low fixed cost chemical scavenger solutions and high fixed cost/low variable cost Claus and liquid redox processes. A cost analysis will be presented to compare these options.
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