PTQ Q3 2024 Issue

updated over the years. In 2023, the National Environment Protection (Ambient Air Quality) Measure standards for SO 2 were set at 0.10 parts per million (ppm) for one hour of exposure and 0.02 ppm for 24 hours of exposure. In April 2024, the EPA proposed replacing the current secondary SO 2 standard with a new annual secondary standard of 10-15 parts per billion (ppb). Technology solutions Companies requiring sulphur removal solutions have a vari- ety of technology solutions available that can support their goals whether this is for liquid or gas treating. Each type of treatment offers different benefits and options. Liquids treating is done predominantly to remove H₂S, RSH, and COS. Some options such as hydrotreating will remove addi- tional contaminants. Hydrotreating is a process for refining crude petroleum and producing transport fuels. In this process, a high vol- ume of hydrogen gas is used to remove harmful impurities. As part of the hydrotreating process, sulphur is added to activate the catalyst, which then converts heavy organic sulphur in the oil into H₂S, ending up primarily in the gas phase. The H₂S is then removed by amine contacting and sent to a sulphur recovery unit (SRU). Although very effec - tive at removing heavy organic sulphur, hydrotreating is energy intensive, requires a considerable capital invest- ment, and generates higher operating costs than other treatment options. Liquid treating Removing sulphur is required for liquid-phase renewables and downstream, midstream, and petrochemical products. Sulphur species must be removed from a broad range of products before they can be considered saleable. LNG, nat - ural gas liquids (NGL), gasoline, kerosene, and diesel are some of the streams that require treatment. Each of the fuels has differing specification requirements for treating to ensure products meet pipeline and product/sales specifica - tions or other requirements, such as when the product is an intermediate feedstock and downstream catalysts must be protected. Caustic treatment to remove impurities has been around for more than a century and has been used since the begin- ning of oil processing. Initial treatment involved heavy mixing of the stream to be treated with caustic, which supported the removal of the sulphur impurities. However, this method often caused significant caustic carryover into the product stream. Over time, technology solutions were developed to improve both the mixing of the streams and product specification attainment and minimise the carryover of the caustic, which can cause issues in downstream equipment or storage. These solutions have continued to be developed, and current versions involve trayed towers, settling vessels, fibre-packed contactors, and additional downstream treat - ment options, including water washes, sand filters, and other items to ensure the product has little to no caustic carryover. There are advantages to using caustic treating over hydrotreating, which include: • Extractive caustic treating requires significantly less

capital (90% less than hydrotreating) and no hydrogen plus minimal operating costs (95% less than hydrotreating). • Extractive caustic treating does not remove or saturate olefins. Valuable octane is maintained, while the octane loss can be as high as 12 numbers in the case of hydrotreating. • Caustic discarded from extractive treating is typically small in volume and can be neutralised on site and then processed in the refinery wastewater treating system or sent to companies specialising in sulphidic caustic disposal. Typical caustic extraction formulas include:

RSH + NaOH –––> RSNa + H₂O H₂S + 2 NaOH –––> Na2S + 2 H₂O

The caustic used in extracting the mercaptans can be easily regenerated, greatly reducing the cost and use of the caustic. An oxidation catalyst, typically sold by the licensor, is required to speed up the regeneration at low tempera- tures. The following oxidation/regeneration reaction drives the sodium mercaptide (RSNa) to disulphide oil (RSSR), which can be scrubbed from the caustic using a hydrocarbon stream or settled out and removed via a settling vessel:

2 RSNa + 1/2 O2 + 2 H2O catalyst RSSR + 2 NaOH + H2 O ––>

Gas treating Gas treatment to remove sulphur can be done in a variety of ways, depending on the quantity of sulphur in the stream. Gas treatment to remove mercaptans is similar to the procees used for liquids treating, as discussed previously. Several dif- ferent options are available for gas treatment, some of which can be licensed and some of which are open art. At lower levels of H₂S, typical solutions include using a either a liquid scavenger, a packed adsorbent, or an absor - bent bed, any of which can remove the H₂S. Typically, these methods have higher operating costs but lower capital costs, and this solution works well at the lower levels of H₂S. These solutions can be used in a variety of industries where this makes the most sense – typically upstream, midstream, and renewables applications. Adsorbents are usually the least expensive capital solution but are not regenerable. The user should be prepared for several operational issues involved with solid adsorbents. They require frequent material changeouts, which involve personnel risks due to potential exposure to H₂S or material dust and, in some cases, potential fire hazards from pyrophoric materials. Liquid scavengers are readily available and highly useful at lower H₂S levels. Numerous processes are used for the appli - cation of scavengers, including atomisers, contact towers, pump-through designs, closed loop, and downhole appli- cations. Each has its pros and cons. Liquid scavengers can provide successful treatment in a wide range of applications: • H₂S removal from gas streams. • H₂S removal from sour hydrocarbon liquids (condensate and NGL streams). • H₂S reduction in sour liquid tank vapour spaces. The downside of using some liquid scavengers is that they may solidify as they spend. A significant odour is also

PTQ Q3 2024