Amine treaters

As with membrane systans, installation of a good filtration system for pre-treatment of the inlet gas has become one of the key components of amine system design. They can remove particulates and take out heavy hydrocarbons that enter with the feed gas. The cleaner an amine system is the better it operates. This should be coupled with regular chemical analysis of the amine solution to ensure proper control of the plant operation and resolve operational problems before they impact performance [17]. 

Amine systems are established technology that is readily available with a proven track record. Incremental improvements over the years in the amine chemistry, design of the contactors and improved process schemes have raised the bar for membrane systems to compete. But higher CO2 concentrations favour membrane systems since in amine treaters in order to remove more CO2 one needs more amine solution. In contrast, when membranes see higher CO2 contents they permeate higher CO2 content. This joins with simpler (even unattended) operations, lower maintenance and operating costs, and smaller foot prints as factors in favour of membrane systems. 

Membrane systems do not have to compete with amine treaters but instead can complement them by cutting high CO2 levels down to levels more compatible with amine treaters. The long-term operations of combined membrane and amine systems by NATCO [14] and Air Liquide [15] are examples of this hybrid process. 

---

LPG/amine treaters can have significant amine losses. Veldman (1989) states that amine losses for well designed and operated LPG treaters due to amine entrainment and solubility amount to about 0.02 lb of amine per barrel of LPG treated. Washing the LPG with a dilute amine-water solution removes entrained amine from the LPG and reduces the concentratian of amine dissolved in the LPG because amine in the hydrocarbon phase establishes equilibrium with the dilute water wash phase. Figure 2-96 includes a typical water wash system. 

Amine Tail Gas Treating. The use of the SulFerox process for amine tail gas treating is described by Pirtle (1991). The plant is a grassroots installation processing up to 6 MMscfd of wellhead gas at 7SO-8SO psig. The sour gas to the amine treater contains about 4,000 ppmv H2S, 730 ppmv mercaptans, and 200 ppmv organic sulfur compounds (RSSR, RSR, etc.). The amine treater uses an MDEA (methyldiethanolamine) based solvent. The acid gas from the amine treater is the feed to the SulFerox unit. It contains 46 mol% H2S, 3.S mol% mercaptans, and 630 ppmv of other sulfur compounds. 

Stream Amine Treater Amine Treater Amine Treater SulFerox Unit Acid Gas Regenerator Air... 

ComponmT— Amine Treater SulFerox Contactor Incitidiite Spent Air as Unrecovered ... 

SOx Transfer Additives. Arguably, SOx transfer additives are the most cost-effective way to lower SOx emissions in an FCC unit. These materials, first developed by Davison Chemical, react with SOx in the FCC regenerator to form sulfates Figure 25). When the sulfated additive circulates to the riser/reactor section, the sulfate is reduced to H2S, which is recovered by amine absorption and sent to the sulfur plant. In some units, these additives reduce FCC SOx emissions by more than 70%. Consequently, if a pre-treater or post-treater still must be installed, its size can be reduced. 

Using amine as the continuous phase also increases the LPG treater amine residence time and provides mote time for the operator to intervene if the interface level controller fails. This minimizes the chance of hydrocarbon breakthrough causing a major sulfur plant upset... 

The development of rigorous design methods for LPG treaters has been hampered by the lack of liquid-liquid equilibrium (LLE) data for amines and sour hydrocarbon liquids. Early designs were based on empirical rules of thumb and field experience with existing units operating under similar conditions. 

Amine-type liquid hydrocarbon treaters can be designed to remove both HjS and COS efficiendy, but mercaptans, which are much weaker acids than H2S, do not react significantly with amines. Howev, they can be made to react with stronger alkalies, such as sodium hydroxide. 

Although almost all LPG treaters have amine as the continuous phase with the interface controller above the top bed, some have LPG as the continuous phase with the interface below the bottom bed of packing. With the interface at the bottom, the amine is dispersed above each bed. Strigle (1994) describes LPG contactor internals for this interface control arrangement. 

Per Table 3-8, the recommended size of the slipstream filtered by activated carbon varies from 1% to 100% (full flow filtration). Early activated amine filters built in the 1970s were often designed for a 1 to 2% amine solution slipstream. Experience demonstrated that these filters were undersized, and most activated carbon filters are now designed for a 10 to 20% slipstream (Bourke and Mazzoni, 1989). However, in some applications, e.g., Claus plant tail gas treaters, activated carbon filters may be designed for full flow filtration. Typical activated carbon bed life is about 6 months to a year. 

Bright R. L., and Leister, D. A., 1987, Gas treaters need clean amines, Hydro. Process., December, pp. 157-158. 

---