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Jan-2014

HCN in amine systems

HCN has far reaching effects on amine system performance. After hydrocarbon contamination, its presence is one of the primary reasons refinery amine systems suffer from accelerated corrosion, operability, and reliability problems.

Ralph H Weiland, Clayton E Jones and Nathan A Hatcher
Optimized Gas Treating, Inc.

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Article Summary

When HCN enters the amine system, its hydrolysis produces ammonia and formate, a heat stable salt (HSS) anion. Reaction of HCN with oxygen and H2S generates another heat stable salt, thiocyanate. Accelerated corrosion leads to faster formation of particulate iron sulphide, which in turn leads to filter element plugging, fouled equipment, lower capacity, and more stable foams.

In this article, mass transfer rate-based simulation is used to study HCN ingress and accumulation in amine systems in unprecedented detail. Following discussions of the chemistry, the incursion and accumulation tendencies for HCN in amine systems are quantified.

Background and Context

Over any substantial period of operation, amine systems operated in refineries can be expected to show increasing buildup of heat stable salts. This is especially pronounced for units that scrub gases primarily from coking and catalytic cracking units, where the heat stable salts consist primarily of formate (HCOO–) and thiocyanate (SCN–). Amine systems treating gases from various sources experience different rates of HSS accumulation. The actual rate of HSS anion buildup depends upon the incursion rate of HCN into the amine system. The primary sources of HSSs are summarised in Table 1 from which a direct chemistry link between HCN, and the common HSS anions formate and thiocyanate is apparent. These two HSS anions tend to dominate in refinery amine systems, which makes the importance of HCN in amine systems somewhat more obvious.

If left unchecked, buildup of heat stable salts eventually permanently neutralises part of the amine by protonation and results in loss of treating solution capacity. This is the primary acute symptom. HSSs are also known to complex iron ion and accelerate corrosion in the hot, lean section of the amine unit. When the complexed iron contacts higher concentrations of H2S in the absorber, iron sulphide precipitates. These particles can foul equipment and stabilise foam, leading to loss of hydraulic capacity, so the operator usually resorts to trading these costs for the cost of replacing filter elements. The costs of equipment failure vary with the failure mode. They are also highly site specific, and the timing of the lost production can matter significantly. In general, lost profit from unplanned equipment failure can be expected to dwarf filter costs. It is unfortunate, however, that costs such as these are often ignored from the economic planning process because the costs are difficult to quantify with certainty. The industry is generally not forthcoming with reporting minor mishaps because there is little business incentive to be open about potentially embarrassing operating episodes or revealing mistakes that can amount to significant competitive advantages when solved.

Hydrogen cyanide, HCN, is a byproduct of cracking the heavier fractions of crude oil in a refinery (either thermally as in a coker, or catalytically as in a Fluid Catalytic Cracker). The gas oil (boiling point 750°F/399°C+) and heavier fractions tend to have greater concentrations of nitrogen than the diesel and lighter fractions. These processes break up the larger nitrogen-containing molecules at high temperatures and low hydrogen partial pressure conditions that may not be as conducive to complete conversion of byproduct molecules such as HCN to ammonia as in a high pressure hydrotreater or hydrocracker.

Thus, HCN occurs quite naturally in refineries and has many sources. Some processes are high producers; others do not seem to produce HCN at all. Once produced, HCN finds its way into the amine system with the H2S-containing gases. It is useful to note that HCN forms in various processes within the refinery; whereas, HSSs form in the amine system. Once in the amine system then, various conditions and the presence of other contaminants allow the HCN to convert into HSS anions. An ounce of prevention is worth a pound of cure — the most obvious way to prevent HSS anion formation in amine systems is to prevent the ingress of HCN in the first instance. This can be a lot more difficult to achieve than might appear at first blush. For example, one approach that has been tried repeatedly by many refiners is water washing the raw gas and sending the wash water to a sour water stripper (SWS). However, this approach seems invariably to fail — the amine system still continues to experience buildup of HSS anions during its operation. Water washing has been addressed in some detail by Weiland et al. (2013) and is not examined further here.

The Disposition of HCN in Amine Systems
If steps are not taken to remove HCN from the sour gas prior to entering the amine system, or if the degree of removal achieved is inadequate, the amine contactor will absorb much of the HCN into the solvent, and allow the rest to escape with the treated gas. Figure 1 is a schematic of the amine system with flash tank and flash gas reabsorber, and the recirculating water wash scheme mentioned above. Table 2 shows the Raw Gas analysis (Stream 24), with 100 ppmv HCN and 1,000 ppmv ammonia.

With a wash water Makeup rate (Stream 25) of 5 gpm, and the wash water recycle (Stream 31) set at 100 gpm, some HCN and substantial ammonia removal can be achieved. The composition of the washed gas (Stream 26) going to the amine unit is shown in Table 3.

The treated gas (Stream 3) from the amine contactor is simulated to contain only 6.2 ppmv H2S, 1.9 ppmv HCN, and 0.47 ppmv ammonia. Essentially 98.3% of the HCN is removed by the 995 gpm solvent flow. Apart from only 0.002% of the absorbed HCN which is lost in the flash gas from the reabsorber, the remainder travels through to the amine regenerator. It is in the regenerator that HCN and ammonia exhibit some interesting and surprising behaviour.

The specifics used for simulating the regenerator are as follows: the regenerator is a 4.5-ft diameter valve-tray column with rich amine feed to the 4th tray from the top (Tray 4) and with the first three trays single pass and the bottom 20 trays of a 2-pass design. The solvent flows to the regenerator (13 psig top pressure) at 1,012 gpm and enters at 215°F. The reboiler consumes 50,000 lb/h of 50 psig saturated steam (0.82 lb/gal). This corresponds to a molar stripping ratio of 0.842 (moles water vapour per mole of total acid gas in the overhead vapour line). This results in lean amine loadings of 0.00060 and 0.00055 moles of H2S and HCN, respectively, per mole of MDEA with just 0.00015 wt% ammonia.

Acid gas to the SRU is 94.8% H2S (wet basis) with 645 ppmv HCN and 23 ppmv ammonia. Most of the ammonia in the overhead vapour (Stream 11) ends up in the reflux condensate (Stream 1) and, of the total condensate, 80% is blown down and added to the refinery sour water system. The resulting 17 gpm of blow-down (Stream 28) contains 170 ppmw HCN, 1,950 ppmw ammonia, and 8,750 ppmw H2S and is sent to the sour water system. However, the most interesting aspect of occurrences in the regenerator is not its overall performance; rather, it’s the way ammonia and HCN distribute themselves internally across the trays in the column itself.


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