HOW TO REDUCE AMINE LOSSES
Ray Veldman COASTAL CHEMICAL CO., L.L.C. Houston, Texas
Presented at PETROENERGY 89 October 23 – 27, 1989
HOW TO REDUCE AMINE LOSSES
Amine unit operation with high amine losses is a very common problem which can often be solved with changes in operating practices or through minor modifications to existing equipment. High amine losses often result in additional operating costs other than amine replacement through poisoning of downstream catalysts and desiccants. The amine consumption figures should be recorded and monitored on a regular basis. The actual usage should then be compared to an optimum predicted usage rate determined by the following equation: Consumption (LBS/day) = 2 LBS/MMSCF (Total MMSCF through all gas absorbers) + .02 lbs/BBL (Total BBL/day through all liquid absorbers) This predicted amine consumption equation is based on actual consumption at several well designed amine systems which experience few upsets. It includes normal losses due to amine volatility, solubility, and entrainment. The equation accurately predicts amine losses in DEA and MDEA systems. For MEA, the predicted consumption should be multiplied by 1.5 to account for MEA’s higher volatility and reclaimer operation. If actual usage significantly exceeds predicted usage, then steps should be taken to reduce amine losses. Amine losses are generally controllable and can be minimized by good design and operation. The principal causes are amine carryover and system leaks. Carryover results from entrainment, foaming, and amine solubility in liquid hydrocarbons. Leaks can be minimized by reducing corrosion, proper pump seal maintenance, proper filter and reclaimer operation, and collection of amine into a designated amine recovery system. Amine Carryover The major cause of day to day amine loss is entrainment. Amine volatility losses do occur but are usually not significant. DEA and MDEA vapor pressure are extremely low and volatility losses in gas absorbers using these solvents are negligible. However, MEA vapor pressure is much higher and volatility losses in low pressure refinery fuel gas absorbers can average .5 pound MEA/MMSCF of gas treated. Table 1 lists vapor pressures of MEA, DEA, and MDEA at 110o F, a typical lean amine temperature.
TABLE 1 Vapor pressure and volatility losses at 110 o F Vapor pressure, psia MEA 2.04 x 103 5 DEA 2.63 x 10 MDEA 2.37 x 105
Volatility loss at 110 o F and 100 psia .447 LB/MMSCF (15% MEA) .016 LB/MMSCF (25% DEA) .026 LB/MMSCF (40% MDEA)
Volatility losses from the regenerator reflux accumulator should also be negligible since under normal operation; there will be very little amine in the reflux. By far, entrainment is a much more significant factor. Entrainment should average .5 pounds amine/MMSCF of gas treated in a properly designed absorber. However, entrainment of well over 3 LB/MMSCF is not uncommon. The best way to minimize entrainment is to design and operate amine absorbers at 60% or below of flooding velocities and to install demisters in properly sized sweet gas knock out drums. Entrainment of heavier hydrocarbon from upstream equipment is also a factor in controlling amine losses. These hydrocarbons promote foaming and can result in plugging of amine absorbers and regenerators. They are best removed by installing demisters in upstream sour gas knock out drums. Foaming is a typical cause of high amine losses. Foaming results from hydrocarbon contamination, high suspended solids, mechanical restrictions, or high amine circulation rates. Proper filtration reducing upstream hydrocarbon entrainment, and maintaining lean amine temperatures 10 to 15 o F hotter than the absorber inlet gas temperature usually minimized foaming. Good flash drum operation is also extremely important in controlling foaming. A flash drum should be sized for a 20 minute amine retention time and should have provisions for skimming of hydrocarbons. The amine unit should have both a mechanical filter for suspended solids removal and a carbon filter for hydrocarbon removal. Both filters should be on the lean amine with the mechanical filter upstream of the carbon filter. Rich amine mechanical filtration has also proved to be very beneficial. Amine rates to the filters should exceed 10% of total amine circulation. Provisions should also be made for antifoam injection into the rich amine feed to the regenerator or the regenerator reflux. Antifoam should only be injected when upsets are occurring or when they are expected due to upstream upsets. Amine foaming can also be reduced by periodically draining or continuously purging a small amount of the regenerator reflux drum to the sour water stripper. This will purge hydrocarbons, ammonia, and cyanides which accumulate in the reflux. In addition, an optimized amine unit with lower circulation rates will typically have fewer foaming problems than an unoptimized system. Lower amine circulation rates allow amine absorbers to operate at a lower percentage of flooding velocity. This minimizes the inherent foam tendency and also provides a longer residence time in the amine flash drum. It also reduces the amount of hydrocarbons sent to the sulfur plant. Liquid Contactors In liquid hydrocarbon amine contactors, both solubility and entrainment contribute to amine losses. Figure 1 shows MEA, DEA, and MDEA solubilities in saturated liquid hydrocarbons at different concentrations. Amine solubilities are higher in olefinic hydrocarbons by similar ratio to higher water solubilities in olefinic versus saturated hydrocarbons. Amine solubility does increase with amine strength, but a 20 wt% MEA solution results in the same amine solubility in the hydrocarbon, 17 ppmw, as a 35 wt% MDEA solution. DEA solubilities are about ½ those of MDEA. Solubility losses contribute to overall amine usage; however, with good liquid hydrocarbon-amine separation, combined solubility and entrainment losses should normally be around 100 ppmw in the treated hydrocarbon stream. Unfortunately, due to poor separation, amine concentration in the treated hydrocarbons often exceed 500 ppmw. Amine-hydrocarbon separation is improved by lowering amine viscosity, by increasing amine drop size at the inlet distributor, and by keeping amine and hydrocarbon velocities at steady rates. For good amine-hydrocarbon separation, the lean amine temperature should be controlled so that
the amine viscosity is around two centipoise or less at the amine-hydrocarbon interface. However, the lean amine temperature should not be increased beyond the vaporization temperature of the liquid hydrocarbons at the contactor operating pressure. Figure 2 shows MEA, DEA, and MDEA viscosities at different temperatures. Amine and hydrocarbons superficial velocities through inlet distributors and through the contactor are extremely important to separation. Generally, the lower the superficial velocity, the better the separation. High velocities result in amine-hydrocarbon emulsions which are very hard to separate. Distributors should be sized for hole velocities of one to two FT/sec and hydrocarbon superficial velocity 2 through the contactor should be less than 10 GPM/FT . Variations in flow also adversely effect separation because they disturb the amine-hydrocarbon interface and temporarily produce aminehydrocarbon emulsions. If possible, upstream process controllers should be tuned or changed to smooth out variations.
A downstream coalescer from the liquid contactor is advisable to recover amine carried over during upsets. The coalescer will also provide additional separation when the amine viscosity or amine distributor velocity is high. To reduce amine solubility, especially when operating with MEA or high concentrations of MDEA, a water injection upstream of the coalescer is recommended. The water spray effectively reduces the amine concentration and therefore reduces its solubility and viscosity. This greatly improves separation in the coalescer and minimizes the amine carryover to downstream units. The coalescer water phase can then be routed to the amine flash drum for amine recovery. Since fresh water is continually added to the unit to enhance recovery, a purge of the regenerator reflux, which as discussed before as being very beneficial, becomes necessary. The weak amine-water solution in the coalescer can also be recirculated through the water injection point to minimize water injection and improve contact.
Amine Leaks and Corrosion Amine unit leaks are not always found when visibly inspecting the equipment. Although flange and valve packing leaks are common, exchanger leaks from corrosion, and lack of or improper amine recovery from filters, pump seals, and the flash drum usually result in greater losses. Corrosion not only results in exchanger leaks, but also is a major source of amine contamination. Corrosion results in high suspended solids which tend to increase amine losses through more frequent filter changes and foaming. Corrosion is more common in the hot areas of the amine unit; however, corrosion due to stress corrosion cracking or from the presence of CO 2 initiated degradation products can be found throughout the unit. High amine acid gas loadings, poor amine regeneration and heat stable amine salts are primary causes of corrosion. Corrosion should be monitored through use of coupons and periodic equipment inspections. If the rich amine loading is too high in the absorber, the acid gas-amine equilibrium will be exceeded downstream when pressure is reduced and when the rich amine is heated in the leanrich exchanger. As this occurs, hot acid gas is released and is free to corrode the steel. The hot acid gas is also a second gas phase, to the rich amine liquid phase, so erosion due to the much higher velocities encountered with two phase flow becomes a major concern. If the lean amine loading is high, it is indicative of poor regeneration because hot corrosive acid gas is present in the reboiler.
Amine heat stable salts are usually formed from oxygen contamination or trace concentrations of acidic compounds in the feed to the amine units. Examples of these acidic compounds are sulfur dioxide, hydrogen cyanide, formic acid, acetic acid, and oxalic acid. Hydrogen cyanide is typically a major contributor to corrosion in the reflux condenser. If this is the case, continuous purging of a slip stream of the reflux to the sour water stripper will keep the cyanide concentration in check but a corrosion inhibitor may also be necessary. The organic acids are a major cause of corrosion in the reboiler. Reboiler temperatures are sufficient to cause the weak organic acid-amine salts to disassociate. The hot organic acid is then free to corrode the steel. As the amine cools when it leaves the reboiler the salt is reformed. Corrosion from the organic acids will usually be limited to the reboiler tubes and the bottom one or two trays of the regenerator. It is more predominant in thermosiphon reboilers or where the amine is being over stripped. A stainless steel reboiler tube bundle will resist the corrosion but the most effective way to deal with this type of corrosion is to prevent the acids from entering the amine unit. Corrosion from organic acids can be neutralized by reacting them with a stronger base than the amine to form a heat stable salt which does not disassociate in the reboiler. Corrosion resulting from CO2 initiated degradation products of MEA and DEA also frequently occurs in units operating with these solvents. MDEA is not degraded by CO2. The CO2 degradation products increase with higher CO 2 concentrations in the inlet gas and with higher MEA and DEA concentrations. MEA degrades to N-(2-hydroxyenthyl) ethylenediamine, HEED, which is corrosive at concentrations above 0.4%. DEA degrades to N-di (2-hydroxyenthyl) piperazine, HEP, which does not directly corrode the unit, but is believed to act as an iron chelator which could continually remove the passivating iron sulfide layer formed when H 2S reacts with steel. This results in more fresh steel being constantly exposed to H 2S to form iron sulfide. As the iron sulfide is swept away by the CO 2 initiated degradation products, more iron sulfide is formed and a gradual thinning of the steel occurs. Therefore, more iron sulfide must be removed through filtration and the foam tendency of the amine is greater due to the higher solids content. Solids, primarily iron sulfide, formed from corrosion can be a continuous source of amine contamination. The iron sulfide should be removed with mechanical filtration, but frequent filter changes or backflushing is a potential for high amine losses. Both the mechanical filter and the carbon filter should be drained to the amine sump for recovery before changing. Similarly, amine leaks from the amine flush to the pump seals on the lean and rich amine pumps should also always be diverted to the amine sump and not the plant sewer. Regular equipment inspections and maintenance should be undertaken to ensure proper operation of the amine recovery system. High amine losses are an indication that one or more problems exist in the unit. More often than not, the problems can be quickly identified and easily solved. Economic justification exists for reducing losses; therefore, amine loss control should become an integral part of amine unit operation. When carryover, corrosion and amine leaks are minimized, amine unit efficiency improves significantly.
HEAT STABLE SALTS
1.
OXYGEN IN FEED
2.
ACIDIC COMPOUNDS IN FEED A. B. C. D. E.
SULFUR DIOXIDE FORMIC ACID ACETIC ACID OXALIC ACID CYANIDE
CO2 DEGRADATION PRODUCTS
MEA HEED: N-2 (2-hydroxyethyl) – ethylenediamine Corrosive above 0.4% in solution DEA HEP: N, N-di-(2-hydroxyenthyl) – piperazine Exhibits iron chelating properties
