HOW TO REDUCE AMINE LOSSES

Ray Veldman

COASTAL CHEMICAL CO., L.L.C.Houston, Texas

Presented atPETROENERGY 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 besolved 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 throughpoisoning of downstream catalysts and desiccants. The amine consumption figures should berecorded and monitored on a regular basis. The actual usage should then be compared to anoptimum 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 welldesigned amine systems which experience few upsets. It includes normal losses due to aminevolatility, solubility, and entrainment. The equation accurately predicts amine losses in DEA andMDEA systems. For MEA, the predicted consumption should be multiplied by 1.5 to account forMEA’s higher volatility and reclaimer operation.

If actual usage significantly exceeds predicted usage, then steps should be taken to reduce aminelosses. Amine losses are generally controllable and can be minimized by good design andoperation. The principal causes are amine carryover and system leaks. Carryover results fromentrainment, foaming, and amine solubility in liquid hydrocarbons. Leaks can be minimized byreducing corrosion, proper pump seal maintenance, proper filter and reclaimer operation, andcollection 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 areusually not significant. DEA and MDEA vapor pressure are extremely low and volatility lossesin gas absorbers using these solvents are negligible. However, MEA vapor pressure is muchhigher and volatility losses in low pressure refinery fuel gas absorbers can average .5 poundMEA/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 110o F

Vapor pressure, psia Volatility loss at 110o F and 100 psia

MEA 2.04 x 103 .447 LB/MMSCF (15% MEA) DEA 2.63 x 105 .016 LB/MMSCF (25% DEA) MDEA 2.37 x 105 .026 LB/MMSCF (40% MDEA)

Volatility losses from the regenerator reflux accumulator should also be negligible since undernormal operation; there will be very little amine in the reflux. By far, entrainment is a much moresignificant factor. Entrainment should average .5 pounds amine/MMSCF of gas treated in aproperly 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 belowof 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 controllingamine losses. These hydrocarbons promote foaming and can result in plugging of amineabsorbers and regenerators. They are best removed by installing demisters in upstream sour gasknock out drums.

Foaming is a typical cause of high amine losses. Foaming results from hydrocarboncontamination, high suspended solids, mechanical restrictions, or high amine circulation rates.Proper filtration reducing upstream hydrocarbon entrainment, and maintaining lean aminetemperatures 10 to 15o F hotter than the absorber inlet gas temperature usually minimizedfoaming. Good flash drum operation is also extremely important in controlling foaming. A flashdrum should be sized for a 20 minute amine retention time and should have provisions forskimming of hydrocarbons. The amine unit should have both a mechanical filter for suspendedsolids removal and a carbon filter for hydrocarbon removal. Both filters should be on the leanamine with the mechanical filter upstream of the carbon filter. Rich amine mechanical filtrationhas also proved to be very beneficial. Amine rates to the filters should exceed 10% of total aminecirculation. Provisions should also be made for antifoam injection into the rich amine feed to theregenerator or the regenerator reflux.

Antifoam should only be injected when upsets are occurring or when they are expected due toupstream upsets. Amine foaming can also be reduced by periodically draining or continuouslypurging a small amount of the regenerator reflux drum to the sour water stripper. This will purgehydrocarbons, ammonia, and cyanides which accumulate in the reflux. In addition, an optimizedamine unit with lower circulation rates will typically have fewer foaming problems than anunoptimized system. Lower amine circulation rates allow amine absorbers to operate at a lowerpercentage of flooding velocity. This minimizes the inherent foam tendency and also provides alonger residence time in the amine flash drum. It also reduces the amount of hydrocarbons sent tothe sulfur plant.

Liquid Contactors

In liquid hydrocarbon amine contactors, both solubility and entrainment contribute to aminelosses. Figure 1 shows MEA, DEA, and MDEA solubilities in saturated liquid hydrocarbons atdifferent concentrations. Amine solubilities are higher in olefinic hydrocarbons by similar ratioto higher water solubilities in olefinic versus saturated hydrocarbons. Amine solubility doesincrease with amine strength, but a 20 wt% MEA solution results in the same amine solubility inthe hydrocarbon, 17 ppmw, as a 35 wt% MDEA solution. DEA solubilities are about ½ those ofMDEA. Solubility losses contribute to overall amine usage; however, with good liquidhydrocarbon-amine separation, combined solubility and entrainment losses should normally bearound 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 aminedrop 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 vaporizationtemperature of the liquid hydrocarbons at the contactor operating pressure. Figure 2 shows MEA,DEA, and MDEA viscosities at different temperatures. Amine and hydrocarbons superficialvelocities through inlet distributors and through the contactor are extremely important toseparation. Generally, the lower the superficial velocity, the better the separation. Highvelocities result in amine-hydrocarbon emulsions which are very hard to separate. Distributorsshould be sized for hole velocities of one to two FT/sec and hydrocarbon superficial velocitythrough the contactor should be less than 10 GPM/FT2. Variations in flow also adversely effectseparation because they disturb the amine-hydrocarbon interface and temporarily produce amine-hydrocarbon emulsions. If possible, upstream process controllers should be tuned or changed tosmooth out variations.

A downstream coalescer from the liquid contactor is advisable to recover amine carried overduring upsets. The coalescer will also provide additional separation when the amine viscosity oramine distributor velocity is high. To reduce amine solubility, especially when operating withMEA or high concentrations of MDEA, a water injection upstream of the coalescer isrecommended. The water spray effectively reduces the amine concentration and thereforereduces its solubility and viscosity. This greatly improves separation in the coalescer andminimizes the amine carryover to downstream units. The coalescer water phase can then berouted to the amine flash drum for amine recovery. Since fresh water is continually added to theunit to enhance recovery, a purge of the regenerator reflux, which as discussed before as beingvery beneficial, becomes necessary. The weak amine-water solution in the coalescer can also berecirculated 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 flangeand valve packing leaks are common, exchanger leaks from corrosion, and lack of or improperamine 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 morefrequent filter changes and foaming. Corrosion is more common in the hot areas of the amineunit; however, corrosion due to stress corrosion cracking or from the presence of CO2 initiateddegradation products can be found throughout the unit. High amine acid gas loadings, pooramine regeneration and heat stable amine salts are primary causes of corrosion. Corrosion shouldbe 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 beexceeded downstream when pressure is reduced and when the rich amine is heated in the lean-rich exchanger. As this occurs, hot acid gas is released and is free to corrode the steel. The hotacid gas is also a second gas phase, to the rich amine liquid phase, so erosion due to the muchhigher velocities encountered with two phase flow becomes a major concern. If the lean amineloading is high, it is indicative of poor regeneration because hot corrosive acid gas is present inthe reboiler.

Amine heat stable salts are usually formed from oxygen contamination or trace concentrations ofacidic compounds in the feed to the amine units. Examples of these acidic compounds are sulfurdioxide, hydrogen cyanide, formic acid, acetic acid, and oxalic acid. Hydrogen cyanide istypically a major contributor to corrosion in the reflux condenser. If this is the case, continuouspurging of a slip stream of the reflux to the sour water stripper will keep the cyanideconcentration in check but a corrosion inhibitor may also be necessary. The organic acids are amajor cause of corrosion in the reboiler. Reboiler temperatures are sufficient to cause the weakorganic acid-amine salts to disassociate. The hot organic acid is then free to corrode the steel. Asthe amine cools when it leaves the reboiler the salt is reformed. Corrosion from the organic acidswill usually be limited to the reboiler tubes and the bottom one or two trays of the regenerator. Itis more predominant in thermosiphon reboilers or where the amine is being over stripped. Astainless steel reboiler tube bundle will resist the corrosion but the most effective way to deal withthis type of corrosion is to prevent the acids from entering the amine unit. Corrosion fromorganic acids can be neutralized by reacting them with a stronger base than the amine to form aheat stable salt which does not disassociate in the reboiler.

Corrosion resulting from CO2 initiated degradation products of MEA and DEA also frequentlyoccurs in units operating with these solvents. MDEA is not degraded by CO2. The CO2

degradation products increase with higher CO2 concentrations in the inlet gas and with higherMEA 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 ironchelator which could continually remove the passivating iron sulfide layer formed when H2Sreacts with steel. This results in more fresh steel being constantly exposed to H2S to form ironsulfide. As the iron sulfide is swept away by the CO2 initiated degradation products, more ironsulfide is formed and a gradual thinning of the steel occurs. Therefore, more iron sulfide must beremoved through filtration and the foam tendency of the amine is greater due to the higher solidscontent.

Solids, primarily iron sulfide, formed from corrosion can be a continuous source of aminecontamination. The iron sulfide should be removed with mechanical filtration, but frequent filterchanges or backflushing is a potential for high amine losses. Both the mechanical filter and thecarbon filter should be drained to the amine sump for recovery before changing. Similarly, amineleaks from the amine flush to the pump seals on the lean and rich amine pumps should alsoalways be diverted to the amine sump and not the plant sewer. Regular equipment inspectionsand 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 thannot, the problems can be quickly identified and easily solved. Economic justification exists forreducing losses; therefore, amine loss control should become an integral part of amine unitoperation. When carryover, corrosion and amine leaks are minimized, amine unit efficiencyimproves significantly.

HEAT STABLE SALTS

1. OXYGEN IN FEED

2. ACIDIC COMPOUNDS IN FEED

A. SULFUR DIOXIDEB. FORMIC ACIDC. ACETIC ACIDD. OXALIC ACIDE. CYANIDE

CO2 DEGRADATION PRODUCTS

MEAHEED: N-2 (2-hydroxyethyl) – ethylenediamine

Corrosive above 0.4% in solution

DEAHEP: N, N-di-(2-hydroxyenthyl) – piperazine

Exhibits iron chelating properties