3.2 Sulphur cycle - Treccani

3.2.1 Introduction

The removal of sulphur components from liquidand gas streams is required in many sectors of thehydrocarbon processing industry. With morestringent fuel regulations and increasingenvironmental concerns, together with the need toprocess sourer crude oils and natural gases,sulphur recovery has become one of the leadingissues in emission reduction.

The term sulphur cycle (Fig. 1) designates alarge number of processes widely used in therefining industry, for purposes ranging from thetransformation and/or capture of sulphurcompounds contained in the petroleum fractionsto their removal, generally as elemental sulphur.

The general idea of the sulphur cycle is toeliminate sulphur compounds from variouspetroleum fractions (Heinrich and Kasztelan, 2001).This is realized via: a) isolation and concentrationof the undesired sulphur compounds; b) sulphurspecies transformation mainly into hydrogensulphide (H2S) in HydroDeSulphurization (HDS)units (HDS units included in a typical reformingcycle are presented in Chapter 3.1) and inhydrocracking or catalytic cracking units; c) captureand enrichment of H2S via solvent washing (e.g.amines units); d) conversion of H2S into elementalsulphur in the Sulphur Recovery Unit (SRU): Clausand/or other processes (see Sections 3.2.3-3.2.4).

Elemental sulphur is the ultimate state ofrecovery of the sulphur species. In the past,recovered elemental sulphur had considerablevalue and was sold in the commercialmarketplace. However, as the hydrocarbonextraction industry continually recovers moresulphur, the supply far exceeds demand and pricesare driven down to levels where transportation is

no longer economically possible. This market isnow expected to exhibit a chronic oversupply. Ona worldwide basis, approximately 60 millionmetric tons of sulphur were produced in the year2000. It is generally assumed that the Clausprocess had produced 85% of this sulphur, 90% ofwhich being used for sulphuric acid (H2SO4)production (60% of H2SO4 is used for fertilizerproduction).

The discussions below intend to give a generalidea of the capabilities of various sulphurrecovery processes, while taking into account thenature of the stream. Compared to gas processing,petroleum refining is a source of gas with lowcarbon dioxide (CO2) content; nevertheless, ifthere is a catalytic cracking unit in the refineryscheme, the gas may contain some othercontaminants such as carbonyl sulphide (COS),

137VOLUME II / REFINING AND PETROCHEMICALS

3.2

Sulphur cycle

refinery gas

sweet/fuel gas

incineration

incineration

acid gas SWS gas, NH3

sulphur

overall sulphurrecovery up to 99.9�

Fig. 1. Typical sulphur cyclein the refining industry.

organic sulphur, cyanides, ammonia and organicacids.

3.2.2 H2S recovery processes

Several factors must be considered when selectinga gas treating process: processing temperature andpressure, quality and quantity of sour gas to betreated, product gas specifications and/orsubsequent processing requirements for the acidgas as well as the produced gas. A few otherfactors, such as capital investment, operatingcosts, climatic conditions and operability, bear animpact on the final choice. Acid gas requirementsare linked to its final processing. A wide range ofavailable processes dedicated to elemental sulphurrecovery from H2S is described in Section 3.2.3.

There are sweetening units in the refinery torecover H2S from acid gas streams. A typicalrefinery exhibits multiple absorbers and acommon regenerator, as there are several unitswhere H2S is produced. Among the products to besweetened, one can find the following: fuel gas,Liquefied Petroleum Gas (LPG), hydrotreaterproduct and/or fuel gas and recycle gas,hydrocracker product and/or fuel gas and recyclegas, cracker gases, and the remaining gasesgenerally combined. The solvent is thenregenerated in a single stripper and the acid gas,produced at low pressure, is sent to the Claus unit,transforming H2S into sulphur, or to an equivalentunit. Chemical, physical or hybrid solvents arethose typically encountered in the industry.Chemical sweetening technology has been usedfor over 70 years; alkanolamines are the mostwidely used of the many available solvents forremoval of H2S and CO2 from refinery andnatural gas streams.

The traditional way of operating sweeteningunits has been to remove CO2 along with H2S.Unfortunately, this CO2 removal causes severalproblems. More energy is needed at the amine

regenerator or stripper, together with a largercirculation rate of amine. On the one hand, a largeCO2 concentration dilutes the gas to be treated inthe Claus unit, sulphur recovery being optimal fora concentrated H2S feed stream, typically morethan 50%. On the other hand, as more CO2 isrejected, more H2S can be converted to elementalsulphur in the Claus unit and, therefore, lesssulphur dioxide (SO2) will be vented or removedby a tail gas scrubber. Moreover, if there is a loopto recover H2S from TGT (Tail Gas Treating) andit is sent to the Claus, then the minimum amountof CO2 is essential to ensure amine and Clausefficiencies. This loop generally utilizes areducing atmosphere to convert all of theremaining sulphur species to H2S; the resultingacid gas is amine washed and the H2S stream isrecycled to the Claus. These considerationsdemonstrate the interest in selective absorption orAcid Gas Enrichment scheme (AGE), combiningtwo amine units (Fig. 2), one being H2S selectiveto provide highly H2S concentrated feed to theClaus unit.

Amine process schemesA very common amine design configuration

includes one single absorber, one singleregenerator and all related equipment such aspumps, heat exchangers and filters. Fig. 3illustrates a typical gas treating plant usingalkanolamine. After passing through an inletseparator and/or a liquid-gas separator to removeany entrained solids or liquids, the sour gas entersthe bottom of the absorber. Generally, trays (oreventually packing) are used as internals for thisvessel, where the gas is contacted counter-currentlywith the solvent. The acid gas is absorbed in the solvent and reacts with the amine.Depending on the application, the absorber mayhave multiple amine feed entry points. Richamine solution leaving the absorber flows to theflash tank, where the solution pressure is reducedto flash the soluble hydrocarbons and to remove

138 ENCYCLOPAEDIA OF HYDROCARBONS

PROCESSES RELATED TO ENVIRONMENTAL ISSUES

sour gas sour gas

H2S to Claus�TGT

H2S, CO2

sweet gas

sweet gas

CO2vent /incineration

H2Sto Claus�TGT

H2S, CO2incineration

Fig. 2. Acid gasenrichment schemes.

the condensed hydrocarbons. From the flash tank,the rich amine passes trough a lean/rich crossexchanger that ensures liquid preheating andflows to the top of the regenerator. The heatprovided by the reboiler is necessary to raise therich amine to its boiling temperature, to break thechemical bond between acid gas and amine, andfinally to produce enough steam, which reducesthe partial pressure and allows the acid gas to bestripped from the solvent. The stripped acid gas,whose pressure depends on SRU requirements,then typically flows to a Claus plant for sulphurrecovery. The hot and lean amine is circulatedback from the reboiler to the absorber afterpassing through the lean/rich exchanger, where itis used to preheat the rich amine, and lean solutioncooler. Part of the solution is filtered to minimizethe quantity of potentially corrosive degradationproducts and the quantity of anti-foaming agentsfor better control of the absorber.

Other considerations may lead to morecomplicated unit designs, including several flashregeneration steps (especially for hybrid andphysical solvents), several absorbers in series,several absorbers in parallel and split-flowconfigurations. An example of split-flowconfiguration is presented in Fig. 4, where a semi-lean amine stream realizes the bulksweetening, while a small stream of lean amine is used to reach the sweet gas specifications.

Many treating processes are available, thoughno single process is ideal for all applications. Theinitial selection must be based on required feedspecifications together with feed parametersincluding the composition, pressure, temperature,and nature of the impurities. A more detailedapproach follows, considering the percentage ofacid gas in the feed. CO2 concentration couldimpose a selective removal of H2S to reduce theregeneration duty of the amine unit. Finally, agiven process is selected according to economics,reliability and versatility factors of the design,while taking environmental constraints intoaccount. As a result, gas processing in therefinery is growing more complex. In fact, thechallenge resides in choosing between varioussolvents and process configurations. Hence, moreupstream and downstream gas processing stepsshould be implemented, which results in a needfor more equipment.

Base for solvent selectionFeed gas composition should be evaluated

prior to entering the absorber section of a solventunit. Contaminated gas damages the solvent andmay cause corrosion, foaming, plugging, togetherwith products that do not meet specificationstandards. The contaminants discussed includesolids or dust, elemental sulphur, COS,mercaptans (RSH), carbon disulphide (CS2),


SULPHUR CYCLE

rawgas

absorber

stripper

treated gas fuel gas

leanamine

acid gasFig. 3. Amine unit,simplified flow diagram.

Benzene-Toluene-Xylenes (BTX), heavyhydrocarbons and mercury.

The numerous possible processes available aswell as the amount of variables involved renderabsolute determination impossible (Lallemand etal., 2004). The feasibility and desirability ofsulphur recovery leads to limitations on theselection of sweetening processes.

The quality of sulphur produced from a Clausunit is quite sensitive to the presence of heavyhydrocarbons in the acid gas. If the solvent absorbslarge quantities of heavy hydrocarbons, anadditional process may be required on the acid gasleaving the unit or a high efficiency burner must beinstalled in the Claus to destroy these components.Chemical and physical solvents are used over awide variety of process conditions, ranging frommedium pressure to atmospheric pressure forrefinery off-gas and Claus tail gas treating. Solventsfor H2S selectivity are employed for refineryapplications with high CO2 slippage, tail gastreating and LPG streams. The absorption of H2Sand the selectivity over CO2 could be controlled bykinetics and contact time, and are enhanced whenoperating at low temperature. Consequently, it isdesirable to lower the lean amine temperature andto run the absorber at a low temperature.

Solvents overviewGeneric and speciality solvents are generally

divided into three categories: chemical solvents,physical solvents and hybrid (mixture of chemicaland physical) solvents. The removal of acid gasesby the chemical solvent is brought about througha chemical reaction. Physical solvents removeacid gases by absorption. Hybrid solvents utilize acombination of absorption and chemical reaction.

Chemical solventsAmine processes utilize an aqueous solvent

containing a chemical reactant: an alkanolamine.On the one hand, hydrogen sulphide and carbondioxide are considered acid gases because theydissociate to form weak acids in aqueoussolutions. On the other hand, alkanolamines areweak bases and react with the acid gases in theabsorber to form soluble acid-base salts. Thesesoluble complexes are then reversed in theregenerator at elevated temperature and lowpressure. Reduced pressure in the regeneratorallows acid gas release and regenerates thesolvent to be reused. Alkanolamines exhibit twoimportant chemical properties. The amino groupis responsible for weak reactivity of the base,allowing heat regeneration of the salt; moreover,



rawgas

absorber

stripper

treated gas

fuel gas

leanamine

acid gas

semi-leanamine

Fig. 4. Amine unit,split-flowconfiguration.

the OH group weakens the basicity, increasessolubility in water and lowers vapour pressurewhen compared to a single amine. Chemicalsolvents are well suited for low operatingpressure applications since the removal capacityis high and relatively insensitive to partialpressure when compared to physical solvents(Fig. 5). As a general rule, amine solutionconcentration and loading (the ratio between thenumber of moles of acid gas and the number ofmoles of amine) are limited by equilibrium andcorrosion issues. Nevertheless, amines arecharacterized by a relatively high heat ofabsorption and then require a substantial amountof heat for regeneration.

The alkanolamines are classified by the degree ofsubstitution of the hydrogen atoms on the centralnitrogen (Table 1). Tertiary amines are fullysubstituted on the nitrogen atom, while primary andsecondary amines keep two or one hydrogen atom onnitrogen, respectively. These differences inmolecular structure clearly impact their acid gasremoval capabilities. Moreover, modern solventsinclude hindered and formulated amines, whichinfluence some of the amine’s properties for specificapplications. When considering generic amines(Table 2), there is a marked difference in solutionconcentration due to the physical-chemicalproperties and potential corrosion of the solution.

The reaction between acid gases andalkanolamine is exothermic and liberates asubstantial amount of heat. Reaction type differs forH2S and CO2. In the following reaction, where R1,R2 and R3 indicate hydrocarbon or alkanol parts ofthe molecule, H2S reacts instantaneously withalkanolamine:

[1] R1R2R3N�H2S��R1R2R3NH�HS�

The reaction between alkanolamine andcarbon dioxide is more complex, in that two

reaction mechanisms can occur. The dissolvedCO2 in aqueous solution hydrolyses to carbonicacid, which slowly dissociates to bicarbonate. Thebicarbonate then forms a salt with the aminethrough an acid-base reaction. The variousreactions are summarised as follows:

[2] CO2�H2O��H2CO3 (carbonic acid)

[3] H2CO3��H��HCO3

� (bicarbonate)

[4] H��R1R2R3N��R1R2R3NH�

[5] global reaction:CO2�H2O�R1R2R3N��

��R1R2R3NH�HCO3�

The carbonic acid dissociation to bicarbonate iskinetically slow, causing the overall reaction to beslow.

When the amine is of primary or secondarytype (i.e. exhibiting labile hydrogen), CO2 reactsdirectly with the amine through intermediateformation of a carbamate, which reacts with asecond molecule of alkanolamine to form anamine salt or zwitterion.

[6] CO2�R1R2NH��R1R2N

�HCOO�

[7] R1R2N�HCOO��R1R2NH��

��R1R2NCOO��R1R2NH2

�

[8] global reaction:CO2�2R1R2NH��

��R1R2NH�2��R1R2NCOO�

The kinetics of this reaction is faster than thecarbonic acid dissociation, though somewhatslower than H2S absorption. This reaction requirestwo alkanolamine molecules, which limits CO2maximum loading to 0.5; therefore, upper loading


SULPHUR CYCLE

acid gas partial pressure

physical 50°C

chemical 50°C

chemical 80°C

physical 80°C

acid

gas

/sol

vent

volu

me

rati

o

Fig. 5. Acid gas recovery: chemical versus physical solvents.

Primary Amines

Monoethanolamine(MEA)

HOCH2CH2�NH2

Diglycolamine(DGA agent)

HOCH2CH2OCH2CH2�NH2

Secondary Amines

Diethanolamine(DEA)

HOCH2CH2�NH�CH2CH2OH

Diisopropanolamine(DIPA)

CH3CHOHCH2�NH�CH2CHOHCH3

Tertiary Amines

Methyldiethanolamine(MDEA)

HOCH2CH2�N(CH3)�CH2CH2OH

Triethanolamine(TEA)

N�(CH2CH2OH)3

Table 1. Classification of alkanolamines

may result from carbamate hydrolysis tobicarbonate. Unlike common amines, hinderedamines are based on a steric hindrance providedby a bulky hydrocarbon-hydroxyl chain adjacentto the amino atom. Consequently, the reaction ofCO2 with this amino group is no longer possibleand the H2S selectivity is thus amplified.

Physical solventsPhysical solvents are based on non-aqueous

solvent and physical absorption. They arecharacterized by low volatility, low to moderateviscosity, high boiling point, and exhibit excellentthermal and chemical stability. The solubility ofH2S, CO2, RSH, CS2 and SO2 is higher in physicalsolvents than hydrogen, methane, oxygen andnitrogen. Nevertheless, heavy hydrocarbons are alsosoluble in the physical solvents. Therefore, the flowscheme takes this particularity into account withmulti-step flashing to lower the pressure, followedby an inert stripping gas and/or a low energydemand regeneration. This method is generallymore complex than that of basic amine, thoughattractive from an economic standpoint since theenergy demand is low. The above is considered forH2S selective recovery when the acid gas partialpressure is greater than 4 bar and when thehydrocarbon content, particularly BTX, is low infeed gas.

Hybrid solventsHybrid solvents, or mixed solvents, are

designed to merge the effects of chemical andphysical solvents by mixing amine (40-60% byweight), physical solvent (10-40% by weight) andwater (20-30% by weight). The process combinesthe advantages of both solvents as it uses physicalsolvent for acid gas bulk removal and chemicalsolvent to achieve gas specifications. Heavyhydrocarbon absorption remains one of thedisadvantages of the hybrid process. Their

application involves the removal of H2S, CO2 andtrace sulphur. The energy requirement andcirculation rate are relatively low (Lecomte et al.,2003). In practice, process schemes combine flashand thermal regenerations.

Another example of mixed solvents isactivated hot potassium carbonate (e.g. withDEA). It is used for H2S and CO2 recovery. Sincethe solvent is hot, which avoids anycrystallization and lowers the viscosity,regeneration does not require a great amount ofenergy and is performed through low pressureflashing. Packing is preferred to trays for thistechnology, which allows process optimizations.The operating costs of this process are primarilydetermined by the overall heat utilization in therefinery.

Main solvents and their applicationsAn approach for initial solvent and process

selection should take into account several factors:lean or rich gas, large or small flow, the amountof sulphur, trace sulphur compounds,contaminants, pressure and site factors.

Amine solventsThese include generic and hindered amines.

All are used, but DEA and MDEA have probablybeen applied more in refinery and natural gassweetening industries in general. Up to now,amine-based processes have dominated the gassweetening industry:• MEA is used for low-pressure applications and

complete acid gas removal. It is a highlyreactive primary amine that exhibits low cost,good thermal stability, partial removal of COSand CS2. However, MEA presents a lowsolvent vapour pressure, a highly corrosivenature, high-energy demand for regeneration,and the removal of acid gas is non-selective.

• DEA is a secondary amine and one of the most



Table 2. Alkanolamines and their applications

Amine Solution(% weight) Applications Comments

MEA 15-20 CO2 Low pressure

DEA 25-40 Refinery Commonly used

MDEA 25-50 Refinery and TGT Selective absorption

Formulated MDEA 40-50 H2S/CO2 Displacing other amine types, low aromatic absorption

DGA 50-60 Refinery Absorbs all sulphur compounds and aromatics

DIPA 25-55 Refinery Absorbs heavy HC and partially COS

widely employed for gas containing H2S, CO2,COS and CS2, due to an overall balancebetween reactivity and corrosion. It is lessreactive, has lower solvent vapour pressureand lower corrosion potential than MEA,coupled with a lower solvent cost. DEA isnon-selective and requires higher circulationrates in the sweetening unit.

• DIPA is primarily used in European refineriesat 40-50% weight concentrations. Its sterichindrance provides a moderate selectivity forH2S over CO2, which can be a disadvantagefor Claus off-gas treatment applications. Itexhibits a partial removal of COS, thoughhydrocarbon solubility takes place to someextent. Its cost is comparable to that of genericMDEA.

• DGA, like DGA agent, allows high solventconcentration. This highly reactive primaryamine removes COS, CS2 and (partially)mercaptans. It shows excellent thermalstability and requires low circulation rates.However, DGA absorbs aromatics and is moreexpensive than both MEA and DEA, whichmust be considered for the sulphur recoverydesign.

• MDEA is among the most recent amines andis now displacing the other alkanolamines. Inhighly concentrated solution, this tertiaryamine is selective to H2S. It exhibits lowvapour pressure, high resistance todegradation, low corrosiveness and low energydemand for regeneration. However, itsreactivity is low and solvents price higherwhen compared to the above. In addition, theremoval of COS and CS2 is low. Formulated oractivated MDEA with primary or secondaryamines allow CO2 absorption and are nowdisplacing primary and secondary amines inrefinery applications. Among the advantages,MDEA absorbs the lowest amount of BTX,compared to DEA and MEA.

• Hindered amines are used as an attractiveapproach for low-pressure acid gasenrichment. One disadvantage of thistechnology is the solvent cost of thesesproprietary amines, when compared to classicacid gas enrichment based on selectiveMDEA.

Application of physical solventsPhysical solvents are used with various

process schemes.• DiMethyl ethers of PolyEthylene Glycol

(DMPEG) are contacted with dehydrated sour

gas to absorb the acid gas constituents. Someselectivity for H2S may be designed in theabsorber with a much lower energy cost thanamine processes, since regeneration is mainlyobtained through flashing and power recoveryturbines. Hydrocarbon co-absorption,especially for aromatics and olefins, ischaracteristic of physical solvents.

• Methanol processes use a refrigerated (�20°Cor lower) mixture of methanol and water. Asmall amount of methanol is injected in thesour gas to prevent hydrate formation. Beingthat methanol has high solubility forhydrocarbons, special attention is paid in theIfpexol process to recover them in a three-phase drum.

• N-Methyl-2-Pyrrolidone (NMP) exhibits someselectivity of H2S over CO2. The same can besaid of methanol, concerning hydrocarbon co-absorption.

• Morpholine process uses a mixture containingn-formyl morpholine and n-acetyl morpholine.This new process is of interest for bulkremoval or for sulphur trace removal.

Application of hybrid solventsThe solvent combination of both chemical and

physical solvent results in a wide range ofapplicability in terms of pressure and acid gascontent:• Mixture of sulpholane (tetramethylene

sulphone), DIPA and water and mixture ofsulfolane, MDEA and water allow a highdegree of removal, not only of H2S and CO2,but also of trace sulphur compounds such asRSH, COS, CS2. Disadvantages of this processinclude high hydrocarbon co-absorption andsometimes a large solvent flow to obtain thesweet gas specification.

• Mixture of methanol, amine and water exhibitsa high recovery for acid gas including tracesulphur compounds, such as mercaptans.

Process design and simulationThe solvent behaviour results from the

operating conditions and must be monitored.Process design is based on the equilibriumbetween the dissolved gas and the solvent. Theloading varies with the solvent concentration inactive species for a given H2S partial pressure. Toachieve a treated gas specification at the unitoutlet, it is necessary for the solvent entering theabsorber to exhibit an H2S concentration lowerthan that in the solvent in equilibrium with theexhaust gas leaving the absorber. Moreover, it is


SULPHUR CYCLE

known that H2S reacts with aqueous alkanolamineat a faster rate than CO2, providing selectivitywhen used with special designs. The absorberinternal efficiency must be incorporated to takeinto account the selectivity in amine unit models.This efficiency is then a function of the kineticrate constants for the reactions between each acidgas and the amine, the physico-chemicalproperties of the solvent, the pressure, thetemperature and the internal design variables. Fortrays, these variables include diameter, weirlength, weir height and the number of trays.Absorption and desorption of H2S (and CO2)involve a heat effect in amine solutions as achemical reaction takes place, and are a functionof amine type, concentration and loading. Thisleads to water evaporation and condensation inthe absorber and in the regenerator; thus the watercontent of the feed gas must be considered whenpredicting the temperature profile.

Commercial simulation software generallymade use of thermodynamic models, such as the one developed in 1976 by R.L. Kent and B. Einsenberg, which are fitted using sets ofproprietary data.

Operating problemsThe operating problems encountered in such

units are usually linked to design; trouble freeoperation results from unit control and, inparticular, solution control. The parts of the unitthat must be carefully checked will follow.

Inlet scrubbing. The type and design of inletseparation must be carefully considered, as theyare critical for trouble-free operation of thesolvent unit. They can vary from slug catchers,removing condensed water and hydrocarbons, toreverse flow filter or coalescers when sub-micronrange aerosols are expected.

Absorber. The diameter is determined by thefeed gas flow rate and the solution circulation rateby the type, concentration and equilibriumloading of the amine. Trays are the most commoninternals, but random and structured packing canbe found.

Flash tank and lean/rich exchanger. Lowpressure at the flash tank (3-6 bar) helps toremove hydrocarbons, which reduces the aminefoaming potential. Exchanger corrosion must beavoided in the rich amine line due to flashing acidgases at the outlet. Stainless steel metallurgyshould be considered for low solventconcentration and high amine loading.

Regenerator. The purpose is to strip the acidgas from the rich amine using steam generated by

the reboiler. Steam or hot oil provides heat to thereboiler; a 3.5 bar saturated steam isrecommended to avoid solvent degradation andcorrosion. The reflux ratio, ranging from 1 to 3, islinked to the lean solvent specification.

Filter. The solvent should be kept clean byusing adequate mechanical filtration (5 or 10 mm)and carbon filtration. The removal of FeS andFeS-hydrocarbon materials from this equipmentavoids problems. A minimum 10-20% slipstreamof the circulation unit should be submitted tofiltration. The filtration media is to be changedwhen the solvent colour varies and heat stablesalts should be prevented from building up.Activated carbon filtration can reduce the needfor antifoam.

Amine solution control system. Solutioncontrol leads to more reliable and trouble-freeoperation. It is important to test the aminebehaviour with appropriate analytical techniques.The operator should have the procedures, theequipment as well as the expertise to perform thetests defined by the process or amine vendor.Foaming, corrosion, solvent degradation and theresulting unit loss in capacity may be the result ofinappropriate analytical tests or evaluation time-schedule. General analysis includes amine tests(alkalinity titration, chromatographic spectrum),acid gas loading, water content, solids and ashcontent, heat stable salt content and anionanalysis (ion chromatography). Moreover, aspecific test for foaming ability could be of greatinterest to monitor the unit.

Process variablesAs the unit is properly designed, the main

variables in solvent processes include thefollowing.

Quality of the feed. The unit is generallydesigned for a specific feed or a range of H2Sconcentration. Since sweet gas quality depends onthe feed characteristics, specifications couldeventually not be reached for some feed streamseven using a higher flow rate or a moreregenerated solvent.

Absorber and regenerator pressures. Absorberpressure generally results from the pressure of gasat the exhaust of the previous refinery unit. Achange in the regenerator pressure may be theresult of a revamp of the SRU, when, for example,a higher sulphur recovery is required.

Absorber temperature. Solvent temperaturemust be higher than feed gas temperature,typically 5-8°C, to prevent condensation andfoaming.



Space velocity. Absorption is affected byhydrodynamics. It is especially important tocontrol space velocity when slow kinetic for CO2is opposed to equilibrium absorption of H2S in aselective removal.

When all of these items are well established,changes in operating conditions may lead to thefollowing problems:

Amines losses. They could be either physical-mechanical or chemical based. Excessivesolution losses are generally linked to solutionfoaming.

Foaming. Foaming will not occur if no extra-unit contaminant is present in the streams.Classical contaminants include corrosioninhibitors, additives, liquids or solids entering theunit and dissolved degradation products (FeS).The above leads to decreased efficiency,unattainable specification and solvent losses.Some additives (silicon-based) are used to lowerthe surface tension of liquids, and thus reducefoaming. Use of an antifoam agent should beconsidered a short-term measure.

Corrosion. Corrosion in amine units requiresvery special attention. Amine and degradationproducts may cause severe corrosion to theequipment. Industry experience has pointed outthree key corrosion issues: exceedingly high flowvelocities, air entries leading to corrosivedegradation products and excessive reboilertemperatures. These issues are resolved throughproper design and operating practices (Bonis etal., 2004) for units working with high amineconcentrations (up to 40% weight for DEA). Aslong as amine degradation products are identifiedas key factors, MDEA is expected to besignificantly less corrosive than DEA, due to ahigher stability coupled with a lower degradationproduct concentration.

Impact of feed gas composition on sulphurremoval unit efficiency. The composition of theacid gas leaving the acid gas removal unit has animpact on sulphur recovery efficiency. If the H2S content is low, acid gas enrichment is recommended. Basically, H2S, hydrocarbons andammonia contents would establish the criteria forsulphur recovery efficiency and designs. Theconventional sulphur plant could then be convertedto oxygen enrichment so as to process more sourgas and destroy the remaining impurities.Nevertheless, if the solvent has been changedeither to process more acid gas or for economicreasons, the downstream sulphur recovery unitsgenerally need some equipment modifications forcapacity expansion.

3.2.3 The Claus process

The objective of the Claus process is to recoverelemental sulphur (Sx, with x between 2-8depending on the temperature) from gas streamscontaining hydrogen sulphide (H2S) stripped fromgas sweetening solvents (see Section 3.2.2). TheClaus process produces elemental sulphur by thepartial oxidation of H2S:

[9] H2S�1/2 O2��1/8 S8�H2O�heat (209 kJ)

The Claus plant effluent gases are either sent toan incinerator or to a TGT unit (see Section3.2.4), depending on the local air pollutioncontrol regulations. The final effluent gas, whichcannot be valorized, is incinerated to convert allof the sulphur compounds to sulphur dioxide(SO2) in a thermal or catalytic incinerator. Beingof very good quality, the elemental sulphurproduced in the SRU, Claus or Claus plus TGT, isused as a basic chemical in the industry. Theproperties of elemental sulphur are well describedin various literature (Meyer, 1976; Shuai andMeisen, 1995).

In the original Claus process, reaction [9] wascarried out in a single step over a catalyst. Sincethe heat of the reaction was dissipated only byradiation, high sulphur recovery was very difficultto obtain. A very important modification to theClaus process was made in 1940, which allowedenergy recovery, increased process capacity andeliminated the issue of maintaining, in thecatalytic reactor, the low temperature favouringhigh sulphur recoveries. In this modified-Clausprocess (Fig. 6), reaction [9] is carried out in twostages.

In the first stage, the thermal section, one-third of the H2S is oxidized to SO2 with air oroxygen enriched air at high temperature(generally 925-1,200°C):

[10] H2S�3/2O2�� SO2�H2O�heat (518 kJ)

This reaction is highly exothermic and is notlimited by equilibrium. The unburned H2S in theacid gas reacts with the SO2 (obtained throughreaction [10], to yield the stoichiometric H2S/SO2ratio of 2:1) to form elemental sulphur vapour:

[11] 2H2S�SO2��3/2S2�2H2O

This reaction is endothermic and is limited byequilibrium. About 60-70% of the conversion ofH2S to elemental sulphur occurs in the thermalstage. An important function of the thermalsection is also to destroy the impurities that maybe present in the feed acid gas stream, such as


SULPHUR CYCLE

ammonia (NH3), hydrocarbons, etc. During thethermal stage, side reactions also occur in thepresence of CO2 or hydrocarbons, which produceCOS and CS2.

In the second stage (i.e. catalytic section), theoverall conversion of H2S to elemental sulphur isincreased in a series of catalytic reactors (1 to 3)by reaction of the generated SO2 and theunreacted H2S over fixed beds of Claus catalystsat much lower temperatures (190-360°C):

[12] 2H2S�SO2��3/8 S8�2H2O�heat (108 kJ)

Reaction [12] is called the Claus reaction. Theuse of appropriate catalysts at selectedtemperatures optimizes the Claus reaction yieldand also allows COS and CS2 produced in thethermal stage to be eliminated. High-Pressure(HP) steam is generated in the Waste Heat Boiler(WHB), in which the gases are cooled from thehigh flame temperature to the lower catalyticreactor (converter) temperature (see again Fig. 6).Sulphur condensers are provided to condense andseparate the elemental sulphur formed after thethermal stage and after each catalytic reactor. Theheat released by the Claus reaction is recovered asLow-Pressure (LP) steam in each sulphurcondenser. Product removal, lower catalyticconverter temperatures and an increased numberof catalytic converters enhance sulphur recovery.Table 3 presents the typical, total sulphur recoveryof the modified-Claus process depending on thenumber of catalytic reactors used.

Nowadays, sulphur recovery plants are basedon the modified-Claus process, although the

original Claus process is still implemented to treatvery low H2S concentrations gases, though in thiscase, it is referred to as direct oxidation process.There are a number of different processconfigurations for the modified-Claus process,depending mainly on the H2S concentration in theClaus feed gas.

Chemistry and thermodynamics of the Clausprocess

In principle, ideal performance is achievedwhen all stoichiometric requirements for the basicprocess reactions are satisfied under the mostfavourable thermodynamic conditions, andequilibrium is reached at all points in the process.While thermodynamic favourability determinesideal performance, the practicable capability isdictated by the kinetic limitations imposed by theoperating conditions and plant equipment.

ThermodynamicsThe basic design of a typical modified-Claus

plant can be best understood by looking at thethermodynamic equilibrium curves calculated forthe reaction of pure hydrogen sulphide (H2S) withair (Fig. 7):

[13] H2S�1/2 O2��1/xSx�H2O

Calculations are based on the principle ofminimization of the Gibbs free energy. All threecurves were calculated without sulphur removalfrom the system. The difference between theupper and lower curves (see again Fig. 7) resultsfrom the sulphur vapour species under



LPsteam

HP or MPsteamair

burner

muffle furnace

waste heat boiler

S S S

LPsteam

LPsteam

or directerator

optional 3rd catalytic staged

catalytic stagethermal stage

0-150°C

H2S

re-h

eate

r

catalyticreactor

catalyticreactor

re-h

eate

r

re-h

eate

r

Fig. 6. Typical Claus process scheme (straight-through design).

consideration and the differences inthermodynamic data. The shape of the curves inFig. 7 is a direct result of the temperaturedependency of the sulphur vapour compositionshown in Fig. 8. High molecular weight speciesdominate at lower temperatures, and vice versa.Thus, for a fixed number of sulphur atoms, fewermoles of sulphur vapour are formed at lowertemperatures. This decreases the sulphur vapourpartial pressure and tends to shift the equilibriumof reaction [13] to the right as well as increase theconversion. The opposite is true at highertemperatures. The same phenomenon causes theconversion to increase at low temperatures and

decrease at high temperatures, as the total systempressure is increased. The theoretical degree ofconversion is high at low temperature, falls offrapidly and passes through a minimum at 560°C(1,040°F), and then increases more slowly athigher temperatures. In the thermal stage region,it is not possible to reach sulphur recoveries ofover 70%. Moreover, care must be taken toquench the reaction mixture rapidly in order toavoid reverse reaction. To convert more gases tosulphur, thermodynamics suggests lowertemperatures in the catalytic region. Beforeentering catalytic converters, elemental sulphurmust be condensed from the gas stream to preventsulphur condensation on the catalytic bed andimprove thermodynamic equilibrium yields. Forthermodynamic reasons, the catalytic unit shouldbe operated at as low a temperature as possibleabove the sulphur dewpoint, provided that the rateof the reaction is fast enough. In practice, sulphurrecovery is maximized by using two or morecatalytic converters with sulphur removal betweeneach converter, and by decreasing temperature insuccessive converters.


SULPHUR CYCLE

Table 3. Total sulphur recovery of the modified-Claus process over the number

of catalytic reactors used

Number of catalyticreactors

Total sulphur recoveryof a modified-Claus

plant (%)

1 75-90

2 94-96

3 95-98

S8

S2

S2, S8

S2, S6, S8

Sx (S1, S2, S3, S4, S5, S6, S7, S8)

0

100

90

80

70

60

50

45500 1,000 1,500 2,000 2,500

conv

ersi

on (

%)

temperature (°F)

Fig. 7. Equilibrium conversion of H2Sto elemental sulphur (Paskall, 1979): effect of restricting the number of sulphur vapour species (pure H2S with air, 1.0 atm, no sulphur removal).

3.2 Ballaguet fig 08

0

100

90

80

70

60

50

below 540°F, vapour saturatedabove 540°F, vapour insaturated40

30

20

10

0500 1,000 1,500 2,000 2,500

com

posi

tion

(m

ole

%)

temperature (°F)

S4

S5

S6

S2

S3

S7

S8

Fig. 8. Equilibrium composition of sulphur vapour from reaction of H2Swith stoichiometric quantity of air with a total system pressure of 1.0 atm (Paskall, 1979).

Chemistry in the thermal stageCombustion processes occurring in the Claus

reaction furnace are complicated (Connock, 1999b). The presence of CO2 and small quantities ofhydrocarbons in the feed acid gas must be takeninto account to ensure that gases leaving theWHB have the desired 2:1 H2S/SO2 ratio. CO2 isparticularly important as it becomes involved in amultitude of processes leading to CO and COS,as well as affecting the amount of hydrogenfinally appearing in the product gas. Fig. 9provides a simplistic overview of Claus furnacechemistry showing what are considered the moreimportant reactions that occur in the furnace inthe absence of hydrocarbon contaminants, but inthe presence of CO2. Chemistry occurring in theClaus reaction furnace may be split into twotypes: combustion reactions occurring in theoxygen-rich region; reactions proceeding in theoxygen-free (anoxic) region drivenby the high temperature resulting fromcombustion reactions.

The carryover of hydrocarbons with the acidgas into the Claus reaction furnace furthercomplicates the reactions. The hydrocarbonimpurities may range from complex alkanes toBTX. Although thermodynamic considerationssuggest that these hydrocarbons should fullycombust to CO2 and H2O, the rate at which theydo so is questionable since the C�H bond isgenerally stronger than the S�H bond. Thus,kinetic factors will affect the fate of thehydrocarbons in the reaction furnace, since theywill be in competition with H2S for a restrictedoxygen supply. In the event that hydrocarbons arenot fully combusted, it is expected that they willproduce CO, C, COS and CS2 through reactions

with the sulphur rich environment:

[14] CH4�� C�2H2

[15] C�H2O�� CO�H2

[16] CO�H2O�� CO2�H2

[17] CH4�2S2�� CS2�2H2S

[18] C�S2�� CS2

COS and CS2 lower the Claus sulphurrecovery, unless their conversion to H2S isachieved by hydrolysis at the relatively hightemperatures found in the first catalytic converter.It has been well established that the design andmode of operation of the furnace can significantlyinfluence the degree to which hydrocarbons areconverted to COS and CS2.

Ammonia (NH3) destruction is also a problemwhen treating refinery Sour Water Stripper (SWS)off-gas.

Chemistry in catalytic stagesSulphur recovery in catalytic stages is

governed by two main catalytic reactions: theClaus reaction [12] and the hydrolysis of COSand CS2 (according to reactions [19] and [20],respectively).

[19] COS�H2O��CO2�H2S

[20] CS2�2H2O��CO2�2H2S

In terms of contribution to sulphur recovery,the Claus reaction is by far the most important.However, the efficiency of the COS and CS2hydrolysis becomes increasingly important andeven limiting when recovery targets of more than



SO2, H2S,S2, CO2,

N2, CO, H2,COS, CS2

SO2, H2S, CO2, N2,[CO, H2, COS, CS2]

H2S O2

SO2

N2CO2

waste heat boiler(heat removal

equilibria readjustment)

burner

1,200°C 1,000°C 600°C

reaction furnace

O2-richregion

anoxicregion

anoxic region

minor products

high temperaturesteam

water

H2S/CO2 [HC]

SO2, 2H2S,H2O, [S2]

[H2, CO,COS, CS2]

Fig. 9. Expanded overview of Claus reaction furnace and waste heat boiler (Connock, 1999b).

97.5% are required. The proper selection ofcatalysts is an essential part of modified-Clausplant optimization to achieve maximum sulphurrecovery efficiencies. A wide range of industrialcatalysts is now available (Table 4). There arebasically five types of industrial Claus catalysts(Sulphur […] 1995; Chasing […] 1997).

Activated alumina catalysts generallydemonstrate high activity toward the Clausreaction in the first reactor, fair activity towardCOS hydrolysis in the first reactor and toward theClaus reaction in the second reactor. They do nothave adequate activity for CS2 hydrolysis.Activated aluminas are manufactured bygranulation of flash-dried alumina hydroxides(hydrated alumina that has had its water thermallyremoved to produce a transitional phase alumina).Alumina-based catalysts are subject to variousdeactivation mechanisms:• A combination of temperature and water

content reduces the effective surface area ofthe catalyst due to thermal and hydrothermalageing. This effect is irreversible, thoughproper design, operation and maintenance ofthe plant can limit it.

• Fouling by condensation of sulphur or bydeposition of carbon or ammonium saltsimpairs catalyst activity by plugging the pores.Sulphur deposition is reversible, the catalystbeing regenerated by heat soaking with noadverse effect. Carbon and ammonium saltsdeactivation is essentially irreversible. It isbest avoided by reducing contamination of thefeed gas (BTX, high molecular weighthydrocarbons, ammonia compounds andamines).

• All alumina-based sulphur recovery catalystsare prone to sulphation if exposed to sulphurand/or SO2 and traces of oxygen. Sulphationis most likely to occur during start-up,shutdown or periods of malfunction when thefeed gas/oxygen balance is disturbed.Sulphation is partly reversible by heat soakingunder an H2S/SO2 ratio above 2:1. However,activity improvement is temporary andrepeated rejuvenations result in irreversibledamage to the catalyst, shortening itslifespan. It is best avoided by proper oxygencontrol. However, a study (Clark et al., 2002)has shown that the formation of sulphate onalumina is directly related to the oxidizingproperties of the solid and the chemistry ofH2S/SO2 conversion over this material.Indeed, although sulphate is formed byoxygen ingress into a converter, it will also be

present on any Claus catalyst as a result of thechemistry of H2S/SO2 conversion, even in theabsence of oxygen.Titanium dioxide-based catalysts

(TiO2-based catalysts) have a higher activity thanactivated alumina towards carbon sulphidehydrolysis in the first reactor and towards theClaus reaction in all stages. Appreciable carbonsulphide conversion can also be attained at secondconverter conditions. The Claus reactionis driven virtually to thermodynamic

equilibrium. TiO2-based catalysts are much lesssusceptible than alumina to ageing and remainvirtually unaffected by sulphation. Sulphate isalso formed on TiO2, though it appears to have noinfluence on CS2 conversion at temperaturesexceeding 320°C. Moreover, they have a virtually unlimited lifespan undernormal conditions.

Various promoted activated alumina catalystsare also available. Alumina may be promoted byalkaline earth oxides (calcium or magnesiumoxides), TiO2 or sodium monoxide (Na2O).The alkaline earth promoted catalysts weredesigned to improve the resistance of activatedalumina Claus catalysts to sulphation. TiO2-promoted alumina catalysts have higheractivity than ordinary activated alumina for both the Claus reaction and carbon sulphide hydrolysis.

Protective catalysts (iron- and nickel-promotedalumina) are used as a guard bed to protect standardalumina catalysts in Claus reactors against sulphationby reducing the oxygen content of the stream gas. It isespecially advantageous to use protective catalysts inClaus plants when direct reheating is considered. Theyare also active for the Claus reaction and hydrolysisreactions. In fact, a bed of activated alumina catalysttopped by a layer of protective catalyst is often morereactive for all reactions than a single layer ofactivated alumina. The use of these oxygen-scavengingcatalysts in the Claus unit also provides protection forsubdewpoint tail gas treatment units downstream. Withstreams containing BTX, it is also possible to use aprotective catalyst layer, generally a selectivehydrogenation catalyst, in order to prevent carbonfouling by avoiding BTX crackingand polymerization.

Claus productivity can also be boosted if the bedsupport material, used at the top and bottom ofClaus reactors, also acts as a catalyst. These activebed support aluminas are used to replace inert ballsproviding higher overall activity. These products areespecially useful when severe operating conditionsrequire an exceptionally strong material.


SULPHUR CYCLE

The industrial Claus processes and their evolutionThe Claus is the technology of choice for

gases containing high concentrations of H2Sand/or large quantities of sulphur. Nevertheless,when H2S content is lower than 30% and/or theamount of sulphur is less than 10-20 tons ofsulphur per day (t S/d), some other processes areoften more economical.

Rich acid gases (H2S�50%)The H2S content of the Claus acid gas feed

encountered in most refineries is around 80%. It istreated in the simplest, straight-through Claus processwhere all of the acid gas is processed in the reaction

furnace. According to the Claus reaction, the air neededfor combustion is one-third of that required for thecomplete combustion of H2S. Consequently, the Clausfurnace operates far away from complete combustion inthe straight-through design. A minimum temperature of925°C is generally considered to sustain a stable flame.A higher flame temperature is often required to destroycontaminants when present.

Medium acid gases (10%�H2S�50%) When H2S concentration is low, the stability of

the flame cannot be reached and the straight-through design is no longer a good choice. Thefollowing possibilities must therefore be chosen.



Table 4. Commercial SRU catalysts from Axens (former Procatalyse) and Almatis (former Alcoa), the world's leading suppliers

Name Company Type Activity

DR Axens Activated alumina Active bed support and Claus reaction

SRU ABS

Almatis/Engelhard

Activated alumina Active bed support and Claus reaction

CRCR 3S

AxensMacroporous activated aluminaUltra-macroporous activated alumina

Claus reaction for Claus and subdewpoint TGT (Sulfreen, CBA and MCRC)

DD-431S-400S-100

Almatis/Engelhard

Activated alumina with tailored pore size distribution

Claus reaction for Claus and subdewpoint TGT (Sulfreen, CBA and MCRC)

AA 2-5 Axens Microporous activated alumina Claus reaction for subdewpoint TGT (Sulfreen)

AM Axens Promoted activated alumina Oxygen scavenger and Claus reactions

AM S 31 Axens Promoted activated alumina Oxygen scavenger, Claus and CS2 reactions

S-100 SRAlmatis/Engelhard

Promoted activated alumina Oxygen scavenger

CSM 31 Axens Proprietary promoterSelective hydrogenation catalyst used as a protective layer with streams containing aromatics

DD-831Almatis/Engelhard

Promoted activated aluminaClaus reaction and Resistance to deactivation from sulphation

DD-931Almatis/Engelhard

TiO2 promoted activated alumina Claus reaction, COS, CS2

CRS 31 Axens TiO2 Claus reaction, COS, CS2, HCN*

TG 103 Axens CoMo / alumina Hydrogenation reactions for SCOT-type TGT

TG 107TG 136

Axens CoMo / aluminaLow temperature hydrogenation reactions for SCOT-type TGT

TGS 294TG 732

Axens Proprietary / aluminaAdsorbent catalyst for direct oxidation of H2S to S for subdewpoint TGT (Doxosulfreen)

* also for IGCC cogeneration plants

Acid gas bypass. When part of the feed gas isbypassed, the furnace operates nearer to completecombustion, if one considers the same quantity ofair entering the Claus unit as in the straight-through design. This results in an increased flametemperature. The design is referred to as the split-flow design. The upper limit for acid gas bypass istwo-thirds of feed gas, as the furnace must beoperated under reducing conditions. However, ifcontaminants are present in the feed, they willremain in part and enter directly into the catalyticsection of the Claus. Troubleshooting and/orinstability of the sulphur plant may then occur,since these contaminants highly contribute todeactivation and plugging of the catalyticconverters. Nevertheless, when this solution isapplicable, it is the simplest and most economicalway to treat medium acid gas composition.

Feed preheat. In order to maintain or raise theflame temperature, combustion air preheating andacid gas preheating must be examined. Acid gaspreheating is more difficult to apply when theacid gas is recovered from the amine regeneratorat low pressure. Moreover, corrosion must beproperly checked as thermal cracking of the acidgas constituents may occur. When considering arevamp of an existing straight-through unit,specific attention must be paid to the design ofthe burner in order to avoid corrosion and toenable the use of high temperature gas.

Oxygen enrichment. Oxygen enrichment raisesthe flame temperature by limiting the nitrogeneffect of air. Moreover, this results in reductionsof the equipment size and investment cost, sincethe global flow processed in the sulphur plant islower (Lee and Moore, 1997). Nevertheless, inorder to be applied, this technology requires anavailable and economical source of oxygen. Forthe time being, only low-level enrichments (i.e. upto 28%) are addressed, since they lead to minorchanges at the Claus unit and provide up to a 25%increase in capacity.

Fuel gas addition. Fuel gas can be added toensure a high flame temperature, though this canbring about some disadvantages. Firstly, this willenlarge the size of the sulphur plant and lower thetotal sulphur recovery efficiency. Moreover, itcould provoke catalyst deactivation or converterplugging, thus the consequences of fuel gasaddition on the sulphur recovery unit must becarefully examined.

Lean acid gas (5%�H2S�30%)For this kind of gas, the Claus process is less

competitive because it is difficult to ensure a stable

flame at a low operating cost; consequently, someother technologies are of interest. One method is toreplace the thermal section of the modified-Clausprocess by a catalytic section. Over the catalyst, airoxidizes H2S to SO2, which reacts with additionalH2S to produce elemental sulphur.

Extra-lean acid gases (H2S�5%)Several technologies are proposed depending on

the H2S content and the sulphur tonnage to berecovered. A way to treat extra-lean acid gas isthrough direct oxidation. In this case, the higher theH2S content, the lower the selectivity of thereaction, though the upper limit is around 1.5%H2S. Other processes, including redox processes(wet oxidation, see Section 3.2.4) or non-regenerative processes, achieve very high recoveryefficiency of nearly 100%. Among the redox, someutilize vanadium complex, as does the Stretfordprocess. Others are based on iron chelates: Lo-Cat,Sulferox or Sulfint HP processes. The chemicalconsumption cost limits their application to lowsulphur tonnage (�10 t S/d). When the quantity ofsulphur to be removed is very low (�0.1 t S/d)scavengers may be used. These liquid or solidchemicals selectively react with H2S. Iron-spongeand Sulfatreat caustic scrubbing are part of theseprocesses. They are based on non-regenerativechemicals such as activated carbon, iron oxide,caustic solution or regenerative chemicals (e.g.triazine). The disposal cost for the used chemicalsshould be accurately considered in the globalevaluation of the process.

Claus operating variablesThe overall sulphur recovery efficiency of a

modified-Claus unit is greatly dependent on thedesign, maintenance and operation of the unit.

The most important control variable in theoperation of Claus plants is the ratio of H2S toSO2 in the gases entering the catalytic converters.Maximum conversion requires that this ratio ismaintained constant at the stoichiometricproportion of 2 moles of H2S to 1 mole of SO2.Appreciable deviation from the stoichiometricratio leads to a drastic reduction in conversionefficiency. Several methods, based on controllingthe air flow by continuous analysis of the ratio ofH2S to SO2 in the plant tail gas, have beendeveloped and are used ever more frequently.Several analytical instruments based on vapourchromatography and ultraviolet absorption areavailable commercially.

In addition, it is very important to operate thedifferent catalytic converters at the right


SULPHUR CYCLE

temperature (Bohme and Sames, 1999). Forexample, the condensation of elemental sulphuron the catalytic converters can be avoided bymaintaining their temperature above the sulphurdewpoint of the gas mixture.

When the feed gas contains contaminants, ahigher flame temperature is often required todestroy them. Ammonia, heavy hydrocarbons,BTX, mercaptans and cyanides are among thecontaminants most often encountered.

As regards ammonia, it is typically providedby the off-gas of the SWS of the refinery. TheClaus unit is considered the best place to destroythis off-gas, which also contains H2S, thanks toits high furnace temperature. NH3 must bedestroyed in the reaction furnace, otherwisesulphur trioxide (SO3) can form due to thefollowing reactions:

[21] 2NH3�5/2O2�� 2NO�3H2O

[22] 2NO�O2�� 2NO2

[NO2][23] SO2�� SO3

SO3 causes severe downstream problems likecorrosion, catalyst deactivation and salt formation.Two methods are available to successfully destroyNH3 using the following reaction:

[24] 2NH3�3/2O2�� N2�3H2O

The first method involves a split-flow reactionfurnace design; the second requires a high-intensity reaction furnace burner. It is essentialfor NH3 to be almost completely destroyed, beingthat ammonia concentrations even as low as500-1,000 ppm by volume (ppmv) can causeproblems.

As for BTX and heavy hydrocarbons, acid gasmay contain these compounds since solvent unitsare able to co-absorb them together with H2S.Feed stream must be analysed and the necessarymeasures must be taken to keep them fromentering the Claus catalytic section, as they maycause catalyst deactivation, plugging and off-specification sulphur for market purposes (e.g.green sulphur compared to bright yellow sulphur).When acid gases of high H2S content areprocessed, the temperature in the reaction furnaceis usually high enough to result in the completecombustion of all hydrocarbons to CO2 and water,and no carbonaceous material deposition isexperienced. However, at the low combustiontemperature occurring in straight-through plants,processing gases with less than approximately 40-50% H2S, cracking and partial combustion of

hydrocarbons produce complex carbonaceousmaterials that are carried into the catalyticreactors, gradually deteriorating catalystperformance. In addition, hydrocarbons can befed directly to the first catalytic converter withoutbeing burned when a split-flow design is utilized.These hydrocarbons can also cause catalystdeterioration.

Regarding mercaptans and cyanides, the samegeneral considerations must be applied for theClaus unit. For other processes, such as redox orscavenger processes, problems connected tochemical odours and disposal must be carefullyconsidered.

3.2.4 Tail gas treatment

The modified-Claus process has continuallyimproved since 1940. However, this process cangenerally achieve only up to 98% sulphurrecovery for a three-stage configuration. Withnew environmental requirements, sulphurrecovery efficiencies of 98.5-99.95% are nowrequired. Regulations differ from country tocountry and may even vary between differentregions within the same country:• In Canada, plants with a capacity of 50 t S/d

should achieve a total sulphur recovery of98.5%, increasing to 99% for plants with acapacity of 2,000 t S/d.

• In Europe, the 1998 ‘bubble concept’ for SO2emissions is often applied, whereby all SO2emission sources in one refinery can bepooled and the total SO2 emission limit of1,700 mg/Nm3 should be met in the flue gas.This emission limit will be reduced in thecoming decades. In Germany, strictregulations (TA-Luft) are in place and requiresulphur recoveries of 99.8% for plants with acapacity of 20-50 t S/d and 99.5% for plantswith capacities over 50 t S/d.

• Japan requires recoveries over 99.8% andTaiwan demands levels as high as 99.95%.

• In the United States, it depends on theindividual state. For example, in Texasrefineries, for new facilities, the recovery mustbe between 96 and 99.8%, depending on thesulphur production capacity. However, itseems that 99.9% recovery efficiency isbecoming a regulatory standard for sulphurrecovery plants with a capacity of 20 t S/d orgreater.Thus, the modified-Claus process has to be

supplemented with another process designed to



remove residual sulphur compounds from theClaus plant tail gas. Processes of this sort areusually called Tail Gas Cleanup (TGC) or Tail GasTreating (TGT) processes. The TGT processes,which have achieved commercial status(Connock, 1998, 2003; Keeping […] 1994), canbe categorized into six groups (Table 5). The mostimportant TGT processes are described asfollows.

Wet subdewpoint processes: Clauspol processesThe Clauspol process was one of the first

TGT processes to be developed. More than 40Clauspol units, ranging from 25-700 t S/d(single train), have been licensed worldwide

since 1971. The Clauspol process (Fig. 10) isbased on the continuation of the Claus reaction[12] between the residual H2S and SO2 presentin Claus tail gas, in a non-volatile liquid organicsolvent containing a proprietary catalyst(Barrère-Tricca et al., 2000). The reaction isperformed at a temperature slightly above thesulphur melting point (120-130°C). Theproduced sulphur (99.9% pure bright yellow) isonly slightly miscible with the solvent and, dueto its higher density, is recovered as a separateliquid phase from the bottom of the reactor,shifting the Claus reaction equilibrium veryfavourably. There are other sulphur componentsthat are advantageously removed from Claus tail


SULPHUR CYCLE

Table 5. Main tail gas treatment (TGT) processes

Category Process name Sulphur recovery (%) Licensor

Wet subdewpoint Clauspol IIClauspol Booster 99,9�

99.0-99.899.9�

Prosernat, FranceProsernat, France

Dry subdewpoint SulfreenHydrosulfreenDoxosulfreenCBAMCRCClinsulf-SDP

99.0-99.599.7

99.8-99.999.3-99.4

99.099.4

Total, France / Lurgi, Italy / Prosernat, FranceTotal, France / Lurgi, Italy / Prosernat, FranceTotal, France / Lurgi, Italy / Prosernat, FranceBP Amoco, USADelta Hudson Engineering, CanadaLinde, Germany

Reduction to H2S� H2S scrubbing

� direct oxidation

� subdewpoint� wet oxidation

SCOTSuper SCOTLS-SCOTSultimateBSR/MDEASulftenResulfResulf-10RAR‘Flexorb SE Plus’ amineHCRBSR/SelectoxMODOPBSR/Hi-ActivityUltraBSR/StretfordBSR/Unisulf

99.999.95�99.95�99.95�99.9�99.9�99.999.95�99.9�99.9�99.95�99.5

99.3-99.599.599.799.999.9

Shell Global Solutions, NetherlandsShell Global Solutions, NetherlandsShell Global Solutions, NetherlandsProsernat, FranceParsons Energy & Chemicals Group Inc., USAFB&D Tech, USA / Union Carbide Corporation, USATPA, USATPA, USATechnip KTI SpA, ItalyExxon Mobil, USASiirtec Nigi, ItalyParsons Energy & Chemicals Group, USAExxon Mobil, USAParsons Energy & Chemicals Group, USABP Amoco Corporation, USAParsons Energy & Chemicals Group, USAParsons Energy & Chemicals Group, USA

Dry oxidation to S Superclaus 99.0-99.5 Jacobs Engineering, Netherlands

Wet oxidation to S Sulfint/Sulfint HPLO-CAT/LO-CAT IISulferox Crystasulf Thiopaq

99.99�99.99�99.99�99.99�99.99�

Prosernat, France / Le Gaz Intégral (LGI), FranceGasTechnologyProducts-Merichem, USAShell Global Solutions, Netherlands / LGI, FranceCrystaTech, USAPaques BV, Netherlands / Shell Global Solutions,Netherlands

Oxidation to SO2 �SO2 scrubbing

Wellman LordClintoxElsorb/Labsorb

99.9�99.9�99.9�

Kvaerner Process Technology, UKLinde, GermanyBelco Technologies, USA

gas in the Clauspol unit (e.g. entrained liquidsulphur, sulphur vapour, COS and CS2, which are partially hydrolysed). The basicClauspol II process allows sulphur recoveries upto 99.8%, provided that COS and CS2have been hydrolysed down to 300 ppmv ofsulphur or less in the catalytic stages of theClaus plant, by using a TiO2-based catalyst. TheClauspol process is a very simple andcontinuous process. It requires neither hydrogennor blower and there is no recycling of H2S backto the Claus unit. Investment and operating costsare low, making the Clauspol II process thecheapest TGT technology available on themarket from 99.4-99.8% sulphur recoveries.Under normal conditions, the carbon steelcorrosion rate in Clauspol units is avoided byapplying simple rules regarding the design,construction and operation of the unit (Barrère-Tricca et al., 2000).

The latest main developments of the Clauspolprocess are described below.• The Clauspol II process circulates a sulphur-

saturated solvent that contains small amountsof liquid sulphur. The liquid sulphur vapourpressure, though low, contributes to sulphurlosses in the effluent from 350 ppmv With itsdesaturation loop, the Clauspol Booster 99.9�process eliminates the liquid sulphur phase inthe solvent and circulates an unsaturatedsolvent. This allows sulphur recoveries of over99.9%.

• The desalter has been recently developed toprevent the accumulation of solid salts on thereactor packing.The desaturation loop and the desalter treat

only a fraction of the solvent from therecirculation loop. They are small, simple, easy toinstall on existing units and easy to operate. Theycan be shut down without shutting down the basicClauspol II section.

Dry subdewpoint processes: Sulfreen processesThe Sulfreen process (Willing and Linder,

1994) was developed in the early 1970s. There aremore than 50 references worldwide ranging from10-2,200 t S/d (single train). The Sulfreen process(Fig. 11) is based on the continuation of the Clausreaction [12], between the residual H2S and SO2present in Claus tail gas, on a dry catalytic bed atlow temperature (120-150°C). Activated aluminais used as the catalyst. The Sulfreen processproduces 99.9% pure bright yellow sulphur. TheClaus reaction is extended and the sulphurrecovery enhanced. This occurs, firstly, because

the equilibrium is thermodynamically favoured atlow temperature and, secondly, since the sulphuris adsorbed on the catalyst. The Sulfreen processbasically consists of two (occasionally three forlarge capacities) Sulfreen reactors in series withthe Claus reactors. As the sulphur accumulates onthe catalyst, its activity decreases and the catalystbeds have to be regenerated thermally at 250-300°C. During the regeneration step, sulphuris desorbed and the catalyst is restored to fullactivity by part of the preheated TGT gas. Onceregeneration is achieved, the catalyst bed iscooled to the operating temperature. Sulphur fromthe hot regeneration stream is then condensed.Typical overall sulphur recoveries are in the 98.5-99.5% range, depending on the Claus unitarrangement. COS and CS2 are not hydrolysed.Two enhanced versions of the Sulfreen processare also available and enable higher sulphurrecoveries to be reached.

The Hydrosulfreen process is based on thepre-treatment of the Claus tail gas by hydrolysisof COS and CS2 to H2S and direct oxidation ofH2S into elemental sulphur. These reactions are performed by contacting theClaus tail gas with a TiO2-based catalyst at about300°C. This pre-treatment is followed by a basicSulfreen reactor. A Claus plant with two catalyticstages and a Hydrosulfreen unit can achieve anoverall sulphur recovery efficiencyof over 99.5%.

The Doxosulfreen process is based on a post-treatment after a Sulfreen unit or an



gas/liquidcontactor

solventtemperaturecontrol

catalystmake-up

Claustail gas

gas to incinerator

liquid sulphur

120-130°C

Fig. 10. Clauspol II process scheme.

Hydrosulfreen unit. The upstream units areoperated to get a slight excess of H2S in order toreach a nearly total SO2 conversion on theSulfreen reactor. Therefore, the remaining H2S atthe outlet of the Sulfreen reactor is oxidized withair to elemental sulphur at a low temperature(100-130°C). Both Sulfreen and oxidationreactors are regenerated through a commonregeneration loop. The oxidation catalyst is basedon copper and optimized special alumina. The Doxosulfreen process is capable of reaching an overall sulphur recovery of up to 99.9%.

Reduction to H2S plus H2S scrubbingAn entire family of TGT processes exists

based on the reduction of sulphur compounds toH2S, followed by H2S scrubbing, and recycling ofthe H2S stream to the Claus unit. The SCOTprocess was the first to be developed and is themost widespread, with more than 200 unitsconstructed all over the world since 1973, andwith single train capacities of up to 2,500 t S/d.The other TGT processes of this family(Sultimate, BSR/Amine, Resulf, RAR, ARCO,HCR, etc.) are more or less designed and operatedin accordance with the SCOT concept (van denBrand and Roos, 2002). The Claus tail gas isheated to about 300°C using a heat exchanger orin-line burner (Fig. 12). The heated gas is mixedwith a reducing gas containing hydrogen andpasses through a fixed bed of CoMo/aluminacatalyst or NiMo/alumina catalyst, where allsulphur components are converted into H2S. Twotypes of reactions occur: hydrolysis andhydrogenation. The tail gas leaves the

hydrogenation reactor at a temperature ofapproximately 320-340°C and is cooled in twostages. The hot gases are cooled to about 160-200°C by passing through the tube-side of ashell-and-tube heat exchanger or waste heatboiler. The gas is then further cooled to 40°C bydirect contact with circulating water in a quenchtower. During gas cooling, most of the watervapour contained in gas is condensed and mixedwith the circulating water. Since the circulatingwater is in a closed loop system, the condensedwater must be removed from the system tomaintain a constant water level in the tower. Thewater leaving the system contains a few ppm ofH2S and is typically recycled to the SWS unit forH2S recovery. The cooled gas leaves the top of thequench tower and is sent to the absorber, where itis washed counter-currently with a lean H2Ssolvent. Various types of solvent can be employed,but a selective amine is normally used (e.g.MDEA). The choice of the solvent depends on thetail gas composition (see Section 3.2.2). Thedownward flowing solvent contacts the upwardflowing gas and absorbs nearly all of the H2S andsome CO2 when present. The absorber off-gastypically contains 150 ppmv of H2S or less and issent to the Claus incinerator. The rich solventleaving the absorber bottom is pumped through alean/rich solvent regenerator, where the H2S (andeventually CO2) are removed by steam stripping.Acid gas from the regenerator is recycled to theClaus thermal stage. Lean solvent from theregenerator is returned to the absorber.

The aims of developments in recent years wereto lower the total sulphur content of the emissionsto less than 50 ppmv (comparable to 99.95% total


SULPHUR CYCLE

250-300- °0°CC 120-1- 050°0 C

to incinerator

Sulfreen reactors

blower sulphur

condenser

heater

Claus tailgas

fuelgas

air

Fig. 11. Sulfreenprocess scheme.Regeneration step:S is removedby vaporizationin hot tail gas. Reaction step: H2S and SO2 react on theSulfreen alumina catalyst,produced S is adsorbed.

sulphur recovery) and to significantly reduceinvestment and operating costs.

In order to reduce capital costs, it is possibleto use a common amine regeneration section forthe TGT unit as well as for the existing aminedesulphurization unit. To reduce operating costs,it is also possible to use the solvent in cascadefrom the TGT unit to the other sweetening units.New catalysts enable operation of thehydrogenation step at lower temperatures (220°Cor below, depending on inlet gas composition),greatly reducing energy consumption andavoiding in line burners with their drawbacks(soot deposit for some of them).

The total sulphur content of the emissions issignificantly lowered thanks to the followingfactors.• Absorption is improved by using a lower lean

solvent temperature, the solubility of H2S inamine solvents decreasing with temperature.

• Stripping is improved utilizing a two-stageregeneration, in which part of the aminesolvent flow is more deeply stripped. Thesuper-lean solvent is routed to the top tray ofthe absorber, while the semi-lean solventcomes in half way down the absorber.

• Inexpensive additive (i.e. strong acid) to theamine solvent improves its regeneration,

producing either a better solvent leanness,thereby a lower off-gas H2S specification, orthe same solvent leanness with less steam.

Wet oxidation: redox processesRedox processes allow direct oxidation of H2S

into elemental sulphur at ambient temperature,with nearly 100% selectivity and conversion.Redox processes are usually highly flexible andare being used on a wide variety of H2Scontaining gases, including gas from acid gasenrichment units and from the Claus unit,provided that the gas is mainly H2S (Nagl, 2001).The main limitations of current redox processesare their relatively high chemical costs, thequality of the sulphur product, which is generallynot as pure as Claus sulphur and, for someapplications, the difficulty in directly treatinghigh pressure gases.

In redox processes, the H2S containing gas iswashed with a solution containing a redoxcatalyst. In a first step, the aqueous solutionabsorbs the H2S, which then reacts with theoxidized form of the catalyst to yield elementalsulphur as the catalyst is converted into itsreduced form. In a second step, the reduced formof the catalyst is contacted with air and oxidizedprior to reuse. Redox catalysts are usually



LPsteam

heater

quenchand cooling

tower

finalaminescrubber

amineregeneration

waste waterto treatment

(SNS)

to incinerator

cooler

reductionreactor

air

naturalgas

Claustail gas

reducinggas

to Claus thermal stageFig. 12. Sultimateprocess scheme.

polyvalent metallic cations chelated with organicligands. The former vanadium salts used in theStretford process have now been replaced in allmajor redox processes by iron complexes basedon Ethylene Diamine Tetra Acetic acid (EDTA),Hydroxyethyl Ethylene Diamine Tri Acetic acid(HEDTA) or Nitrilo Tri Acetic acid (NTA)(McManus, 1998; Heguy and Nagl, 2003).

The main chemical reactions are:

[25] H2S�2Fe3�� S�2Fe2��2H�

[26] 2Fe2��2H��1/2O2�� 2Fe3��H2O

[27] global reaction: H2S�1/2O2�� S�H2O

Usually the two distinct steps of the process,which are H2S oxidation [25] and Fe2� oxidation[26], are performed in separate vessels; the redoxsolution is circulated between the two. Absorptionis performed at the pressure of the gas to be treatedand regeneration or oxidation of the solution isconducted at atmospheric pressure. The elementalsulphur forms nearly instantaneously in theabsorber vessel when the sour gas comes in contactwith the oxidized solution. Solid sulphur is thenseparated from the solution (flotation, filtration,centrifugation, etc.), generally under atmosphericpressure. The recovered sulphur is contaminatedwith the iron catalyst and degradation productscomposed of organic and inorganic salts. In order toproduce Claus quality sulphur, this sulphur needs tobe treated by water washing and/or smelting. Theorganic ligands used in the catalytic solution areslowly oxidized during process operation. Acontinuous catalyst make-up prevents an efficiencydecrease due to degradation and catalyst losses inthe sulphur product. Chemical cost is usually in therange of several hundreds of US dollars per ton ofsulphur produced and is the most important factorin the overall treatment cost. Since iron basedcatalyst and its degradation products are non-toxicand/or easily biodegradable, the ‘redox’ sulphurwill generally be easily disposed in landfills, or soldfor agricultural use as fertilizer.

As previously shown, the most common methodfor high pressure gas desulphurization remains H2Sextraction with an amine unit, followed by a Clausunit or a low pressure redox unit; thedepressurization of this mixture, prior to theatmospheric air oxidation step in the redox process,can lead to severe foaming and plugging problems.Despite these difficulties, the direct treatment ofhigh pressure gases with redox processes remainsattractive as up to 50% investment savings could begained, as compared to conventional methods (LeStrat et al., 2001). In the Sulfint HP process, sulphur

particles are then removed from the solution beforeits depressurization, thanks to a continuous high-pressure filtration. Dissolved gas, which is low foraqueous solution compared to organic solvents,easily separates in a flash drum; moreover, foamingtendency is tremendously reduced, as no sulphurparticles are found down the filter.

Other processes, such as Crystasulf, are basedon organic solvent that facilitates larger sulphurcrystals at the price of solvent coabsorption.

Dry oxidation: SuperclausThe Superclaus process (Lagas et al., 1989) was

introduced to the industry in 1988 as a newdevelopment of the Claus process. More than 70 unitshave been licensed worldwide, ranging from 3-1,000 t S/d. The Superclaus unit consists of a thermalstage, followed by three catalytic stages with sulphurremoval by condensation between each stage. Tworeactors are filled with standard Claus catalysts, whilethe third reactor is filled with a proprietary selectiveoxidation catalyst known as Superclaus catalyst(Fe2O3 on silica support for the last generation). Thethermal stage is operated under oxygen-deficientconditions, in so that the H2S/SO2 ratio in the furnaceis much higher than the conventional 2:1. As a result,the second catalytic reactor outlet gas contains a largeexcess of H2S over SO2. In the last catalytic reactor(i.e. the Superclaus reactor), the catalyst oxidizes theH2S to elemental sulphur (reaction [13]) with anefficiency of over 85%. The Superclaus reactortemperature must be between 200 and 300°C in orderto avoid sulphur vapour condensation and oxidation ofthe gas phase. No reverse Claus reaction betweensulphur and water to form H2S and SO2 may occur. Inaddition, COS and CS2 are not hydrolysed. A totalsulphur recovery efficiency of up to 99% can beobtained with the Superclaus-99.

Attaining over 99% requires a third Claus reactorand/or a hydrogenation/hydrolysis step, prior to theselective oxidation step. For instance, the Superclaus-99.5 process includes such ahydrogenation/hydrolysis step. Since the selectiveoxidation catalyst is not sensitive to water, there is noneed to condense water downstream of thehydrogenation reactor. In such a case, sulphurrecoveries range from 99-99.5% (for rich H2S feeds).

Oxidation to SO2 plus SO2 scrubbingThe basic principle behind these processes lies

in the incineration or catalytic oxidation of Claustail gas streams to convert all sulphur species toSO2, followed by SO2 scrubbing and recycle ofthe SO2 stream to the Claus unit. The totalcapacity of the Claus process is thus increased.


SULPHUR CYCLE

These processes can achieve an extremely highsulphur recovery of over 99.9%. The maindifference between the processes resides in thedifferent scrubbing mediums employed to removeSO2 (Table 6). Established SO2 recovery systemsfor Claus incinerator tail gas include the WellmanLord process (Keeping […] 1994) and the Clintoxprocess. In recent years, there has been stronginterest to develop new processes of this type(Connock 1999a; SO2 removal […] 2004):Cansolv, ClausMaster, Labsorb (based on theElsorb), Clausorb, and Turbotak.

3.2.5 Safety and environmentalissues

Liquid sulphur produced in the modified-Clausprocess contains 150-400 ppm wt of residualhydrogen sulphide in the form of both dissolvedhydrogen sulphide (H2S) and hydrogenpolysulphides (H2Sx) in equilibrium with sulphur.H2S/H2Sx equilibrium is temperature dependent: at 130°C, H2S/H2Sx�10, and at150°C, H2S/H2Sx�1.

The decomposition of H2Sx to elementalsulphur is a very slow reaction:

[28] H2Sx (liquid)��H2S (dissolved)�

(x�1)S (liquid)

H2S dissolved in the liquid phase passes intothe gaseous phase by physical desorption:

[29] H2S (dissolved)��H2S (gas)

The H2S content in the atmosphere becomesprogressively more dangerous above 50 ppmvand is even lethal at 600 ppmv. The lowerexplosion and flammability limit of H2S is

approximately 3.5% by volume at 150°C in air.During handling, storage and transportation,when sulphur is agitated and cooled, H2S isreleased from the sulphur. The H2S concentrationin the surrounding atmosphere can reach toxiclevel, fire and explosion limits. Therefore, theindustry must produce liquid or solid elementalsulphur with a maximum value of 10 ppm wt ofhydrogen sulphide (H2S � H2Sx). Liquid sulphurshould be degassed for the following mainreasons: a) safe storage and transportation ofliquid sulphur; b) safer working conditions forpersonnel handling liquid sulphur; c) lesscorrosion in sulphur storage tanks, transportpiping and road tankers/ships; d) lower hydrogensulphide emissions into the atmosphere; e) highersulphur strength thanks to the formation ofpolymeric form of sulphur Sx; the solid sulphurproduced from undegassed liquid sulphur is morefriable.

The principle of the degasification processesof liquid sulphur is to release the dissolved H2Sgas and to accelerate the decomposition of theH2Sx to H2S. The release of the dissolved H2S isobtained by agitation of the liquid sulphur. Thedecomposition of the H2Sx to H2S can beaccelerated by means of a catalyst, reducing theenergy consumption and the equipment size. Thereleased H2S gas must be removed from the gasspace above the sulphur by flushing with a sweepgas (air, Claus tail gas or inert gas). Air seems tobe the best sweep gas. Indeed, tail gas stillcontains residual H2S, therefore the degassingrate is reduced because the H2S available in theliquid sulphur tends to be in equilibrium withH2S in the gaseous phase. Air contributes todegassing by promoting the direct oxidation ofH2S to elemental sulphur through oxygen. Using



Table 6. SO2 scrubbing processes

Process name Scrubbing medium Licensor

Wellmann Lord Sodium sulphite solution Kvaerner Process Technology

Clintox Physical absorbant (glycol ether based) Linde

Labsorb/ElsorbInorganic aqueous solution made from caustic and phosphoric acid (sodium phosphate buffer)

Belco Technologies

Cansolv Proprietary aqueous diamine solvent Cansolv Technologies

ClausMaster Dibutyl butyl phosphonate Monsanto Enviro-Chem Systems

TurbotakDow Chemical’s proprietary Turbosox amine-based sorbent

Turbosonic Technologies

ClausorbCentaur activated carbon, a proprietary catalystdeveloped by Calgon Carbon

Parsons Energy & Chemicals Group

air as sweep gas prevents accumulation ofpyrophoric iron sulphide (FeS) formed on carbonsteel surface by reaction with H2S. Thisaccumulation generally occurs when using inertgas sweeping. The physical desorption ofdissolved H2S shifts to the right the equilibriumof reactions [28] and [29]. Sweep gas quantityshould be designed in such a way that the H2Sconcentration is 1.5% by volume, maximum.

Several sulphur-degassing processes have beendeveloped. The first widely implemented is theAquisulf process (Nougayrede and Voirin, 1989),with more than 45 references from 15-1,200 t S/d(single train). This process is based on thefollowing two principles: mechanical degassingby agitation and pulverization to favour gas-liquidcontact; chemical degassing by catalyst injectionto speed up the decomposition of H2Sx.

The Aquisulf process is available in batch andcontinuous versions. In the continuous version(Fig. 13), the liquid sulphur pit consists of two ormore compartments. The sulphur in the firstcompartment is pumped and mixed with thecatalyst and sprayed back into the compartment.The liquid sulphur overflows from a weir to thesecond compartment. The liquid sulphur is againpumped and sprayed in this tank to provide moreagitation. The original catalyst wasNH3. However, problems associated withammonium salts have resulted in thedevelopment of a proprietary Aquisulf liquidcatalyst, which does a better job than NH3 ofdecomposing the H2Sx and does not result insolid salt formation. Other degassing processesare available, such as D’CAASS (Fenderson andAllison, 2000), HySpec and MAG.

References

Barrère-Tricca C. et al. (2000) Thirty years of operatingexperience with the Clauspol process, in: Sulphur 2000.Proceedings of the international conference, San Francisco(CA), 29 October-1 November.

Bohme G., Sames A. (1999) The seven deadly sins of sulphurrecovery, in: Sulphur 99. Proceedings of the internationalconference, Calgary (Alberta), 17-20 October.

Bonis M. et al. (2004) A critical look at amines. A practicalreview of corrosion experience over four decades, in:Proceedings of the Gas processors association annualconvention, New Orleans (LA), 14-17 March.

Brand K. van den, Roos I. (2002) Shell’s new low-costSCOT process, in: Sulphur 2002. Proceedings of theinternational conference, Wien, 27-30 October.

Chasing the elusive last 1 or 2 %. (Claus sulphur recoveryprocess used in petroleum refineries) (Special reports:sulphur recovery in refineries) (1997), «Sulphur»,September-October, 41-47.

Clark P.D. et al. (2002) How do Claus catalysts really work?,in: Proceedings of the 52nd Laurance Reid Gas conditioningconference, Norman (OK), 24-27 February, 153-176.

Connock L. (1998) Approaching the limit: 99.9+ % sulphurrecovery, «Sulphur», July-August 34-55.

Connock L. (1999a) New SO2 scrubbing technologies abound.(Special reports: refinery sulphur), «Sulphur», July-August,53-56.

Connock L. (1999b) Understanding your Claus reactionfurnace, «Sulphur», January-February, 34-42.

Connock L. (2003) Enhanced sulphur recovery, «Sulphur»,May-June, 29-39.

Fenderson S., Allison T. (2000) Sulphur degassing retrofitmade easy with the D´GAASS process, in: Sulphur 2000.Proceedings of the international conference, San Francisco(CA), 29 October-1 November, 247-261.

Heguy D.L., Nagl G.J. (2003) Consider optimized iron-redoxprocesses to remove sulphur, «Hydrocarbon Processing», 82, 53-57.

Heinrich G., Kasztelan S. (2001) Hydrotreating, in:


SULPHUR CYCLE

ejector

1st compartment 2nd compartment

LP steam to incinerator

catalyst injection

degassed sulphurto storage

sulphur fromClaus plant�TGT unit

sweep gas(inert/tail gas)

levelcontrol

Fig. 13. ContinuousAquisulf scheme.

Leprince P. (edited by) Conversion processes, Paris, Technip,533-573.

Keeping abreast of the regulations. (Sulphur emissionsrestrictions) (Improved claus sulphur recovery) (1994),«Sulphur», March-April, 35-59.

Kent R.L., Einsenberg B. (1976) Better data for aminetreating, «Hydrocarbon Processing», 55, 87-90.

Lagas J.A. et al. (1989) Claus process gets extra boost,«Hydrocarbon Processing», April, 40-42.

Lallemand F. et al. (2004) A new look at amines. Extendingthe gas industry ‘workhorse’to new limits, in: Proceedingsof the Gas processors association annual convention, NewOrleans (LA), 14-17 March.

Lecomte F. et al. (2003) Hybrisol, a new gas treatment processfor sour natural gases, in: Proceedings of the LauranceReid Gas conditioning conference, Norman (OK), 25-27February, 281-310.

Lee C.H., Moore A. (1997) Oxygen enhanced Clausoperation. A case study, «Petroleum Technology Quarterly»,July, 73-75.

Le Strat P.Y. et al. (2001) New redox process successful inhigh pressure gas stream, «Oil & Gas Journal», November,26, 46-53.

McManus D. (1998) Hydrogen sulphide removal from gasstreams using homogeneous chelated iron oxidationcatalysts, in: Proceedings of the Gas processors associationEuropean chapter meeting, London, 18 February.

Meyer B. (1976) Elemental sulfur, «Chemical Reviews», 76,367-388.

Nagl G. (2001) Liquid redox enhances Claus process,«Sulphur», May-June, 1-6.

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Willing W., Linder T. (1994) Lurgi’s TGT processes andnew operational results from sulfreen plants, in: Sulphur1994. Proceedings of the international conference, Tampa(FL), 6-9 November.

Jean-Pierre Ballaguet Cécile Barrère-Tricca

Institut Français du PétroleVernaison, France



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