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The sour gas of natural gas, refinery fuel gas, petro-chemical industry and synthesis gas of purificationplants contains substantial amounts of acid gases

such as CO2, H2S, COS and RSH. The bulk removal ofthese gases is more conventionally handled by absorptioninto different chemical solvents.

The alkanolamines have been widely used since 1930when the amine unit configuration, based on phenylhy-drazine as an absorbent, was developed and patented inthe USA. Improvements of this process basically includednew alkanolamines and plant design development.

This fundamental discovery was later improved byusing alkanolamines as solvents. Besides the alka-nolamine process, selexol, hot carbonate and otherprocesses have traditionally been used for treating thesesour gases and tail gases of sulfur plants.

This article is devoted to the newly developed andpatented HIGHSULF™ concept of absorption/desorptiongas sweetening processes based on amine or any otherselective solvents. Results of computer runs comparingthis new process and conventional processes for aminegas sweetening and tail gas treating are discussed.

Amine gas sweetening processH2S concentration in the feed gas of the Claus sulfurrecovery units has an important influence on the compli-cated chemical reactions that are involved in the hydro-gen sulfide oxidation processes in the thermal reactor athigh temperature and in the catalytic reactors atthe moderate temperatures. The efficiency ofhydrogen sulfide oxidation reaction and sulfurrecovery increases at higher hydrogen sulfideconcentrations in the feed of sulfur recovery unit(Figures 1 and 2). The higher hydrogen sulfideconcentration combined with lower hydrocarbonand CO2 concentration in the sulfur plant feed,generate tail gas with less mass flow.

There are known correlations between H2Sconcentration, hydrocarbon and CO2 content inthe feed and the initial investment cost of the sul-fur plant and tail gas treating unit. In fact, thecombustible contaminants mentioned aboveaffect both the installed and operating costs. Anydiluents such as N2 or CO2, increase the plantcost because most of the sulfur recovery equip-

ment is sized on the basis of mass flow. Thus the majorequipment and process piping increases in size, causingthe overall investment to increase.

In the case of gas processing plants, there can be highconcentrations of hydrocarbons in the feed gas. Thesehydrocarbons generate COS and CS2 in the thermal stageof the Claus unit and an undesirable mass of CO2.

The flow diagram of a typical amine gas sweeteningprocess is shown in Figure 3. Feed gas absorbed in theabsorber generates rich amine, which is sent to theregenerator column to regenerate lean amine. All acid gasobtained in the top of the regeneration column is used asa feed of Claus sulfur recovery unit.

Tofik K. Khanmamedov,TKK Company, USA, analyses a new family of processes developed specifically to improve the

efficiency of amine gas sweetening and tail gas treating.

Figure 1. Equilibrium conversion of hydrogen sulfide to sulfur in Claus reaction.

Table 1. Acid gas composition of regular and HIGHSULFTM amine unitsGas plant acid Acid gas composition, mole %gas components Regular amine unit, HUGHSULFTM amine

MDEA unit, MDEAH2S 33.10 46.20CO2 57.30 47.10H2O 8.53 6.40Hydrocarbons 1.07 0.3Gasifier plant Acid gas composition, mole %Acid gas components regular amine unit,MDEA HUGHSULFTM amine unit, MDEAH2S 11.68 24.78CO2 79.11 68.42CO 1.76 0.23H2O 6.40 6.38COS 0.05 -H2 0.996 0.19CH4 0.004 -

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The patented concept uses the same equipmentshown in Figure 3. The feed gas stream of the absorber isenriched by the hydrogen sulfide of the acid gas.Therefore, the gas enriched with H2S is fed to theabsorber with higher partial pressure of H2S than in rawgas inlet stream. A physical solvent, at relatively highpressure, may be used for processing natural gas toremove CO2, H2S, COS and CS2. A chemical solventwould be used for the process of removing (absorbing)H2S and CO2 from feed streams in gas processing plantsor refineries operating at relatively low pressures.Residual, unabsorbed gas, with minimal target contami-nate content, is discharged from the absorber overheadand target contaminate enriched solvent stream is dis-charged from the absorber bottom, before passingthrough a lean/rich solvent heat exchanger to enter theregenerator as a heated rich solvent stream. In the regen-erator, the heated rich solvent stream gives up theabsorbed acid gases, which are discharged through theregenerator overhead condenser as the target contami-nate rich overhead gas stream. Contaminate lean solventstream is returned to the absorber at a reduced tempera-ture after passing through heat exchanger and cooler. Aportion of the regenerator overhead gas stream is passedthrough a cooler and recycled to the absorber, while theremaining target contaminate rich gas stream is passed tothe next process step. A compressor, controlled byprocess input signal, is required in applications having aninlet pressure higher than the discharge pressure atregenerator overhead cooler. Otherwise, the respectiveflowrates of streams to the sulfur plant and in the recycleline are governed by fixed or variable flow restrictions,which according to the designer’s choice, may be imple-mented by selective line sizing, flow restrictions or controlvalves. The possible increased capital cost of a typicalgas sweetening unit is more than offset by the reduced

size, cost and efficiency of the downstream sulfur recov-ery unit. The HIGHSULFTM process increases the concen-tration of H2S and reduces hydrocarbons in the acid gas.

For a typical natural gas processing plants with lowH2S concentration in the natural gas, HIGHSULFTM yieldsacid gas with higher H2S concentrations than can beachieved using conventional amine treatments.

Table 1 compares acid gas compositions using con-ventional amine treatment and the patented process. Ascan be seen from these computer simulation results, theH2S concentration in acid gas is 39% greater than in con-ventional amine treatments. Hydrocarbon content in acidgas reduced by 72%.

In other applications, as in the case of gasifier Table 1,H2S enrichment is greater than 100% and hydrocarbonsand hydrogen content is significantly reduced. In the caseof natural gas plants with a high CO2/H2S ratio in the feedgas, H2S enrichment is greater than 54%.

As mentioned above, combustible contaminants in theClaus feed greatly increase the initial cost of the unit,since oxygen has to be supplied for burning these com-ponents. For instance, a mole of methane requires threetimes as much oxygen as does a mole of hydrogen sulfidein feed, and a mole of propane in the Claus unit feedrequires seven times as much as does a mole of hydro-gen sulfide. Since oxygen is usually supplied as air, thediluent effect of nitrogen amplifies the effect of the extraoxygen requirement. Both the air blower and its driversize increases, as well as the other Claus unit equipment,because the combustion products such as CO, CO2 andH2O add to the plant cost. Obviously if new equipment isrequired, the initial installed cost rises. The presence ofthe combustible contaminants in the Claus unit feed defi-nitely reduces the overall sulfur recovery.

The main advantages of HIGHSULFTM concept foramine gas sweetening units are:

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Figure 2. Equilibrium conversion of hydrogen sulfide to sulfur vs. temperature vs. concentration.

Table 2. Material balance of HIGHSULFTM TGTU (amine section) Absorber feed Absorber offgas Acid gas to SRU

N2 225.873 225.864 0.009H2S 4.332 0.016 4.316H2 20.046 20.045 0.001CO2 59.446 52.842 6.610H2O 38.280 12.101 0.751CH4 0.177 0.177Total mole/h 348.154 311.045 11.687Total kg/h 4455.9 4043.5 204.01

Table 3. Material balance of conventional TGTU (amine section)Absorber feed Absorberoff gas Acid gas to SRU

N2 225.873 225.848 0.025H2S 4.332 0.015 4.317H2 20.046 20.043 0.003CO2 59.446 44.894 14.552H2O 38.280 11.681 1.306CH4 0.177 0.177

Total mole/h 348.154 302.658 20.203Total kg/h 4455.9 3881.1 368.3

Figure 3. Amine gas sweetening process.

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� The process helps to increase the concentra-tion of H2S in acid gas.

� The process reduces level of hydrocarbons inacid gas.

� The process has significant advantages inplants with high CO2/H2S ratios.

� The process provides a means to producesweetened gas that meets specific require-ments for international gas transportation sys-tems.

� The process provides flexibility in the utilisa-tion of parallel sulfur plants to maintain pro-duction and product levels.

� The process has greater ability to removeH2S/COS/CS2/RSH components from natural gas.

Tail gas treating processA process flow diagram of a conventional tail gas treat-ment processes (TGTU) is shown in Figure 4. A TGTUincludes heater, hydrogenation/hydrolysis reactor withCo-Mo or another appropriate catalyst, boiler, quenchtower and selective amine absorber and regenerator.

Tail gas, typically at 150 ˚C enters the feed heaterwhere it is raised to reactor temperature (approximately260 ˚C). The heater may be of the indirect gas-gas type,hot oil or direct heater. Two types of direct heaters arepossible. The inline burner for fuel gas combustion oper-ates stoichiometrically, during which the tail gas tempera-ture is elevated to downstream catalytic hydrogenationreactor inlet temperature. The other mode of inline burneroperation combusts the fuel gas sub-stoichiometrically tosimultaneously heat the tail gas and supply CO and H2 forthe reduction of all sulfur species of the tail gas.

The hot gas mixture is then discharged to the hydro-genation/hydrolysis reactor, where in the presence of Co-Mo or another appropriate catalyst, sulfur dioxide andsulfur are hydrogenated to hydrogen sulfide while car-bonyl sulfide and carbon disulfide are hydrolysed tohydrogen sulfide and carbon dioxide.

The effluent gas stream from the reactor then passesthrough the boiler, generating waste low pressure steamand continues as partially cooled gas stream to thequench column. In the quench column, a sour waterstream condenses out for further treatment in the sourwater stripper and the hydrogen sulfide bearing gasstream is cooled for selective amine absorption.

The absorber is fed by the combined streams of

quench tower overhead gas stream and hydrogen sulfideenriched gas. A partial pressure of hydrogen sulfide in thiscombined stream is increased over that in quench toweroverhead stream. In the absorber, MDEA or another H2Sselective solvent absorbs hydrogen sulfide. The efficiencyof this selective absorption is promoted by the elevatedpartial pressure of H2S in the absorber.

As was explained in the previous case, contrary toconventional TGTU, the absorber of HIGHSULFTM TGTUis fed by the combined streams of the quench tower over-head gas stream and hydrogen sulfide enriched gas. Apartial pressure of hydrogen sulfide in this combinedstream is increased over that in quench tower overheadstream. In the absorber, hydrogen sulfide is absorbed byMDEA or another H2S selective solvent. The efficiency ofthis selective absorption is promoted by the elevated par-tial pressure of H2S in the absorber.

The flow scheme of a TGTU in Figure 4 is intended tobe general and a process flow diagram for a particularlicensee may differ, as required for the individual plantdesign requirements.

Material balances of amine sections of HIGHSULFTM

and conventional TGTU of a small refinery are given inTable 2 and Table 3. Similar absorber feeds and all otherparameters in computer runs for 47.5 w. % of MDEA wereused in both cases, making it easy to see most of theadvantages of the patented TGTU process.

As can be seen from Table 2, the CO2 rejection inHIGHSULFTM TGTU is 88.89%, which is much higherthan the 75.5% achieved in the regular TGTU case illus-trated in Table 3. The absorber overhead H2S concentra-tions are well below 100 ppmv. The H2S in overhead canbe adjusted to any desirable level. In some cases, higher than the normal using temperature of the over-head of quench tower is successfully compensated for by

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Table 4. Computer run data for MDEA based conventional and HIGHSULFTM TGTUParameter Conventional HIGHSULFTM

H2S in feed gas, vol% 1.24 1.24CO2 in feed gas, vol% 17.0 17.0Total S in treated gas, ppmv <100 <100Lean solvent temperature, ˚C 38 38Steam rate, kg/m3 MDEA solution 107.85 107.85CO2 rejection in absorber, % 75.5 88.9H2S concentration in recycle stream to SRU, vol% 21.4 36.6Mass flow of recycle stream to SRU, kg/h 368.29 204.0Fresh acid gas received on SRU, kg/h 2948 3052Relative change of fresh acid gas 100 103.5mass flow received on SRU, %

Figure 4. Tail gas treating process.

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increasing the partial pressure of H2S in the feed ofabsorber. This advantage of the process certainly makesit more attractive if one will consider difficulties relatedwith quench water trim cooler operation.

The mass flow of acid gas of patented process is 1.8times less (204.0 kg/h) than mass flow of acid gas (368.29kg/h) in the regular process. This means that any existingregular TGTU with an absorption-regeneration sectioncan be switched to HIGHSULFTM and this switch willincrease capacity of the sulfur plant up to 3.5% and high-er. Or, the patented process may lead to a significant sav-ing from oxygen reduction in Claus units with oxygeninjection in the front end.

The high pressure of the acid gas from the regenera-tor, compared with the pressure of the gas feeding theabsorber, makes it easy to switch from an existing TGTUto the new system and it shows that it is ideal for revampsas well as for new plants.

The patented process fits perfectly in the configurationof all tail gas treating units designed with amine absorp-tion-desorption section. It is the least complex of theknown family of tail gas treating processes and it shouldbe mentioned that it has a high turndown capability.

The summarised results of computer runs of conven-tional and HIGHSULFTM type TGTU for similar feed aregiven in Table 4.

The advantages of the new TGTU process include:

� Increased H2S selectivity of generic MDEA and anyother selective solvents in the same absorber withoutany capital investments, keep the same level of totalsulfur in treated gas.

� Less mass flow of the recycling acid gas stream thatgoes back to SRU.

� Increased capacity of SRU by reducing hydraulic load-ing of SRU.

� May reduce duty of quench water trim cooler and leanamine water trim cooler of the existing or new TGTU.

� There is less operating cost and the need for applica-tion of expensive solvents is limited.

� Any existing TGTU can be easily and fast switched toHIGHSULFTM by enhancement of proved equipment ofregular TGTU without any additional capital invest-ment.

� The tail gas treatment process is the least complex ofthe known family of tail gas treating processes andhas a high turndown capability.

� May reduce the circulation rate of any existing quenchtower and keep the same level of CO2 rejection inabsorber and overhead gas stream.

Conclusion The family of HIGHSULFTM processes (gas sweeteningand TGTU) brings an additional and new important dimen-sion, such as controlled partial pressure of H2S in the feedof absorber, to gas sweetening and the control system.The concept increases CO2 rejection in the absorber ofamine units and retains the required H2S level in theabsorber overhead. It also increases H2S concentration inthe acid gas, reduces hydrocarbons and controls the com-position and the mass flow of acid gas of TGTU going toSRU as well as reducing capital and operating costs forthe new and existing conventional TGTU related withcooling requirements.

Enquiry no: 12

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