aardolie-engasraffinaderijen-4.23.5.2sulphurrecoveryunitssru

Chapter 4 Techniques to consider in the determination of BAT

338 Mineral Oil and Gas Refineries

Corrosive salts, which concentrate during recycling, can be removed via ion exchangetechniques. Some proprietary solutions may be biodegradable under suitable conditions.

It is important also that the amine processes have sufficient capacity to allow maintenanceactivities and upsets. This sufficient capacity can be achieved by having redundancy equipment,apply load shedding, emergency amine scrubbers or multiple scrubber systems.

ApplicabilityProcess off-gas streams from the coker, catalytic cracking unit, hydrotreating units andhydroprocessing units can contain high concentrations of hydrogen sulphide mixed with lightrefinery fuel gases. Emergency H2S scrubbers are also important.

EconomicsThe cost of upgrade the refinery amine treatment system (2 %) to meet 0.01 to 0.02 % v/v ofH2S in fuel gas is around 3.75 to 4.5 million EUR. This cost is battery limit costs based on 1998prices and include such items as equipment, licence fees, foundations, erection, tie-ins toexisting plant and commissioning. They are an order of magnitude only. Site-specific factorssuch as layout, available space and necessary modifications to existing plant could have asignificant impact. In some cases these factors might be expected to increase the costs by some50 %.

Driving force for implementationReduce the sulphur content of flue gases.

Example plant(s)Common technology used all over the world

Reference literature[118, VROM, 1999], [211, Ecker, 1999], [19, Irish EPA, 1993], [268, TWG, 2001]

4.23.5.2 Sulphur recovery units (SRU)

H2S-rich gas streams from Amine Treating Units (see above section) and Sour Water Strippers(see Section 4.24.2) are treated in a Sulphur Recovery Unit (SRU) normally a Claus process forbulk sulphur removal and subsequently in a Tail Gas Clean-up Unit (TGCU, see later in thissection) for trace H2S removal. Other components entering the SRU include NH3, CO2 and to aminor extent various hydrocarbons.

4.23.5.2.1 Claus Process

DescriptionThe Claus process consists of partial combustion of the hydrogen sulphide-rich gas stream (withone-third the stoichiometric quantity of air) and then reacting the resulting sulphur dioxide andunburned hydrogen sulphide in the presence of a activated alumina catalyst to produceelemental sulphur.

ACID GAS

AIR

MAIN BURNER

BFW

STEAM

LINE BURNERS

REACTORSLINE BURNER

TAIL GAS TO TGT

STEAM

SULPHURSULPHUR PIT

STEAM

BFW

230-300°C0.3 barg

200-220°C0.2 barg

INCINERATORREACTOR

OFF-GASTO STACK

Figure 4.11: Simplified process flow diagram of a sulphur recovery unit (CLAUS) unit

Techniques to consider in the determination of BAT Chapter 4

Mineral Oil and Gas Refineries 339

The capacity of the Claus plants can be increased with the use of oxygen instead of air(OxyClaus process) however this has not any beneficial effect in the efficiency of the Clausplant. Use of this process increase capacity up to 200 % in existing Claus sulphur recoveryunits, or for a more economical design of Claus sulphur units.

Achieved environmental benefits

Number of Claus reactors Efficiency (%H2S converted)1 902 94 - 963 97 - 98

Table 4.36: Efficiencies of the Claus process

Cross-media effects

Emissions based on 20000 t/yr SRUSource Flow Composition

min/maxComments

Emissions:CO2, SO2,NOx

Incineratoroff-gas

0.2 % of totalH2S-load tothe SRU

SO2 1500mg/Nm3 Throughpresence of NH3non-catalyticdeNOxing takesplace

Amount of SO2 released dependson total sulphur production andoverall sulphur recovery

Effluent: Knock-out drum forwater in SWS off-gas

0.02 m3/h H2S: 50 mg/l;Phenol: 100 mg/l;NH3: 2000 mg/l

To be treated in the SWS

Waste Spent SRU catalyst plant specific Mainly Al2O3

The reduction of SO2 leads to an increase of the CO2 emission. For example for a 100 t/dsulphur claus plant, the application of three reactors would lead to an emission of 4.8 tonnes ofsulphur per day at a cost of 8.5 tonnes of CO2 per day.

Operational data• Feed/air ratio control, temperature control of the furnace, reactors and condensers and good

demisting of liquid sulphur, especially from the final condenser exit gas stream areimportant parameters in obtaining maximum sulphur recovery. Good control andavailability is crucial as a technique, to deliver any design targets. In this line, the use ofstate-of-the-art control and monitoring systems can be seen as an important technique. Useof a tail gas analyser linked to the process control system (feedback control) will aidoptimum conversion during all plant operating conditions, including changes to sulphurthroughput

• To have a SRU configuration with sufficient capacity for the H2S feed to the unit includingthe sourest crude oil to be used is important. The duplication of the SRU capacity isimportant to consider to obtain low sulphur emissions. This enough capacity also shouldconsider to allow the scheduled maintenance activity to proceed every two years, without asignificant increase of sulphur emissions.

• To have utilisation factors close to 100% increase how efficient the units are used. Thosecapacity factors should plan also major turnaround maintenance.

• use a good furnace burning-zone design and effective furnace temperature and oxygencontrol systems where sour water stripper off-gases are a feed stream, because the processmust also be designed and operated to complete the destruction of ammonia. Ammoniabreakthrough may lead to deposition and blockages of catalyst beds by ammonium salts (egcarbonate/sulphate) and these SRUs need to be monitored for evidence of this.

The utilities necessary in the SRU are summarised in next table



Fuel (MJ/t) Electricity(kWh/t)

Steam produced(kg/t)

Cooling water(m3/t, ∆T=10 °C)

1000 – 1600 60 - 75 1500 - 2000 0 - 20

In some cases, the SRU need a pilot flame when the H2S concentration is so low that a stableflame cannot be achieved.

ApplicabilityFully applicable

EconomicsAbatement Plant size

rangeApproximatecapital cost

(EUR millioninstalled)

Approximateoperating cost peryear (EUR million)

Upgrade SRU with O2 enrichment toincrease throughput from100 t/d to 170 t/d.

100 t/d 2.1 - 5.3 1.6 (costs are foroxygen)

They are battery limit costs based on 1998 prices and include such items as equipment, licence fees,foundations, erection, tie-ins to existing plant and commissioning. They are an order of magnitude only.Site-specific factors such as layout, available space and necessary modifications to existing plant couldhave a significant impact. In some cases these factors might be expected to increase the costs by some50 %.

Another example of the upgrade of SRU with oxygen enrichment (Oxyclaus)Economics: For a reference 200 tpd sulphur recovery unit (Claus and tail gas unit) requiring99.9 % overall sulphur recovery, capital cost savings of $2 - 3 million are achievable withoxygen enrichment as compared to an air only design. Based on typical pipeline oxygen costs of$35 per tonne, even if oxygen enrichment were used 100 % of the time, it would take over8 years for oxygen costs to equal the increamental capital saving.

Example of the economics of the installation of a third Claus reactor.Capacity of process: 30000 t/yr sulphur production (sulphur recovery efficiency 94 - 96 % for atwo stage unit); Volume of gas: 60 million m3/yr; Pollutant initial concentration: 34000 mgSO2/m3 (1.2 % molar or 2.3 % weight, rest considered as air) The investment cost to build a newthird reactors is between EUR 2 and 3 millions and the operating cost around EUR 0.1 millionper year.

Driving force for implementationReduction of sulphur emissions

Example plantsIn the market, it exists more than 5 licensors of this process. The Claus process is public domainand virtually applied at any refinery. Two stages Claus process is the most common in Europe.More than 30 Oxyclaus systems are in operation in the world.

Reference literature[250, Winter, 2000], [258, Manduzio, 2000], [115, CONCAWE, 1999], [45, Sema and Sofres,1991], [181, HP, 1998], [114, Ademe, 1999]

4.23.5.2.2 Tail Gas Treatment Unit (TGTU)

DescriptionCurrent methods for removing sulphur from the hydrogen sulphide gas streams are typically acombination of two processes: the Claus process (See section above) followed by a tail gasclean-up or treatment unit. Since the Claus process by itself removes about 96 % (2 stages) ofthe hydrogen sulphide in the gas stream, the TGTU processes are often used to further recoversulphur.



More than 20 processes for TGTU have been developed in order to enhance the recovery ofSulphur compounds from natural gas and/or refinery sources. TGTU processes can be broadlydivided according to the principles applied:

- Dry bed processes, where the main process step is achieved on a solid catalyst. Two pathshave been followed within this group: a) Extend Claus reaction on a solid bed, b)Oxidisesulphur compounds to SO2 prior to absorption, or reaction.

- Liquid Phase Sub-DewPoint processes, consisting of extending the Claus reaction undersub-dewpoint conditions in liquid phase.

- Liquid scrubbing processes. There are two main categories, H2S scrubbing processes andSO2 scrubbing processes. In the most commonly applied configurations, H2S or SO2 arerecycled to the upstream Claus Unit.

- Liquid Redox process. Liquid phase oxidation processes to absorb H2S.

The first and third categories can further be divided in sub-categories depending on the sulphurrecovery method used. It should be noted that a strict distinction between dry beds and liquidscrubbing processes may become uneasy as some arrangement combine the capabilities of bothtypes of processes. Some processes belonging to the four groups above-mentioned are furtherexplained below; this list is not intended to be exhaustive:

The H2S Scrubbing process is by far the most widely applied. The concept underlying H2Sscrubbing processes are:- Hydrogenation and hydrolysis of all sulphur compounds to H2S passing it through a cobalt-

molybdenum catalyst with the addition of a reducing gas- Absorption of H2S by an amine solution (generic amine or specialty amine)- Regeneration of the amine solution and recycle of the H2S to the upfront Claus reaction

furnace.Several Licensor currently propose variations on the H2S scrubbing process, using solventsavailable on the market place, or in some instances proprietary solvents.

STEAM

ABSORBER REGENERATOR

WATERMAKE-UP

RETURN ACIDGAS TO SRU

QUENCHWATER COOLER

REDUCTIONREACTOR

STEAM BFW

TAIL GASFROM SRU

SCOT BURNER

OFF-GASTO INCINERATOR

AIR

SOUR WATERTO SWS

NATURAL GAS

Figure 4.12: Simplified process flow diagram of a tail gas Claus unit (SCOT) unit

The Sulfreen process is a dry-bed, sub-dew point absorption process based on the extension ofthe Claus reaction, i.e. catalytic oxidation of H2S to S. Basically consists of two (occasionallythree for large capacities) Sulfreen reactors in series with the Claus reactors. Activated Aluminais used as a catalyst. Regeneration is needed since the sulphur accumulates on the catalystdecreasing its activity. Sulphur from the hot regeneration stream is condensed in a dedicatedcondenser. Two variations are used: Hydrosulfreen and DoxoSulfreen.

The HydroSulfreen adds a conversion step upstream of the first Sulfreen reactor, to perform thehydrolysis of COS and CS2 to H2S with the help of a activated Titanium oxide Claus catalyst.



The Claus reaction takes place in the HydroSulfreen reactor and produced sulphur is condensedin a dedicated condenser

The DoxoSulfreen concept is based on two ideas: the upstream units are operated to get a slightexcess of H2S, compared to the quantity necessary to maintain the Claus ratio, therefore a nearlytotal SO2 conversion takes place on the conventional Sulfreen catalyst; then the remaining H2Sis directly oxidised to elemental Sulphur

In the Beaven process, the hydrogen sulphide in the relatively low concentration gas streamfrom the Claus process can be almost completely removed by absorption in a quinone solution.The dissolved hydrogen sulphide is oxidized to form a mixture of elemental sulphur and hydro-quinone. The solution is injected with air or oxygen to oxidize the hydro-quinone back toquinone. The solution is then filtered or centrifuged to remove the sulphur and the quinone isthen re-used. The Beaven process is also effective in removing small amounts of sulphurdioxide, carbonyl sulphide, and carbon disulphide that are not affected by the Claus process.These compounds are first converted to hydrogen sulphide at elevated temperatures in a cobaltmolybdate catalyst prior to being fed to the Beaven unit.

The CBA (cold bed absorption), process is very similar to the Sulfreen process except in thefact that the CBA process uses a hot process stream indigenous to the Claus process toaccomplish regeneration of the sulphur loaded catalyst bed. The hot process stream is part of theeffluent of the first Claus reactor. Several configurations are available depending on the numberof Claus converters.

The Clauspol is a process where the tail gas is put in contact with a solvent (polyethyleneglycol) and the reaction of H2S and SO2 is catalysed by a dissolved catalysts. (sodium salt of aninorganic acid) which is a solvent for H2S and SO2, but not for liquid sulphur.The Claus reactioncan therefore proceed at low temperature (120 °C) and is shifted further to the right as theproduced sulphur is removed from the reaction medium, as it is not soluble and separates.

The Superclaus process is based on two principles:- Operating the Claus plant with excess H2S to minimise the SO2 content in the Claus tail gas.

This feature simplifies and makes more flexible the air ratio control.- Selective oxidation of the remaining H2S in the Claus tail gas by means of specific catalyst

which efficiently convert the remaining H2S in the presence of water vapour and excessoxygen to elemental sulphur only.

This reaction takes place in a specific converter (oxidation reactor), downstream of a two orthree reactors traditional Claus unit. The catalyst used is an alumina based catalyst coated withiron oxide and chromium oxide layers.

The LO-CAT process. Absorption and regeneration are performed in a single vessel divided intwo sections: the centerwell and the outer space where aeration with air is performed. Thepurpose of the Centerwell is to separate the sulphite ions from air in order to minimize by-product formation (e.g. thiosulphate). The difference in aeration (and therefore of density)between the centerwell and the outer space give sufficient driving force for solution circulationbetween the absorption and the regeneration zones without the need of a specific pump. The lasttype of processing scheme is called the “aerobic unit” and is used to treat air contaminated withH2S. All reactions take place in the same vessel, at the expense of increased by-productformation, but with the advantage of a reduced capital cost.

The SO2 abatement from the Claus plant is a process that uses a physical scrubbing mechanismto remove SO2 from the incinerated tail gas of a Claus plant. The recovered SO2 is recycled tothe inlet of the Claus plant unit.

Achieved environmental benefitsTail gas treatment units increase the overall recovery of H2S decreasing the sulphur emissionsfrom the refinery. For example, if a refinery has a 100 t/d SRU, with a two stage Claus reactor



emits around 5 t/d of sulphur. If a tail gas clean-up process is included in such a refinery theemissions of sulphur may be reduced to 0.5 t/d, representing that a reduction of 90 % of thesulphur emissions from the sulphur recovery units. Next table shows the expected overallsulphur recovery yield, the resulting additional recovered sulphur and the dry basis sulphuremission (in the form of SO2 specie) after incineration, of the tail gas treatments considered inthis Section.

Expected sulphurrecovery yield

Expected additionalsulphur recovered

Expected SO2 emissions(Dry Basis)

Process (%) t / d mg / Nm3

Claus 96.01 - 13652Superclaus 98.66 2.77 4631Sulfreen 99.42 3.56 2010Beavon 99-99.9 - -CBA 99 - 99.50 3.65 1726Clauspol 99.5 – 99.9Clauspol II 99.60 3.75 1382SO2 abatement 99.9HydroSulfreen (1) 99.67 3.82 1066DoxoSulfreen (2) 99.88 4.04 414RAR 99.94 4.10 242LO-CAT II (3) 99.99 4.16 18SCOT 99.5-99.99(1) Sulfreen reactors and hydrolysis section(2) Sulfreen reactors, hydrolysis section and DoxoSulfreen reactors(3) As LO-CAT II tail gas cannot be incinerated, sulphur is in the form of H2S specie.

Table 4.37: Expected overall sulphur recovery yield, the resulting additional recovered sulphurand the SO2 emissions (dry basis) after incineration

Cross-media effectsThe reduction of SO2 leads to an increase of the CO2 emission. For instance the application of atailing gas treatment would lead to a SO2 reduction of 96 % (if compared with the three reactoroption), however at an increase for CO2 of 110 %. For example for a 100 t/d sulphur claus plantwith three reactors, the application of a TGTU would reduce the emissions of SO2 to 0.1 t/d butat a price of increasing the CO2 emissions to 18 t/d.

Emissions based on 20000 t/yr SRU/TGCU.Source Flow Composition

min/maxComments

Effluents Sour water fromquench column forSRU off-gas

1m3 / tonne Sproduced(2 m3/h)

H2S: 50 mg/l;Phenol: 100 mg/l;NH3: 2000 mg/l

To be treated in the SWS

Waste:SCOT

Spent TGCUcatalyst

Regenerationand disposal20 - 100 t/yr

2 - 8 % Ni/Mo onAl2O3,S: 5 - 15 %;Coke: 10 - 30 %

Spent Claus catalyst is pyrophoricand needs purging with N2

Table 4.38: Cross-media effects associated to some of the TGTU



Operational dataGood control and availability is crucial as a technique, to deliver any design targets. Theestimate of operating costs, including sulphur produced, utilities and chemicals as well asadditional manpower expense are given in the following table:

OPERATING COST ESTIMATEUtilities

ConsumptionUtilities

ProductionCatalyst

ConsumptionChemical

ConsumptionOperation

CostRecovered

Sulphur TOTAL

Process k$ / y k$ / y k$ / y k$ / y k$ / y k$ / y k$ / ySulfreen 52 -6 37 n/a 20 -24 79HydroSulfreen 82 -22 74 n/a 20 -26 128DoxoSulfreen 125 -29 264 n/a 30 -27 363CBA 36 n/a 13 n/a 10 -25 34Superclaus 106 -32 44 n/a 10 -19 109Clauspol II 52 n/a 26 26 20 -25 99RAR 133 n/a 16 10 30 -28 161LO-CAT II 138 n/a 15 148 30 -28 303

Table 4.39: Operating costs of some TGTU units

ApplicabilityApplicable to both new and existing plants. Capacities range from 2 to more than 2000 tonnesof sulphur per day from the combined Claus/tail gas treatment units.

EconomicsThe cost of the SRU depends strongly on the type of tail gas treatment. Following several tablesshow some examples of economics of the TGTUs.

Abatement Plant sizerange

Approximatecapital cost

(EUR millioninstalled)

Approximate operatingcost per year

SRU including Tailgas treatment unit(TGTU) to give>99 % S recovery

50 t/d100 t/d250 t/d

121935

New SRU operating costapproximately equal toexisting costs.

Tailgas treatment unit to improve SRUrecovery to 99 %

50 t/d100 t/d250 t/d

1.62.12.9

Operating cost relativelylow

Tailgas treatment unit to improve SRUrecovery to 99.8 %

50 t/d100 t/d250 t/d

3.54.46.3

Operating cost relativelylow

They are battery limit costs based on 1998 prices and include such items as equipment, licence fees,foundations, erection, tie-ins to existing plant and commissioning. They are an order of magnitude only.Site-specific factors such as layout, available space and necessary modifications to existing plant could havea significant impact. In some cases these factors might be expected to increase the costs by some 50 %.

Usual practice is to relate the capital cost of the TGCU to the one of the up front Claus unit. Thefollowing table gives estimate of such ratio, for a 100 t/d Claus unit (including catalyst) in arefinery environment.



Without Licence, Catalystsand Chemicals

Licence, Catalyst andChemicals included

Process (%) (%)Sulfreen 29.2 30.9HydroSulfreen (1) 44.7 47.6DoxoSulfreen (2) 67.0 76.0CBA 35.4 36.1Superclaus 12.3 15.3Clauspol II 33.7 37.3RAR 67.2 67.5LO-CAT II 46.8 49.0(1) Sulfreen reactors and hydrolysis section(2) Sulfreen reactors, hydrolysis section and DoxoSulfreen reactors

The reference to the upstream sulphur unit is indicative and corresponds to the way this kind ofcomparison is usually presented in the literature. This comparison should be taken with carewhen comparing with other studies, as the capital cost of a sulphur unit may vary greatly.

A particular example of the cost of a three stages Claus plant plus TGTU superclaus process isshown in the following table:

3rd Stage Claus plus super-Claus (1997)DESCRIPTION k EUR %INDIRECT COSTSDetailed Engineering 8.0 27Field Supervision 1.6 5Owner 2.4 8

Subtotal 12.0 40DIRECT COSTS – EQUIPMENTMaterials 7.3 25Catalysts and Chemicals 0.6 2

Subtotal 7.9 27DIRECT COSTS - NON EQUIPMENTSubcontracts 8.6 29Temporary Construction & Consumables 0.4 1

Subtotal 9.0 30Total Capital 28.9 97

EXPENSELicensing Fee 0.5 2

Subtotal 0.5 2Final Total 29.4 99

Table 4.40: Economics of tail gas treatment units of the sulphur recovery units

Another example of the cost of a TGTU unit reports that for a Clauspol unit treating a typicalClaus unit tail gas, combined production of 100 tonnes of sulphur per day (ISBL 1998 GulfCoast location), the investment (excluding engineering and license fees) came up to 3 millionUS$.

The following table shows specific costs data for SO2 abatement under the assumptions outlinedin Annex IV.



Name of the technique EUR/tonne SO2abated (1)

EUR/tonne SO2abated (2)

3rd reactor 32Stand Alone Scot 321-538 32Cascade Scot Commonregenerator

32

Super Claus 155-228 32-161Super Claus + Claus Stage 32-160Clauspol 198-330 32Sulfreen 174-288 32-160Hydro-sulfreen 253-417 32-160CBA/AMOCO cold realabsorption

169-300 -

(1) [346, France, 2001]. Bases for calculation in Annex IV(2) [115, CONCAWE, 1999] Bases for calculation in Annex IV

Driving force for implementationReduction of sulphur emissions and recovery of sulphur.

Example plants

Technique Number of installations all over the worldBeavon More than 150 installationsClauspol More than 50 unitsSulfreen/Hydrosulfreen More than 150 units in operationSuperclaus More than 70 commercial plants

Table 4.41: Approximate number of commercial installations in the world

Reference literature[195, The world refining association, 1999], [112, Foster Wheeler Energy, 1999], [309,Kerkhof, 2000], [257, Gilbert, 2000], [115, CONCAWE, 1999], [107, Janson, 1999], [181, HP,1998], [114, Ademe, 1999], [45, Sema and Sofres, 1991], [346, France, 2001]

4.23.5.2.3 Sulphur storage

DescriptionIn order to reduce the emissions of H2S from the storage and transport of liquid sulphur, theamount of H2S and polysulphides in the sulphur can be reduced to <10 ppm by oxidation ortreatment with a suitable additive.

Reference literature[268, TWG, 2001]

4.23.5.3 Hydrogen sulphide and light mercaptan removal

DescriptionThe system works with a fixed-bed or batch-type granular reactant.

Achieved environmental benefitsProcesses for odour and low emission control features.

ApplicabilityApplications to waste water sytems, land oil tanker vent, oil storage and transportation, andbitumen plants.

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