4.23.5.2 Sulphur recovery units (SRU) H 2 S-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 for bulk sulphur removal and subsequently in a Tail Gas Clean-up Unit (TGCU, see later in this section) for trace H 2 S removal. Other components entering the SRU include NH 3, CO 2 and to a minor extent various hydrocarbons. 4.23.5.2.1 Claus Process Description The Claus process consists of partial combustion of the hydrogen sulphide-rich gas stream (with one-third the stoichiometric quantity of air) and then reacting the resulting sulphur dioxide and unburned hydrogen sulphide in the presence of a activated alumina catalyst to produce elemental sulphur. ACID GAS MAIN BURNER AIR BFW LINE BURNERS 230-300 C 0.3 barg BFW REACTORS 200-220 C 0.2 barg LINE BURNER OFF-GAS TO STACK INCINERATOR REACTOR TAIL GAS TO TGT SULPHUR PIT SULPHUR Figure 4.11: Simplified process flow diagram of a sulphur recovery unit (CLAUS) unit 338 Mineral Oil and Gas Refineries
Techniques to consider in the determination of BAT Chapter 4 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 Claus plant. Use of this process increase capacity up to 200 % in existing Claus sulphur recovery units, or for a more economical design of Claus sulphur units. Achieved environmental benefits Number of Claus reactors Efficiency (%H 2 S converted) 1 90 2 94-96 3 97-98 Table 4.36: Efficiencies of the Claus process Cross-media effects Emissions based on 20000 t/yr SRU Source Flow Composition min/max Emissions: CO 2, SO 2, NO x Incinerator off-gas 0.2 % of total H 2 S-load to the SRU SO 2 1500 mg/nm 3 Through presence of NH 3 non-catalytic denoxing takes place Effluent: Knock-out drum for water in SWS offgas 0.02 m 3 /h H 2 S: 50 mg/l; Phenol: 100 mg/l; NH 3 : 2000 mg/l Waste Spent SRU catalyst plant specific Mainly Al 2 O 3 Comments Amount of SO 2 released depends on total sulphur production and overall sulphur recovery To be treated in the SWS The reduction of SO 2 leads to an increase of the CO 2 emission. For example for a 100 t/d sulphur claus plant, the application of three reactors would lead to an emission of 4.8 tonnes of sulphur per day at a cost of 8.5 tonnes of CO 2 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 are important parameters in obtaining maximum sulphur recovery. Good control and availability is crucial as a technique, to deliver any design targets. In this line, the use of state-of-the-art control and monitoring systems can be seen as an important technique. Use of a tail gas analyser linked to the process control system (feedback control) will aid optimum conversion during all plant operating conditions, including changes to sulphur throughput To have a SRU configuration with sufficient capacity for the H 2 S feed to the unit including the sourest crude oil to be used is important. The duplication of the SRU capacity is important to consider to obtain low sulphur emissions. This enough capacity also should consider to allow the scheduled maintenance activity to proceed every two years, without a significant increase of sulphur emissions. To have utilisation factors close to 100% increase how efficient the units are used. Those capacity factors should plan also major turnaround maintenance. use a good furnace burning-zone design and effective furnace temperature and oxygen control systems where sour water stripper off-gases are a feed stream, because the process must also be designed and operated to complete the destruction of ammonia. Ammonia breakthrough may lead to deposition and blockages of catalyst beds by ammonium salts (eg carbonate/sulphate) and these SRUs need to be monitored for evidence of this. The utilities necessary in the SRU are summarised in next table Mineral Oil and Gas Refineries 339
Chapter 4 Techniques to consider in the determination of BAT Fuel (MJ/t) Electricity Steam produced Cooling water (kwh/t) (kg/t) (m 3 /t, T=10 C) 1000 1600 60-75 1500-2000 0-20 In some cases, the SRU need a pilot flame when the H 2 S concentration is so low that a stable flame cannot be achieved. Applicability Fully applicable Economics Abatement Plant size range Approximate capital cost (EUR million installed) Approximate operating cost per year (EUR million) Upgrade SRU with O 2 enrichment to 100 t/d 2.1-5.3 1.6 (costs are for increase throughput from100 t/d to 170 t/d. oxygen) 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 have a significant impact. In some cases these factors might be expected to increase the costs by some 50 %. 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) requiring 99.9 % overall sulphur recovery, capital cost savings of $2-3 million are achievable with oxygen 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 over 8 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 a two stage unit); Volume of gas: 60 million m 3 /yr; Pollutant initial concentration: 34000 mg SO 2 /m 3 (1.2 % molar or 2.3 % weight, rest considered as air) The investment cost to build a new third reactors is between EUR 2 and 3 millions and the operating cost around EUR 0.1 million per year. Driving force for implementation Reduction of sulphur emissions Example plants In the market, it exists more than 5 licensors of this process. The Claus process is public domain and 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) Description Current methods for removing sulphur from the hydrogen sulphide gas streams are typically a combination of two processes: the Claus process (See section above) followed by a tail gas clean-up or treatment unit. Since the Claus process by itself removes about 96 % (2 stages) of the hydrogen sulphide in the gas stream, the TGTU processes are often used to further recover sulphur. 340 Mineral Oil and Gas Refineries
Techniques to consider in the determination of BAT Chapter 4 More than 20 processes for TGTU have been developed in order to enhance the recovery of Sulphur compounds from natural gas and/or refinery sources. TGTU processes can be broadly divided according to the principles applied: - Dry bed processes, where the main process step is achieved on a solid catalyst. Two paths have been followed within this group: a) Extend Claus reaction on a solid bed, b)oxidise sulphur compounds to SO 2 prior to absorption, or reaction. - Liquid Phase Sub-DewPoint processes, consisting of extending the Claus reaction under sub-dewpoint conditions in liquid phase. - Liquid scrubbing processes. There are two main categories, H 2 S scrubbing processes and SO 2 scrubbing processes. In the most commonly applied configurations, H 2 S or SO 2 are recycled to the upstream Claus Unit. - Liquid Redox process. Liquid phase oxidation processes to absorb H 2 S. The first and third categories can further be divided in sub-categories depending on the sulphur recovery method used. It should be noted that a strict distinction between dry beds and liquid scrubbing processes may become uneasy as some arrangement combine the capabilities of both types of processes. Some processes belonging to the four groups above-mentioned are further explained below; this list is not intended to be exhaustive: The H 2 S Scrubbing process is by far the most widely applied. The concept underlying H 2 S scrubbing processes are: - Hydrogenation and hydrolysis of all sulphur compounds to H 2 S passing it through a cobaltmolybdenum catalyst with the addition of a reducing gas - Absorption of H 2 S by an amine solution (generic amine or specialty amine) - Regeneration of the amine solution and recycle of the H 2 S to the upfront Claus reaction furnace. Several Licensor currently propose variations on the H 2 S scrubbing process, using solvents available on the market place, or in some instances proprietary solvents. TAIL GAS FROM SRU NATURAL GAS AIR SCOT BURNER QUENCH WATER COOLER WATER MAKE-UP OFF-GAS TO INCINERATOR RETURN ACID GAS TO SRU REDUCTION REACTOR ABSORBER REGENERATOR BFW SOUR WATER TO SWS 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 of the Claus reaction, i.e. catalytic oxidation of H 2 S to S. Basically consists of two (occasionally three for large capacities) Sulfreen reactors in series with the Claus reactors. Activated Alumina is used as a catalyst. Regeneration is needed since the sulphur accumulates on the catalyst decreasing its activity. Sulphur from the hot regeneration stream is condensed in a dedicated condenser. Two variations are used: Hydrosulfreen and DoxoSulfreen. The HydroSulfreen adds a conversion step upstream of the first Sulfreen reactor, to perform the hydrolysis of COS and CS 2 to H 2 S with the help of a activated Titanium oxide Claus catalyst. Mineral Oil and Gas Refineries 341
Chapter 4 Techniques to consider in the determination of BAT The Claus reaction takes place in the HydroSulfreen reactor and produced sulphur is condensed in a dedicated condenser The DoxoSulfreen concept is based on two ideas: the upstream units are operated to get a slight excess of H 2 S, compared to the quantity necessary to maintain the Claus ratio, therefore a nearly total SO 2 conversion takes place on the conventional Sulfreen catalyst; then the remaining H 2 S is directly oxidised to elemental Sulphur In the Beaven process, the hydrogen sulphide in the relatively low concentration gas stream from 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 hydroquinone. The solution is injected with air or oxygen to oxidize the hydro-quinone back to quinone. The solution is then filtered or centrifuged to remove the sulphur and the quinone is then re-used. The Beaven process is also effective in removing small amounts of sulphur dioxide, 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 cobalt molybdate catalyst prior to being fed to the Beaven unit. The CBA (cold bed absorption), process is very similar to the Sulfreen process except in the fact that the CBA process uses a hot process stream indigenous to the Claus process to accomplish regeneration of the sulphur loaded catalyst bed. The hot process stream is part of the effluent of the first Claus reactor. Several configurations are available depending on the number of Claus converters. The Clauspol is a process where the tail gas is put in contact with a solvent (polyethylene glycol) and the reaction of H 2 S and SO 2 is catalysed by a dissolved catalysts. (sodium salt of an inorganic acid) which is a solvent for H 2 S and SO 2, but not for liquid sulphur.the Claus reaction can therefore proceed at low temperature (120 C) and is shifted further to the right as the produced 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 H 2 S to minimise the SO 2 content in the Claus tail gas. This feature simplifies and makes more flexible the air ratio control. - Selective oxidation of the remaining H 2 S in the Claus tail gas by means of specific catalyst which efficiently convert the remaining H 2 S in the presence of water vapour and excess oxygen to elemental sulphur only. This reaction takes place in a specific converter (oxidation reactor), downstream of a two or three reactors traditional Claus unit. The catalyst used is an alumina based catalyst coated with iron oxide and chromium oxide layers. The LO-CAT process. Absorption and regeneration are performed in a single vessel divided in two sections: the centerwell and the outer space where aeration with air is performed. The purpose of the Centerwell is to separate the sulphite ions from air in order to minimize byproduct 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 circulation between the absorption and the regeneration zones without the need of a specific pump. The last type of processing scheme is called the aerobic unit and is used to treat air contaminated with H 2 S. All reactions take place in the same vessel, at the expense of increased by-product formation, but with the advantage of a reduced capital cost. The SO 2 abatement from the Claus plant is a process that uses a physical scrubbing mechanism to remove SO 2 from the incinerated tail gas of a Claus plant. The recovered SO 2 is recycled to the inlet of the Claus plant unit. Achieved environmental benefits Tail gas treatment units increase the overall recovery of H 2 S decreasing the sulphur emissions from the refinery. For example, if a refinery has a 100 t/d SRU, with a two stage Claus reactor 342 Mineral Oil and Gas Refineries
Techniques to consider in the determination of BAT Chapter 4 emits around 5 t/d of sulphur. If a tail gas clean-up process is included in such a refinery the emissions of sulphur may be reduced to 0.5 t/d, representing that a reduction of 90 % of the sulphur emissions from the sulphur recovery units. Next table shows the expected overall sulphur recovery yield, the resulting additional recovered sulphur and the dry basis sulphur emission (in the form of SO 2 specie) after incineration, of the tail gas treatments considered in this Section. Expected sulphur recovery yield Expected additional sulphur recovered Expected SO 2 emissions (Dry Basis) Process (%) t / d mg / Nm 3 Claus 96.01-13652 Superclaus 98.66 2.77 4631 Sulfreen 99.42 3.56 2010 Beavon 99-99.9 - - CBA 99-99.50 3.65 1726 Clauspol 99.5 99.9 Clauspol II 99.60 3.75 1382 SO 2 abatement 99.9 HydroSulfreen (1) 99.67 3.82 1066 DoxoSulfreen (2) 99.88 4.04 414 RAR 99.94 4.10 242 LO-CAT II (3) 99.99 4.16 18 SCOT 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 H 2 S specie. Table 4.37: Expected overall sulphur recovery yield, the resulting additional recovered sulphur and the SO 2 emissions (dry basis) after incineration Cross-media effects The reduction of SO 2 leads to an increase of the CO 2 emission. For instance the application of a tailing gas treatment would lead to a SO 2 reduction of 96 % (if compared with the three reactor option), however at an increase for CO 2 of 110 %. For example for a 100 t/d sulphur claus plant with three reactors, the application of a TGTU would reduce the emissions of SO 2 to 0.1 t/d but at a price of increasing the CO 2 emissions to 18 t/d. Emissions based on 20000 t/yr SRU/TGCU. Source Flow Composition min/max Effluents Waste: SCOT Sour water from quench column for SRU off-gas Spent TGCU catalyst 1m 3 / tonne S produced (2 m 3 /h) Regeneration and disposal 20-100 t/yr H 2 S: 50 mg/l; Phenol: 100 mg/l; NH 3 : 2000 mg/l 2-8 % Ni/Mo on Al 2 O 3, S: 5-15 %; Coke: 10-30 % Comments To be treated in the SWS Spent Claus catalyst is pyrophoric and needs purging with N 2 Table 4.38: Cross-media effects associated to some of the TGTU Mineral Oil and Gas Refineries 343
Chapter 4 Techniques to consider in the determination of BAT Operational data Good control and availability is crucial as a technique, to deliver any design targets. The estimate of operating costs, including sulphur produced, utilities and chemicals as well as additional manpower expense are given in the following table: Utilities Consumption Utilities Production OPERATING COST ESTIMATE Catalyst Consumption Chemical Consumption Operation Cost Recovered Sulphur TOTAL Process k$ / y k$ / y k$ / y k$ / y k$ / y k$ / y k$ / y Sulfreen 52-6 37 n/a 20-24 79 HydroSulfreen 82-22 74 n/a 20-26 128 DoxoSulfreen 125-29 264 n/a 30-27 363 CBA 36 n/a 13 n/a 10-25 34 Superclaus 106-32 44 n/a 10-19 109 Clauspol II 52 n/a 26 26 20-25 99 RAR 133 n/a 16 10 30-28 161 LO-CAT II 138 n/a 15 148 30-28 303 Table 4.39: Operating costs of some TGTU units Applicability Applicable to both new and existing plants. Capacities range from 2 to more than 2000 tonnes of sulphur per day from the combined Claus/tail gas treatment units. Economics The cost of the SRU depends strongly on the type of tail gas treatment. Following several tables show some examples of economics of the TGTUs. Abatement SRU including Tailgas treatment unit (TGTU) to give>99 % S recovery Tailgas treatment unit to improve SRU recovery to 99 % Tailgas treatment unit to improve SRU recovery to 99.8 % Plant size range 50 t/d 100 t/d 250 t/d 50 t/d 100 t/d 250 t/d 50 t/d 100 t/d 250 t/d Approximate capital cost (EUR million installed) 12 19 35 1.6 2.1 2.9 3.5 4.4 Approximate operating cost per year New SRU operating cost approximately equal to existing costs. Operating cost relatively low Operating cost relatively low 6.3 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 have a 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. The following table gives estimate of such ratio, for a 100 t/d Claus unit (including catalyst) in a refinery environment. 344 Mineral Oil and Gas Refineries
Techniques to consider in the determination of BAT Chapter 4 Without Licence, Catalysts and Chemicals Licence, Catalyst and Chemicals included Process (%) (%) Sulfreen 29.2 30.9 HydroSulfreen (1) 44.7 47.6 DoxoSulfreen (2) 67.0 76.0 CBA 35.4 36.1 Superclaus 12.3 15.3 Clauspol II 33.7 37.3 RAR 67.2 67.5 LO-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 of comparison is usually presented in the literature. This comparison should be taken with care when 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 is shown in the following table: 3rd Stage Claus plus super-claus (1997) DESCRIPTION k EUR % INDIRECT COSTS Detailed Engineering 8.0 27 Field Supervision 1.6 5 Owner 2.4 8 Subtotal 12.0 40 DIRECT COSTS EQUIPMENT Materials 7.3 25 Catalysts and Chemicals 0.6 2 Subtotal 7.9 27 DIRECT COSTS - NON EQUIPMENT Subcontracts 8.6 29 Temporary Construction & Consumables 0.4 1 Subtotal 9.0 30 Total Capital 28.9 97 EXPENSE Licensing Fee 0.5 2 Subtotal 0.5 2 Final 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 typical Claus unit tail gas, combined production of 100 tonnes of sulphur per day (ISBL 1998 Gulf Coast location), the investment (excluding engineering and license fees) came up to 3 million US$. The following table shows specific costs data for SO 2 abatement under the assumptions outlined in Annex IV. Mineral Oil and Gas Refineries 345
Chapter 4 Techniques to consider in the determination of BAT Name of the technique EUR/tonne SO 2 abated (1) EUR/tonne SO 2 abated (2) 3 rd reactor 32 Stand Alone Scot 321-538 32 Cascade Scot Common 32 regenerator Super Claus 155-228 32-161 Super Claus + Claus Stage 32-160 Clauspol 198-330 32 Sulfreen 174-288 32-160 Hydro-sulfreen 253-417 32-160 CBA/AMOCO cold real absorption 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 implementation Reduction of sulphur emissions and recovery of sulphur. Example plants Technique Beavon Clauspol Sulfreen/Hydrosulfreen Superclaus Number of installations all over the world More than 150 installations More than 50 units More than 150 units in operation 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 Description In order to reduce the emissions of H 2 S from the storage and transport of liquid sulphur, the amount of H 2 S and polysulphides in the sulphur can be reduced to <10 ppm by oxidation or treatment with a suitable additive. Reference literature [268, TWG, 2001]