ELEMENTAL SULFUR is produced by reacting H2S and S02 in the vapor phase.
2H2S + SO2 --> 1.5S2 + 2H2O
Reaction products are cooled to about 290°F to condense which is subsequently separated in the molten state from uncondensed gases. Sulfur is generally stored and/or shipped as a liquid at temperature above 250°F or in various solid forms. Liquid sulfur has a clear, bright cherry red appearance while solid sulfur varies in color from canary yellow to dark brown or black.
Claus sulfur recovery units consist of six primary operations:
· Combustion step
· Gas cooling
· Reaction of H2S and S02
· Condensation of elemental sulfur
· Reheating reactor feeds
· Incineration.
Sulfur is produced both non-catalytically (combustion zone) and catalytically to reach maximum recovery. Generally one thermal reactor (combustion furnace) is followed in a series by two or more catalytic reactors. The ratio of reactants is controlled by fixing the amount to be burned.
H2S + 1.5O2 = SO2 + H2O
Since two moles of H2S react with one mole of SO2, only about one-third of the H2S feed is burned, leaving two-thirds to react with the newly formed SO2.
Because of the cooling required to condense elemental sulfur, gases need to be reheated prior to being fed to the downstream catalytic reactor. Following the final condensation and separation of molten sulfur, tail gases are usually sent to an incinerator or a tail gas treater. In the incinerator all unrecovered sulfur compounds are converted to SO2 prior to emission to the atmosphere. In a tail gas treater most of the unrecovered sulfur compounds are converted, and the remainder are usually incinerated before discharge to the air.
COMBUSTION
The combustion process is very critical to successful Claus operations. About one-third of the H2S is burned along with other feed combustibles: hydrogen, hydrocarbons, carbon monoxide, ammonia, cyanides, mercaptans, etc., which are partially oxidized. The furnace operates in a reducing atmosphere, which makes air feed control to the burner very important. Generally, only enough air is fed to oxidize about one-third of the H2S to SO2 and H2O, reduce hydrocarbons only to CO and H2O, convert NH3 to N2 and H2O, and burn cyanides and mercaptans to CO, N2, SO2 and H2O.
Normally, less than 40% of total feed gas is burned in the combustion chamber. For a typical Claus unit feeding a gas containing 81 % H2S, 9% CO2, 6% H2O and 4% hydrocarbons, only 31 % of the entire feed stream is oxidized. One- third of the H2S is burned (27 % of the feed) plus the 4% other combustibles. Thus combustion products include two-third of feed H2S plus some CO from partial oxidation of hydrocarbons. Additionally, some feed H2S converts directly to H2 and sulfur, creating a highly reducing atmosphere since there is no uncombined oxygen and there are significant amounts of reducing gases (H2S, H2, CO). Combustion air is usually supplied by a blower, since the furnace operates under a positive pressure (3.0 to 8.0 psig).
The combustion process is complicated considerably by the presence of ammonia, other mercaptans and cyanides in the feed. These compounds are very difficult to burn in a reducing atmosphere. Unoxidized cyanides and ammonia react with available H2S to produce compounds that plug the catalytic reactors, sulfur condensers, and heat exchangers, molten sulfur drain legs, etc. Therefore, it is imperative that ammonia or cyanide in the feed be properly destroyed by combustion.
A typical low H2S feed might contain 21 % H2S, 70% CO2, 6% H2O and 3% other combustibles. Here only 10% of the entire feed stream would be oxidized in the furnace (one-third of the feed H2S (7%) plus 3% other combustibles). This makes it difficult to maintain stable combustion in the furnace. Therefore, a procedure has been developed where some feed is bypassed around the furnace. This practice is called "split-flow" operation.
A potential disadvantage of "split-flow" is that some hydrocarbon, ammonia, cyanides, etc., are also fed directly to the first catalytic reactor without being burned. Unoxidized NH3 and cyanides tend to react with H2S to form compounds that plug the Claus unit. Often unreacted hydrocarbons degrade to carbon, shortening catalyst life. Carbon contamination can cause frequent unit shutdowns, premature catalyst change-outs, and off-color sulfur product.
Another technique developed to improve combustion stability involves use of preheated air and/or preheated acid gas. Typically, air and acid gas feed temperatures are less than 200°F and 100-150°F, respectively. By externally preheating air and/or acid gas to the burner, a more stable combustion condition is possible.
Theoretically, there is no upper limit to the air temperature. Practically, however, air is not preheated above 750°F, and more often is around 450°F. On the other hand, acid gas should not be heated above 650°F, since H2S starts to sulfide carbon steel at this temperature, damaging or destroying exchangers, piping, etc. Generally, acid gas is preheated to a maximum of 450°F.
Another procedure used for extremely low H2S feeds (<8%) is "direct oxidation." However, some variation of preheated feed and/or "split-flow" is usually preferable. Other approaches include addition of fuel to the unit feed, use of oxygen or oxygen-enriched air. However, use of oxygen usually is practical only if an air separation unit is part of the plant facilities.
Based on use of air for combustion, the types of Claus plants commonly selected are listed in Table 1.
TABLE 1
H2S in feed, % Type Claus unit
55-100 Straight through
40-55 Straight through with feed and/or air preheat
25-40 Split flow
12-25 Split flow with feed and/or air preheat
7-12 Split flow with feed and/or air preheat with added fuel
< 7 Claus plant usually not practical
For oxygen or oxygen-enriched air supply, these feed H2S concentrations would change somewhat.
All solvents used in sour gas treating result in hydrocarbons being present in Claus plant feed. Usually the hydrocarbon level is a minimum of 2% with a maximum of about 10%. Hydrocarbon content of Claus plant feed is a function of feed gas pressure, type of solvent used, and type of hydrocarbon present.
Gas Cooling & Sulfur Condensation
Gases leaving the combustion furnace at 2,000 to 2,500°F are most often cooled by generating saturated steam in a waste heat boiler of the fire-tube type. Hot gases pass: through the tubes with boiling water on the shell side where steam pressures between 20 and 600 psig can be successfully maintained. Sulfur is not normally condensed m the waste heat boiler because the outlet temperature (500 to 650°F) is I above the sulfur dew point temperature for gases leaving the furnace.
For straight-through type units, furnace-produced sulfur is roughly 50-65% of total production. The first sulfur condenser downstream of the waste heat boiler recovers sulfur by cooling gases to 300-400°F. Cooling is usually accomplished by steam generation at steam pressures between 20 and 80 psig. Gas outlet temperature from the sulfur condensers is limited to about 20oF minimum above steam temperature.
If low-pressure steam (20-80 psig) is not needed in the plant, another procedure occasionally used is a "closed" water boiling system where steam is generated in sulfur condensation at 20 psig, condensed and the condensate returned to the "boiler" (sulfur condenser) as feed water, thereby "closing the loop." This cooling method minimizes the amount of make-up water required for the system,
REACTOR FEED HEATING
Gas leaving the sulfur condenser is at its dew point but generally contains some liquid entrainment as well. Therefore, liquid sulfur needs to be vaporized and the gas temperature raised above the sulfur dew point before this gas can be fed to the catalytic reactor. Otherwise liquid sulfur would plug-off individual catalyst pores, effectively deactivating the catalyst. Additionally, elemental sulfur could solidify to form a concrete-like mass with the catalyst and block off gas flow through the bed. Therefore some type reactor feed heater is required following each sulfur condensation step except the final one.
Several reheat methods commonly used include:
· Indirect
· Fired heaters
· Hot gas bypass (direct mixing).
Direct mixing usually feeds a slip-stream of hot gas (600 to 1,500°F) from the waste heat boiler to the sulfur condenser outlet gases, upstream of the catalytic reactor. Mixing these two streams establishes the desired reactor inlet temperature.
Fired heater types include in-line burners wherein either fuel gas or acid gas is burned and combustion products mixed directly with reactor feed to raise the gas temperature to the proper level. Most in-line burners are fueled by a portion of the Claus unit acid gas feed.
Indirect reheat methods include use of steam or hot oil to heat reactor feed gases, which flow through the tube side of an exchanger upstream of the reactor. Also hot gases from a reactor outlet or boiler can be used as the heating media for the reactor feed, using a gas-to-gas heat exchanger.
The main advantage for hot gas bypass is its relatively low installation cost. This results since only piping and valves are required and the pressure drop is low. The main disadvantage is lower overall net sulfur recovery. Boiler outlet gases used as heat source normally contain large quantities of uncondensed elemental sulfur which bypass the first sulfur condenser (and often the second) and are fed directly to the ) catalytic reactor. This elemental sulfur in reactor feed limits the net reaction of H2S and SO2 because of the effects on re- action constants. Since the Claus reaction is reversible, there could be sufficient elemental sulfur to prevent net reaction of H2S and SO2 (2H2S + SO2 <=> 1.5 S2 + 2 H2O). This disadvantage is amplified at low turndown rates.
Because of the elemental sulfur problem, hot gas bypass method is usually limited to the first two catalytic reactors. Units with three catalytic reactors should not use this method on the third reactor. Usually an indirect method of reheat is preferable for the third reactor.
The main advantage of in-line burner reheat is ability to heat reactor catalyst to temperature levels where catalyst can be rejuvenated or regenerated. System pressure drop is also relatively low. Normally a portion of the acid gas feed is by-passed around the main combustion furnace and fed directly to the in-line reheater burner. Consequently, each in-line heater must be properly controlled to maintain the optimum H2S/SO2 ratio in the catalytic reactor feed for maximum sulfur production. Instead of controlling the air/acid gas ratio at only the main burner, this method requires control of air feed at four locations on a three catalytic reactor plant. Additionally, all acid gas does not pass through the thermal reactor where the largest amount of sulfur is produced. Some of acid gas also bypasses the first catalytic reactor, which generally produces about 30% of the total overall elemental sulfur. While this method generally results in better sulfur recovery than hot gas bypass, sulfur recovery is somewhat less than with the indirect methods.
Another potential disadvantage of in-line burner design is formation of SO3 in the system if air control is inaccurate. These sulfates can rapidly deactivate catalyst and, if the air rate is too low, produce carbon from hydrocarbon in the feed. Carbon is thus fed directly to the catalytic reactor, which can cause a premature catalyst change-out.
The most commonly used indirect reheat method is use of a steam-heated exchanger installed between each sulfur condenser and catalytic reactor. Process gas passes through tubes with condensing steam on the shell side. This is the most accurate control method and results in the best overall sulfur recovery performance. Also there is no loss of recovery efficiency at reduced unit thruput rates. The main disadvantages of this method are that pressure drop across these exchangers is higher than in other systems and the initial investment is more. Additionally, reactor inlet temperatures are limited to some level below that of the heating media. Thus catalyst regeneration is usually not possible with indirect reheat. However, indirect reheat avoids catalyst sulfation, carbon deposits, sulfur laydown, etc., thus virtually eliminating need for regeneration. Therefore, indirect reheat actually results in longer catalyst life.
INCINERATION
Tail gas is usually incinerated, since some sulfur always passes through the Claus process. Incineration oxidizes all sulfur compounds to SO2 such that gases can be discharged to the atmosphere via a stack. Stack height is theoretically a function of the amount and/or concentration of SO2 in the gases, although it is usually governed by local pollution regulations. Where no local or state regulations set the height, a safe discharge of SO2 can usually be made at about 100 feet, above grade.
Tail gas also can be fed to a downstream tail gas treater designed to recover most the sulfur in the stream. However, off-gas from the tail gas treater is frequently incinerated for the same reason, i.e., to convert sulfur compounds to SO2 before discharge to the atmosphere.
OPERATING GUIDES
Minimum temperature for stable combustion of the main acid gas feed stream is about 1,750oF. For better results this temperature should exceed 1,850°F, and preferably should be above 2,000°F. Maximum temperature usually is about 2,600°F.
Sulfur condenser outlet temperatures typically are 350- 400°F for the first two condensers and 270-320°F for the final two condensers. Lower sulfur condenser outlet temperatures result in higher overall sulfur recovery.
The approach to equilibrium for the Claus reaction is better realized at as low a temperature as possible. Conversely, carbon-sulfur compounds such as COS and CS2, which are formed in the combustion operation (Table 2), react more readily at higher temperatures (Table 3). Unfortunately, the higher reactor temperatures do not favor the Claus reaction. Consequently, the first catalytic reactor frequently is operated at a rather high temperature, while later reactors are operated at temperatures as low as possible. A typical three-reactor Claus unit will have the first reactor inlet at 450- 480°F, the second reactor at 390-430°F, and the third reactor at 370-410°F. This allows for maximum reaction of COS and CS2 in the first bed and maximum H2S-SO2 reaction in the second and third beds.
Typically, a temperature rise across each reactor occurs because the reaction is exothermic. The theoretical temperature increase generally ranges between 80 and 180°F for the first reactor, 20-60°F for the second reactor and 5-15°F for the third reactor. Actual measured plant temperatures are less than these values because of heat losses to the atmosphere.
MECHANICAL CONSIDERATIONS
Reaction Furnace. Design of the burner and furnace are very important since the operating temperature usually ranges between 1, 750°F and 2,600°F. These high temperatures require refractory lining to prevent overheating the steel vessel used in external furnaces. However, some furnaces place the main burner in the waste heat boiler where it is surrounded by water. This is called a "fire tube" unit and has no refractory. Normally the fire tube varies from a minimum of about 16 inches in diameter up to maximum of about 40 inches. The fire tube is the least expensive installation for small Claus units. However, the external reaction furnace is generally more practical for capacities over 30 LT/D.
Normal furnace residence time should be 0.5 to 1.5 seconds, depending on H2S concentration in the feed gas. Residence time less than 0.5 second can cause operating difficulties and inefficiencies.
Refractories capable of withstanding high temperature normally have relatively high alumina contents (> 60%). Unfortunately, such refractories, which are poor insulators, do not provide adequate protection for steel vessels. Consequently, a second refractory layer is frequently used to provide proper insulating qualities. These second refractories generally cannot withstand high flame temperature, thus forcing the two-layer system. The combination refractory is usually a minimum of 7 to 9 inches thick. Caution should be used in refractory design because overheated steel (> 650°F) results in direct sulfide attack while overcooled steel (< 300°F) causes acid corrosion in this system. Both phenomena cause premature failure of the furnace shell.
WASTE HEAT BOILER
Boilers other than large fire-tube type use smaller tubes which are exposed to hot combustion gases. Consequently, these tubes must be protected to ensure satisfactory life. Additionally, the inlet tube sheet is protected from direct contact with hot gases by use of about 3 inches of refractory.
The inlet end of each tube is shielded by inserting into the tube a ceramic ferrule that extends about 6 inches beyond the inlet tubesheet. This ferrule also protrudes about 2 to 3 inches in front of the inlet tubesheet to prevent hot gas from contacting the tube directly at the critical junction of tube and tubesheet. Use of ceramic ferrules is imperative if reasonable tube life is to be expected. For best results, these ceramic ferrules are wrapped with a thin layer of insulation (1/8-3/8 in. thick).
Tube size ranges from 2 to 6 inches for most boilers. Generally, welded (ERW) tubes are installed, but occasionally seamless tubes are used. Tube spacing is based on a minimum ligament dimension of 0.75 -1.0 in. Design mass velocity ranges between 1.0 and 8.0 Ib/sec/ft2 based on allowable tube-side pressure drop.
Tubesheet design (ASME code, Section I) for these vessels is greatly influenced by thermal/mechanical stress at the tube attachments. Tubesheets are usually thin (¾ to 1½ in.), resulting in acceptable temperature profiles at tube welds, tube sheet ligaments between tubes, and for portions not backed by water. Deflection that occurs during operation must be considered in order to reduce additional stress transmitted to the tube attachment. Boilers that are fully flooded have tube patterns arranged to account for bending stress at the outer boundaries of the tube sheets, whereas kettle-type boilers have stayrods to stiffen portions of tubesheets not supplied by tubes. Where possible, boilers should be provided with bolted inspection ports at the end and/or beginning of each pass.
Proper process design of the boiler requires that heat ex- change calculations include effects of radiation transfer as well as normal convection transfer. If radiation is ignored in calculating surface area requirements, the Claus boiler is usually appreciably over-sized. This can lead to operating problems because a waste heat boiler that is too large can cause premature sulfur condensation, improper reheat, viscous sulfur formation, etc.
SULFUR CONDENSERS
Sulfur condensers are built either as single-pass or multi- pass units (up to four tube passes in a single shell). In either case, they are generally designed with a minimum tube size of 1 inch. Normally 12 BWG steel tubes are used and installed with a ½ to ¾-in. ligament between the outer walls of the tubes. Welded (ERW) tubes are generally used.
Sulfur condensers operate at heat fluxes much lower than waste heat boilers and usually at much lower steam pressures. Both factors significantly reduce design criteria for tube sheets and tube attachments.
Sulfur condensers may be designed in accordance with ASME Section I or Section VIII Codes. In either case, tubesheet design need only meet ASME rules of design to pro- vide satisfactory service. Sulfur condenser tube attachments are typically rolled, seal welded, and re-rolled.
Design mass velocity varies from 3.0 to 8.0 lb/sec/ft2. Care must be taken to keep mass velocity sufficiently high during turndown conditions to prevent "sulfur misting." If "sulfur misting" occurs, liquid sulfur will not separate adequately from the process gas in the condenser separator chambers.
The liquid sulfur drain leg and nozzle should be steam- jacketed to prevent plugging by solid sulfur, and the drains should be installed for easy access for cleaning and disassembly. If possible, the sulfur condenser should be the low point in the Claus unit to allow any condensed sulfur to freely drain into ,the condenser and flow out through the drain legs.
Inspection ports and manways at each end of the condenser should be bolted to allow access to tubes for cleaning and inspection.
Vapor-liquid separator chambers are used to separate liquid sulfur from uncondensed process gas. These are made as either integral parts of the condenser or as separate vessels. Most sulfur condensers are designed to generate steam on the shell side while the gases are cooled and sulfur is condensed on the tube side. Design steam pressure is usually 20 to 80 psig.
CATALYST BEDS
Most catalytic reactors use a design flow of 2.0 to 4 mole& per hour of process gas per cubic foot of catalyst bed. Normally, activated alumina catalyst (density equals 45-53 lb/ft3) is supported at the bottom of the bed with a 3 to 6-inch depth of more dense material (84-100 lb/ft3). Support material prevents catalyst migration from the reactor to the sulfur condenser, can plug sulfur drain legs and condenser tubes, necessitating a plant shutdown for cleaning. Catalyst bed support material is usually provided with a carbon steel sup- port floor and stainless steel screen. A minimum of 3 inches of support material is also recommended on the top of the catalyst bed to serve as a gas flow distributor.
Frequently, catalyst beds are placed in a single horizontal vessel for units less than 100 LT/D. Each bed is separated by internal partition plates. For the larger units, individual catalyst beds are normally used. Although vertical reactors are used, they are not normally economical in units less than 800 LT/D. Internal refractory lining of these vessels is not necessary unless in-place catalyst regeneration is planned, in which case the support grating must be designed for elevated temperatures. Each catalyst bed should have a minimum of 3 inches of insulation outside if no internal refractory is used. When internal refractory lining is supplied, the outside insulation thickness can be reduced to 1 to 2 inches.
Nozzles located in the bottom of catalytic reactors should be installed flush with the vessel interior, otherwise internal projections act as weirs, allowing corrosive material to accumulate and corrode carbon steel walls.
PIPING
There are two major areas of piping concern: liquid sulfur drain lines and vapor process lines. Since sulfur freezes below 245°F, liquid sulfur drain lines must be adequately heated and insulated to prevent sulfur solidification. Main process lines are also heavily insulated to prevent vapor sulfur from condensing and/or subliming. However, the more critical concern in large process piping is allowance for thermal expansion.
Process lines expand because outlet temperatures from catalytic reactors range between 400 and 680°F. Expansion of these lines can cause severe damage to vessels, heat exchangers, and pipe if not adequately designed. Either stainless steel convoluted expansion joints or expansion "loops" are used on catalytic reactor outlets. Convoluted joints should be installed in vertical pipe sections only and should be insulated on the outside.
Carbon steel piping is adequate. Schedule 40 is normally used for small units. However, units requiring 14-inch or larger lines need only standard weight pipe. For process lines over 30 inches in diameter, piping thickness can be the same as for catalytic reactor vessel walls.
Typically, condensers are sealed by liquid sulfur, since it drains into the sulfur collection vessel. This prevents uncondensed gases from escaping to the atmosphere via the sulfur pit. Molten sulfur drain lines, which usually include both horizontal and vertical sections, need to have installed adequate facilities for clean-out to avoid premature unit shut-down for unplugging drain lines.
The best method of heating liquid sulfur drain lines is with jacketed pipe. Usually steam is used as a heat source, but hot oil is also satisfactory. For best performance, the system should be designed to maintain molten sulfur at a minimum temperature of 280°F. Generally, it is best not to use superheated steam because of the danger of overheating sulfur. Above about 325°F, the sulfur viscosity increases rapidly, preventing free flow from condensers to storage (Fig. 1).
Since liquid sulfur seals the condenser to prevent vapors from getting to the atmosphere, it is imperative that the "net" liquid column be sufficient to withstand the maxi- mum operating pressure, usually the air blower maximum discharge pressure.
INCINERATOR/STACK
All sulfur compounds can be oxidized to SO2 both thermally and catalytically. Thermal oxidation normally occurs at temperatures between 1,000 and 1,500°F in the presence of excess oxygen. The penalty for using insufficient oxygen and/or lower temperatures is that some H2S may not be converted to SO2; thus H2S is discharged to the atmosphere. Using too much oxygen consumes costly fuel.
Claus unit tail gas will not support combustion because there are too few combustibles present (<3%). Thus, oxidation of all sulfur components in tail gas to SO2 requires use of external fuel and air.
Catalytic incineration, a recent development, works when tail gas is heated to 750-900°F. Heated gas and heated air in contact with a fixed-bed catalytic reactor promote oxidation of sulfur components to SO2.
Air is fed by natural draft for most thermal incinerators, but for those operating with waste heat recovery sections, a blower is used. Usually at least 25% excess air is used for proper tail gas incineration.
Incinerator and stack are often combined into a single vessel, called an incinerator-stack. In this convenient design, the incinerator is usually an enlarged base and the stack of a small diameter extending upward from the incinerator. A horizontal burner normally mounts into the incinerator side. Tail gas can be fed either through the burner or into the incinerator adjacent to the burner via another nozzle.
Normally the incinerator is sized for at least 0.5-1.5 seconds residence time.
Most incinerator-stacks are constructed with a steel shell lined with heat-resistant refractory. Such stacks can be free- standing, or guy- or derrick-supported structures. Selection of support type is dictated by stack height, windload and/or, seismic criteria for the site. A guy-supported stack is most: economical; however, a larger plot space is needed for guy anchors and cables. A free standing stack is most commonly: used for heights not exceeding 250 ft. Taller stacks are usually derrick-supported.
Incinerators are generally designed for a maximum operating temperature of 2,000°F. Thus refractories rated as low as 2,200°F have been successfully used in incinerator-stack installations. Normally, one layer of refractory is sufficient, and is usually an insulating castable rated at service conditions of 2,200°F or above.
Vertical incinerators installed at the base of the stack require proper protection for the incinerator steel floor. The preferred protection is circulation of ambient air below the steel floor. For best results, the steel should be kept cooler than 650- 700°F, and hotter than 300°F. Above about 650°F, steel can be directly sulfided. Below 300°F, water can condense against the shell, absorb SO2 and form a very strong, highly corrosive acid. Accomplishing these temperature goals requires careful design of both inside refractory lining and outside insulation. Normally, refractory thickness to protect the incinerator shell (either vertical or horizontal type) is 2 to 4 inches. The incinerator floor on vertical units normally employs 4 to 6 inches of refractory.
The incinerator-stack should be insulated on the outside to prevent low shell temperature. This insulation can be an air gap (usually 3 to 4 inches deep) with either a stainless steel or aluminum sheathing around the incinerator-stack, or a <1.0 inch-thick layer of blanket-type insulation covered with aluminum or stainless steel. Over-insulation can cause steel shell overheating.
Most government air control units (federal, state and/or local) require that emissions be monitored on a periodic basis. Thus the incinerator-stack is usually equipped with plat- forms, sample nozzles and utilities located at the proper level. This equipment permits periodic measurement of stack flowrate and stack gas composition for use in determining sulfur emission rates.
Where continuous monitoring is required, SO2 stack gas analyzers are installed on the stack. These instruments are often coupled with flow meters to develop a continuous record of flow and SO2 content.
Typical stack velocities for design are 40 to 100 ft/sec, with allowable pressure drop generally determining actual design flowrate.
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