Sulfur Recovery

CHAPTER

Sulfur Recovery

11

Sulfur is an extremely useful element. Its largest application is for the manufacture of fertilizers, with other principal users including rubber industries, cosmetics, and pharmaceuticals. Sulfur is present in many raw industrial gases and in natural gas in the form of hydrogen sulfide (H2S). The noxious hydrogen sulfide fumes that characterize many gas processing and refinery operations and petroleum production sites represent a genuine threat to our environment. Sulfur removal facilities are located at the majority of oil and gas processing facilities throughout the world. The sulfur recovery unit does not make a profit for the operator, but it is an essential processing step to allow the overall facility to operate, as the discharge of sulfur compounds to the atmosphere is severely restricted by environmental regulations. Concentration levels of H2S vary significantly depending upon their source. H2S produced from absorption processes, such as amine treating of natural gas or refinery gas, can contain 50–75% H2S by volume or higher. Many other processes can produce H2S with only ppm concentration, but in quantities that preclude the gases from being vented without further treatment. Sulfur is present in natural gas principally as hydrogen sulfide and, in other fossil fuels, as sulfurcontaining compounds that are converted to hydrogen sulfide during processing. The H2S, together with some or all of any carbon dioxide (CO2) present, is removed from the natural gas or refinery gas by means of one of the gas treating processes described in Chapter 10. The resulting H2S-containing acid gas stream is flared, incinerated, or fed to a sulfur recovery unit. This chapter is concerned with recovery of sulfur by means of the modified Claus and Claus tail gas cleanup processes.

11.1 The Claus process The large variations in concentrations and flows require different methods for H2S removal and sulfur recovery. For relatively small quantities of H2S/sulfur, scavenger processes are often used. For sulfur quantities up to approximately 5 long tons per day of sulfur, liquid reduction–oxidation (redox) processes are common. The sulfur is produced as an aqueous slurry. Direct oxidation can sometimes be utilized for low H2S concentrations to produce high-quality liquid sulfur. The Claus process is the most widely used process for conversion of H2S to elemental sulfur. Variations of the Claus process, direct oxidation and liquid redox processes, can overlap other processes’ applicability ranges. Figure 11.1 is a sulfur recovery process applicability chart, which presents the relative ranges of technology applications. The Claus process was invented in 1883 by the English scientist Carl Friedrich Claus. The basic Claus process mixed hydrogen sulfide with oxygen and passed the mixture across a preheated catalyst bed. The end products were sulfur, water, and thermal energy. Because the process performed best at 400–600
F, and the reaction heat could be removed only by direct radiation, only a small amount of H2S could be processed at one time without overheating the Natural Gas Processing. http://dx.doi.org/10.1016/B978-0-08-099971-5.00011-8 Copyright © 2014 Elsevier Inc. All rights reserved.

519

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FIGURE 11.1 Sulfur recovery process applicability chart representing the relative ranges of technology applications.

reactor. The process was improved in 1938 by the addition of free-flame oxidation ahead of the catalyst bed and by revising the catalytic step. This “modified Claus process” greatly increased the sulfur yield and is the basis of most sulfur recovery units (SRUs) in use today.

11.1.1 How the process works Feed gas for a Claus sulfur recovery unit usually originates in an acid gas sweetening plant. The stream, containing varying amounts of H2S and CO2, is saturated with water and frequently has small amounts of hydrocarbons and other impurities in addition to the principal components. In a typical unit (Figure 11.2), H2S-bearing gas enters at about 8 psig and 120
F. Combustion air is compressed to an equivalent pressure by centrifugal blowers. Both inlet streams then flow to a burner, which fires into a reaction furnace. The free-flame modified Claus reaction can convert approximately 50–70% of the sulfur gases to sulfur vapor. The hot gases, up to 2500
F, are then cooled by generating steam in a waste heat boiler. The gases are further cooled by producing low-pressure steam in a separate heat exchanger, commonly referred to as a sulfur condenser. This cools the hot gases to approximately 325
F, condensing most of the sulfur that has formed up to this point. The resultant liquid sulfur is removed in a separator section of the condenser and flows by gravity to a sulfur storage tank. Here it is kept molten, at approximately 280
F, by steam coils. Sulfur accumulated in this reservoir is pumped to trucks or rail cars for shipment. The Claus process as used today is a modification of a process first used in 1883 in which H2S was reacted over a catalyst with air (oxygen) to form elemental sulfur and water. H2 S þ 1=2 O2 /S þ H2 O

(11.1)

Control of this highly exothermic reaction was difficult and sulfur recovery efficiencies were low. In order to overcome these process deficiencies, a modification of the Claus process was developed and introduced in 1936 in which the overall reaction was separated into: (1) a highly

11.1 The Claus process

Reactor No.1

HP steam

Furnace

Reheater No.1

WHB

KO drum

Reheater No.2

Reactor No.3

Reheater No.3

BFW

Acid gas

LP steam

LP steam

Condenser No. 1

Condenser No. 2

BFW

LP steam Condenser No. 3

BFW

BFW

Air

Water Dashed line represents split flow prodces

Reactor No.2

521

LP steam

Tail gas

Condenser No. 4

BFW Liquid sulfur

Air blower Sulfur pit

Typical straight through sulfur plant FIGURE 11.2 Typical straight-through sulfur plant.

exothermic thermal or combustion reaction section, in which most of the overall heat of reaction (from burning one-third of the H2S and essentially 100% of any hydrocarbons and other combustibles in the feed) is released and removed; and (2) a moderately exothermic catalytic reaction section, in which sulfur dioxide (SO2) formed in the combustion section reacts with unburned H2S to form elemental sulfur. The principal reactions taking place (neglecting those of the hydrocarbons and other combustibles) can then be written as follows: Thermal or Combustion Reaction Section H2 S þ 11=2 O2 /SO2 þ H2 O

(11.2)

DH@25
C ¼ 518;900 kJ Combustion and Catalytic Reaction Sections 3 2H2 S þ SO2 / SX þ 2H2 O X DH@25
C ¼ 96;100 kJ

(11.3)

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CHAPTER 11 Sulfur Recovery

Overall Reaction 3 3H2 S þ 11=2 O2 / SX þ 3H2 O X

(11.4)

DH @ 25
C ¼ 615;000 kJ

11.1.2 Simplified process description The hot combustion products from the furnace at 1000–1300
C enter the waste heat boiler and are partially cooled by generating steam. Any steam level from 3 to 45 barg can be generated. •

• •

• • •

The combustion products are further cooled in the first sulfur condenser, usually by generating low-pressure steam at 3–5 barg. This cools the gas enough to condense the sulfur formed in the furnace, which is then separated from the gas and drained to a collection pit. In order to avoid sulfur condensing in the downstream catalyst bed, the gas leaving the sulfur condenser must be heated before entering the reactor. The heated stream enters the first reactor, containing a bed of sulfur conversion catalyst. About 70% of the remaining H2S and SO2 in the gas will react to form sulfur, which leaves the reactor with the gas as sulfur vapor. The hot gas leaving the first reactor is cooled in the second sulfur condenser, where low-pressure steam is again produced and the sulfur formed in the reactor is condensed. A further one or two more heating, reaction, and condensing stages follow to react most of the remaining H2S and SO2. The sulfur plant tail gas is routed either to a tail gas treatment unit for further processing or to a thermal oxidizer to incinerate all of the sulfur compounds in the tail gas to SO2 before dispersing the effluent to the atmosphere.

For the usual Claus plant feed gas composition (water saturated with 30–80 mol% H2S, 0.5–1.5 mol% hydrocarbons, the remainder CO2), the modified Claus process arrangement results in thermal section (burner) temperatures of about 980–1370
C. The principal molecular species in this temperature range is S2 and conditions appear favorable for the formation of elemental sulfur by direct oxidation of H2S Eqn (11.5) rather than by the Claus reaction Eqn (11.6). However, both laboratory and plant measurements indicate that the more highly exothermic oxidation of H2S to SO2 Eqn (11.2) predominates and the composition of the equilibrium mixture therefore is determined by the slightly endothermic Claus reaction Eqn (11.6). 2H2 S þ O2 /2H2 O þ S2

(11.5)

DH@25
C ¼ 314;500 kJ 3 2H2 S þ SO2 /2H2 O þ S2 2 DH@25
C ¼ þ47;500 kJ

(11.6)

11.1 The Claus process

523

To attain an overall sulfur recovery level above about 70%, the thermal, or combustion, section of the plant is followed by one or more catalytic reaction stages. Sulfur is condensed and separated from the process gases after the combustion section and after each catalytic reaction stage in order to improve equilibrium conversion. Gases leaving the final sulfur condensation and separation stage may require further processing. These requirements are established by local, state, or national regulatory agencies. These requirements can be affected by the size of the sulfur recovery plant, the H2S content of the plant feed gas, and the geographical location of the plant.

11.1.3 Claus process considerations The Claus sulfur recovery process includes the following process operations: • •

•

•

•

Combustiondburn hydrocarbons and other combustibles and one-third of the H2S in the feed. Waste heat recoverydcool combustion products. Because most Claus plants produce 1030–3450 kPa (ga) steam at 185–243
C, the temperature of the cooled process gas stream is usually about 315–370
C. Sulfur condensingdcool outlet streams from waste heat recovery unit and from catalytic converters. Low-pressure steam at 345–480 kPa (ga) is often produced and the temperature of the cooled gas stream is usually about 177
C or 127–149
C for the last condenser. ReheatingdReheat process stream, after sulfur condensation and separation, to a temperature high enough to remain sufficiently above the sulfur dew point, and generally, for the first converter, high enough to promote hydrolysis of carbonyl sulfide (COS) and carbon disulfide (CS2) to H2S and CO2. COS þ H2 O/CO2 þ H2 S

(11.7)

CS2 þ 2H2 O/CO2 þ 2H2 S

(11.8)

Catalytic conversiondPromote reaction of H2S and SO2 to form elemental sulfur Eqn (11.3).

11.1.4 Catalytic reaction Any further conversion of the sulfur gases must be done by catalytic reaction. The gas is reheated by one of several means and is then introduced to the catalyst bed. The catalytic Claus reaction releases more energy and converts more than half of the remaining sulfur gases to sulfur vapor. This vapor is condensed by generating low-pressure steam and is removed from the gas stream. The remaining gases are reheated and enter the next catalytic bed. This cycle of reheating, catalytic conversion, and sulfur condensation is repeated in two to four catalytic steps. A typical SRU has one free-flame reaction and three catalytic reaction stages. Each reaction step converts a smaller fraction of the remaining sulfur gases to sulfur vapor, but the combined effect of the entire unit is to reduce the hydrogen sulfide content to an acceptable level.

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CHAPTER 11 Sulfur Recovery

11.1.5 High yields plus energy Claus sulfur plants can normally achieve high sulfur recovery efficiencies. For lean acid gas streams, the recovery typically ranges from 93% for two-stage units (two catalytic reactor beds) up to 96% for three-stage units. For richer acid gas streams, the recovery typically ranges from 95% for two-stage units up to 97% for three-stage units. Since the Claus reaction is an equilibrium reaction, complete H2S and SO2 conversion is not practical in a conventional Claus plant. The concentration of contaminants in the acid gas can also limit recovery. For facilities where higher sulfur recovery levels are required, the Claus plant is usually equipped with a tail gas cleanup unit to either extend the Claus reaction or capture the unconverted sulfur compounds and recycle them to the Claus plant. All Claus SRUs produce more heat energy as steam than they consume. This is particularly true for those plants equipped with waste heat boilers on the incinerator. The steam produced can be used for driving blowers or pumps, reboiler heat in the gas treating or sour water stripper plants, heat tracing, or any of a number of other plant energy requirements. Following are some sulfur recovery and tail gas cleanup methods: • • • • • • •

Straight-through Claus Split-flow Claus Direct oxidation Acid gas enrichment Oxygen enrichment Cold bed adsorption Shell Claus off-gas treating

11.2 Technology overview This section presents an overview of the technologies available through several process plants.

11.2.1 Types of plants Claus sulfur recovery units are generally classified according to the method used for the production of SO2 and the method used to reheat the catalyst bed feeds. The various reheat methods can be used with any SO2 production method, whereas the technique used for the production of SO2 is determined by the H2S content of the acid gas feedstock. Most sulfur recovery plants utilize one of three basic variations of the modified Claus process: “straight-through,” “split-flow,” or “direct oxidation.” “Acid gas enrichment” can be applied ahead of the SRU to produce a richer acid gas stream and “oxygen enrichment” may be used in combination with any of these variations. These three varieties of the modified Claus process differ in the method used to oxidize H2S and produce SO2 ahead of the first catalytic reactor. The first two processes use a flame reaction furnace ahead of the catalytic stages. The third process reacts oxygen directly with the H2S in the first catalytic reactor to produce the SO2.

11.2 Technology overview

525

11.2.2 Straight-through process A “straight-through” unit passes all the acid gas through the combustion burner and reaction furnace. The initial free-flame reaction usually converts more than half of the incoming sulfur to elemental sulfur. This reduces the amount that must be handled by the catalytic sections and thus leads to the highest overall sulfur recovery. The amount of heat generated in the reaction depends on the amount of H2S available to the burner. With rich acid gas (60–100% H2S), the reaction heat keeps the flame temperature above 2200
F. When the gas is leaner, the flame temperature is reduced; the greater mass is heated to a lower temperature. If the temperature falls below a critical point, approximately 1800–2000
F, the flame becomes unstable and cannot be maintained. This point is usually reached when the acid gas has an H2S content of 50% or less. The problem can be overcome, within limits, by preheating the acid gas and/or air before it enters the burner. However, the lower the H2S content, the higher the preheat requirement becomes; when the gas composition falls below about 40% H2S, this approach ceases to be practical.

11.2.3 Split-flow process The second method of SO2 production, known as the “split-flow” technique, is used to process leaner acid gases with 15–50% H2S content. In these units, at least one-third of the acid gas flows into the combustion burner and the balance usually bypasses the furnace entirely. Enough H2S is burned to provide the necessary 2:1 ratio of H2S to SO2 in the catalyst beds. The flame temperature is kept above the minimum, since the constant amount of heat supplied is absorbed by a lower mass of gas. The free-flame Claus reaction is reduced or eliminated entirely by this approach, since little or no H2S is available to react in the furnace. This results in a slight reduction of the overall sulfur recovery.

11.2.4 Split-flow process for ammonia destruction A variation of the split-flow process is often applied in refinery SRUs that must process sour water stripper (SWS) off-gas and destroy the ammonia it contains. Efficient ammonia destruction is critical for SRUs in refineries, since ammonia can combine with the sulfur compounds in the process gas to form salts that precipitate in the lower-temperature section of the Claus unit. Accumulation of such ammonium salts would lead to unreliable operation and unacceptable maintenance costs. All of the SWS gas is routed to the combustion burner along with a portion of the amine acid gas, so that at least one-third of the total H2S is supplied to the burner. This creates a high-temperature combustion zone at the inlet end of the reactor furnace where the ammonia breaks down into nitrogen and water by thermal decomposition. The remainder of the amine acid gas is injected into the middle part of the reactor furnace, where it mixes with the burner combustion products. The outlet end of the furnace provides residence time for the SO2 produced by the burner to react with the H2S in the bypass acid gas and form sulfur, and for any hydrocarbons in the bypass acid gas to oxidize. An optical pyrometer is typically used to monitor the temperature in the inlet section of the furnace, and is often used to adjust the amount of bypass acid gas to control the temperature at the desired value.

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CHAPTER 11 Sulfur Recovery

11.2.5 Direct oxidation process When the H2S concentration is below about 15% in the acid gas, the direct oxidation version of the modified Claus process may be used. Rather than using a burner to combust H2S to form SO2, the direct oxidation process catalytically reacts oxygen with H2S by mixing the air and acid gas upstream of a catalytic reactor. As SO2 forms, it then reacts with the remaining H2S via the Claus reaction to form sulfur. The direct oxidation is typically followed by one or more standard Claus reactors to produce and recover additional sulfur. The direct oxidation process is sensitive to catalyst deactivation by contaminants in the acid gas feed (particularly hydrocarbons), so it is not used as much as the other Claus process varieties.

11.3 Acid gas enrichment When the acid gas produced by the gas treating system is low in H2S concentration, it is sometimes advantageous to “enrich” the acid gas by contacting it with a second solvent. The second solvent is typically a selective solvent designed to absorb essentially all of the H2S from the acid gas while letting most of the remainder (generally CO2) “slip” through. The enriching process can often raise the H2S concentration of the SRU feed gas by a factor of five or more. Not only does this allow using smaller equipment in the SRU, but it can often allow a more reliable SRU process to be used, such as a straight-through Claus process instead of a direct-oxidation Claus process.

11.4 Oxygen enrichment Since air is approximately 79% nitrogen and 21% oxygen, the introduction of air to supply the oxygen for combustion of H2S to SO2 also introduces a large quantity of nitrogen. When air is used as the oxygen source, approximately 5.6 mol of nitrogen is introduced into the gas flow for every mol of H2S that is burned. Nitrogen does not react and the added mass of the nitrogen lowers the adiabatic flame temperature in the reaction furnace. The nitrogen must also be heated, cooled, and reheated through the combustion, sulfur condensation, and reheat ahead of the reactors. Pure oxygen or enriched sources of oxygen can be used instead of air in the Claus process. Higher flame temperatures can be achieved with lower H2S concentrations. In addition, the relative equipment sizes can be reduced in proportion to the amount of nitrogen that is not introduced with oxygen for combustion.

11.5 Reheat methods Gas leaving the sulfur condenser is at its sulfur dew point temperature. Since the catalytic reaction requires a higher temperature for proper operation, the gas must be reheated before entering the reactor. This can be done directly (internally) or indirectly (externally). The method chosen is an important characteristic of any sulfur recovery unit.

11.5 Reheat methods

527

11.5.1 Direct reheat Two direct reheat methods are commonly employed: “inline burning” and “hot gas bypass.” The first of these burns fuel or acid gas with air in an inline burner, allowing the combustion products to mix directly with the process gas flow. The second method bypasses a portion of the hot boiler outlet gas around the sulfur condenser and mixes it with the reactor feed stream. Both methods have an adverse effect on overall sulfur recovery. In the case of the inline burner, it is difficult to maintain precise control of the overall air/H2S ratio. Any excess of deficiency of oxygen to the inline burner can cause undesirable reactions in the catalyst beds. Too little oxygen can lead to carbon deposits on the catalyst, reducing its activity. Too much oxygen can lead to catalyst deactivation, increased corrosion, and, in extreme cases, fire in the reactor. All of these result in reduced sulfur recovery. The “hot gas bypass” method allows a portion of the sulfur-bearing process gas to skip one or more catalytic reaction and sulfur condensing steps. When this happens, the sulfur gases have less opportunity to convert to sulfur vapor and the overall sulfur recovery drops. With both methods, the recovery loss is more pronounced in a lean acid gas unit than it is in a rich gas SRU.

11.5.2 Indirect reheat The indirect reheat method uses an outside heat source to raise the temperature of the acid gases in a heat exchanger. Although this requires additional equipment, it eliminates the conversion loss problems associated with direct reheat. There are three common variations of indirect reheat: “gas–gas exchange,” “fuel gas firing,” and “steam reheat.” Gas–gas exchangers use a sulfur condenser feed to reheat the sulfur condenser outlet gas. This exchange works well as long as the temperature of the heating gas is maintained above a minimum level. If the upstream catalyst bed has lost some of its efficiency, however, the drop in conversion will lower the outlet temperature. Less heat energy will be available for reheat. As a result, the following catalyst bed will perform less efficiently and overall sulfur recovery will decrease. Steam reheat and fuel gas-fired heaters have none of the problems associated with the gas–gas exchange method described above. Fuel gas firing uses a conventional fired heater; the acid gases are heated in tubes and the combustion products are vented to the atmosphere. For this reason, fuel gas firing usually involves higher utility costs than the other indirect methods. Steam reheat can usually be accomplished by utilizing a portion of the steam produced by the SRU itself, often in the same vessel with the source of steam production. Steam reheat is the method commonly preferred in better-quality sulfur plant designs. Table 11.1 can be used as a guide in Claus process selection.

Table 11.1 Claus Plant Configurations Feed H2S Concentration (mol%)

Claus Variation Suggested

55e100 30e55 15e30 10e15 5e10

Straight-through Straight-through or straight-through with acid gas and/or air preheat Split-flow or straight-through with feed and/or air preheat Split-flow with acid gas and/or air preheat Split-flow with fuel added or with acid gas and air preheat, or direct oxidation or sulfur recycle Sulfur recycle or variations of direct oxidation or other sulfur recovery processes

<5

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CHAPTER 11 Sulfur Recovery

11.6 Combustion operation Most Claus plants operate in the “straight-through” mode. The combustion is carried out in a reducing atmosphere with only enough air (1) to oxidize one-third of the H2S to SO2, (2) to burn hydrocarbons and mercaptans, and (3) for many refinery Claus units, to oxidize ammonia and cyanides. Air is supplied by a blower and the combustion is carried out at 20–100 kPa (ga), depending on the number of converters and whether a tail gas unit is installed downstream of the Claus plant. Numerous side reactions can also take place during the combustion operation, resulting in such products as hydrogen (H2), carbon monoxide (CO), COS, and CS2. Thermal decomposition of H2S appears to be the most likely source of hydrogen since the concentration of H2 in the product gas is roughly proportional to the concentration of H2S in the feed gas. Formation of CO, COS, and CS2 is related to the amounts of CO2 and/or hydrocarbons present in the feed gas. Plant tests indicate concentrations of H2 and CO in the product gas to be approximately at equilibrium at reaction furnace temperatures; Table 11.2 indicates potential COS and CS2 formation in the Claus furnace. Heavy hydrocarbons, ammonia, and cyanides are difficult to burn completely in a reducing atmosphere. Heavy hydrocarbons may burn partially and form carbon, which can cause deactivation of the Claus catalyst and the production of off-color sulfur. Ammonia and cyanides can burn to form nitric oxide (NO), which catalyzes the oxidation of sulfur dioxide (SO2) to sulfur trioxide (SO3); SO3 causes sulfation of the catalyst and can also cause severe corrosion in cooler parts of the unit. Unburned ammonia may form ammonium salts, which can plug the catalytic converters, sulfur condensers, liquid sulfur drain legs, etc. Feed streams containing ammonia and cyanides are sometimes handled in a special two-combustion-stage burner or in a separate burner to ensure satisfactory combustion. Flame stability can be a problem with low H2S content feeds (a flame temperature of about 980
C appears to be the minimum for stable operation). The split-flow, sulfur recycle, or direct oxidation process variations often are utilized to handle these H2S-lean feeds; but in these process schemes, any hydrocarbons, ammonia, cyanides, etc., in all or part of the feed gas are fed unburned to the first catalytic converter. This can result in the cracking of heavy hydrocarbons to form carbon or carbonaceous deposits and the formation of ammonium salts, resulting in deactivation of the catalyst and/or plugging of equipment. A method of avoiding these problems while still improving flame stability is to preheat the combustion air and/or acid gas, and to operate “straight-through.”

11.7 Sulfur condenser operation Sulfur is condensed ahead of the first catalytic converter (except in the case of split-flow operation) and following each catalytic converter in order to promote the Claus reaction. These condensers (other than the one following the last catalytic converter) are typically designed for outlet temperatures of 166–182
C, which results in a condensed liquid sulfur of reasonably low viscosity and a metal skin temperature (on the process gas side) above the sulfurous/sulfuric acid dew point. The final sulfur condenser outlet temperature can be as low as 127
C, depending on the cooling medium available. A large temperature difference between process gases and cooling medium should

11.8 Waste heat recovery operation

529

Table 11.2 Potential COS and CS2 Formation in Claus Furnaces Feed Composition (mol%) Hydrocarbon (as C3H8)

Water

CO2

H2S

COS, CS2 Formation, % of Sulfur in Feed

0 0 0 0 0 0 0 0 2 2 2 2 2 2 2 2 4 4 4 4 4 4 4 4

6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6

4 14 24 34 44 54 64 74 4 14 24 34 44 54 64 74 4 14 24 34 44 54 64 74

90 80 70 60 50 40 30 20 88 78 68 58 48 38 28 18 86 76 66 56 46 36 26 16

0.5 1.5 2.5 3.5 4.5 5.5 6.5 7.5 2 3 4.5 6 7 9 11 14 3.5 5 6 8 10 12 14 18

(a) Maximum. Actual production varies with operating temperature and pressure, residence time, burner mixing, and burner efficiency. (b) Units feeding <30% H2S may operate other than “straight-through,” causing reduced COS and CS2 production proportional to amount fed to main burner.

be avoided, however, because of the possible formation of sulfur fog; this is especially important for the final sulfur condenser.

11.8 Waste heat recovery operation Most Claus plants cool the process gases, leaving the combustion section by generating steam in a firetube waste heat boiler. Steam pressures usually range between 1035 and 3450 kPa (ga). The waste heat boiler outlet temperature is therefore normally above the sulfur dew point of the process gases; however, some sulfur may condense, especially during partial loads, and provision should be made to

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CHAPTER 11 Sulfur Recovery

drain this sulfur from the process stream (or the piping should be arranged so the sulfur will drain through downstream equipment). Other methods of cooling the hot combustion gases include the use of glycol–water mixtures, amine solutions, circulating cooling water (no boiling), and oil baths. The utilization of one of these alternate cooling fluids can be especially advantageous at locations where good-quality boiler feed water is not available, or where steam generation is not desired. Some small Claus units use a closed steam system. Steam is generated at 140–210 kPa (ga), condensed with air in an elevated condenser, and the steam condensate returned by gravity to the boiler as feed water.

11.9 Catalyst converter operation The Claus reaction is exothermic at converter temperatures, and the reaction equilibrium is favored by lower temperatures. However, COS and CS2 hydrolyze more completely at higher temperatures, as shown by Figure 11.3. The first catalytic converter is therefore frequently operated at temperatures high enough to promote the hydrolysis of COS and CS2; the second and third catalytic converters are operated at temperatures only high enough to obtain acceptable reaction rates and to avoid liquid sulfur deposition and associated catalyst deactivation. A three-converter Claus unit will utilize inlet

FIGURE 11.3 Hydrolysis of COS and CS2 with activated alumina catalyst in sulfur converter (GPSA, 2004) [1].

11.10 Claus tail gas treating process selection

531

temperatures in the following range: (1) first converter, 232–249
C; (2) second converter, 199–221
C; (3) third converter, 188–210
C. A temperature rise occurs across each catalytic converter because both the Claus and COS/CS2 hydrolysis reactions are exothermic. The temperature rise will generally be 44–100
C for the first converter, 14–33
C for the second converter, and 3–8
C for the third converter. Because of heat losses, measured temperatures for the third converter will often show a small temperature drop. The foregoing is based on using the regular Claus catalyst in all of the converters. Regular catalyst is made of activated alumina (Al2O3). The primary function of activated alumina is to increase the rate of the Claus reaction and ensure full equilibrium conversion to sulfur. It also helps hydrolyze the carbon sulfides, COS and CS2, to H2S and CO2 in the first converter Eqn (11.7) and (11.8); but it achieves reasonable hydrolysis only at high temperatures of 300–340
C (Figure 11.3), which reduces the equilibrium conversion to sulfur in the Claus reaction (Figure 22.2). A catalyst made of activated titania (i.e., titanium dioxide; TiO2) can achieve greater than 90% hydrolysis of the carbon sulfides at temperatures of 300–340
C.

11.10 Claus tail gas treating process selection With the sulfur content of crude oil and natural gas on the increase and tightening sulfur content in fuels, refiners and gas processors are pushed for additional sulfur recovery capacity. At the same time, environmental regulatory agencies of many countries continue to promulgate more stringent standards for sulfur emissions from oil, gas, and chemical processing facilities. It is necessary to develop and implement reliable and cost-effective technologies to cope with the changing requirements. In response to this trend, several new technologies are now emerging to comply with the most stringent regulations. Typical sulfur recovery efficiencies for Claus plants are 90–96% for a two- stage and 95–98% for a three-stage plant. Most countries require sulfur recovery efficiency in the range of 98.5–99.9%þ. Therefore the sulfur constituents in the Claus tail gas need to be reduced further. The key parameters effecting the selection of the tail gas cleanup process are: • • • • • • • •

Feed gas composition, including H2S content and hydrocarbons and other contaminants Existing equipment and process configuration Required recovery efficiency Concentration of sulfur species in the stack gas Ease of operation Remote location Sulfur product quality Costs (capital and operating).

Various aspects and considerations when choosing the most optimum process configuration for tail gas treating are discussed. There are several key features affecting the selection of the tail gas cleanup process that should be taken into account. When required recovery efficiency and concentration of sulfur species in the stack gas is known, selection of the tail gas process is one step closer. The first step is one of the most important criteria for the selection of the tail gas treating processes. When the required sulfur recovery is established, the selection of the tail gas process

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CHAPTER 11 Sulfur Recovery

Table 11.3 Residual Sulfur with Fresh Catalyst Contaminant

Part per million volume (PPMV)

Carbonyl sulfide (COS) Carbon monoxide (CO) Carbon disulfide (CS2) Methyl mercaptan (CH3SH)

<20 <200 0 0

will be limited. Table 11.3 represents the various tail gas cleanup processes and the recovery that will be achieved. When concentration of impurities in the acid gas, such as COS and CS2, H2S content, and feed gas composition, and finally treated gas specifications, are established, the type of amine used for a particular application could be selected in step two. Finally the third step is the evaluation between the identical process chosen for ease of operation, capital and operating cost, and remote location. For revamp units, minimum equipment modifications and process configuration should be considered as a main key factor. The fundamental process employed typically heats the Claus tail gas to 550–650
F (w290–340
C) by inline substoichiometric combustion of natural gas in a reducing gas generator (RGG) for subsequent catalytic reduction of virtually all non-H2S sulfur components to H2S. Conversion of SO2 and elemental sulfur (Sx) is by hydrogenation: SO2 þ 3H2 /H2 S þ 4H2 O þ DH

(11.9)

SX þ XH2 /XH2 S þ DH

(11.10)

Conversion of COS and CS2 is by hydrolysis: COS þ H2 O/H2 S þ CO2 þ DH

(11.11)

CS2 þ 2H2 O/2H2 S þ CO2 þ DH

(11.12)

CO is essentially hydrolyzed to yield additional H2 according to the “water gas shift” reaction: CO þ H2 O/H2 þ CO2 þ DH

(11.13)

A cobalt–moly catalyst, similar to hydrodesulfurization catalyst, is typically employed. As received, the catalyst is an alumina substrate impregnated with oxides of cobalt and molybdenum, which must be converted to the active sulfided state. To convert the cobalt oxide to the sulfide, a simple exchange of the oxide with H2S is all that is necessary: CoO þ H2 S/CoS þ H2 O þ DH

(11.14)

Converting molybdenum trioxide to the active disulfide, however, requires a change in oxidation number that also requires hydrogen: MoO3 þ 2H2 S þ H2 /MoS2 þ 3H2 O þ DH

(11.15)

CO and H2 naturally present in the Claus tail gas will typically satisfy up to 70% of tail gas unit (TGU) demand, with the balance generated in the RGG.

11.10 Claus tail gas treating process selection

533

The reduced tail gas is then cooled to 90–100
F (w30–40
C) to condense most of the water vapor, which accounts for w35% of the stream. While it is recognized that there is potential for H2S recovery using an alkanolamine, there was some concern about formation of heat-stable thiosulfate resulting from SO2 breakthroughs. Consequently, the Stretford redox process could be adopted by employing an alkaline vanadium salt solution to oxidize absorbed H2S to elemental sulfur particles, which were subsequently removed by froth flotation, filtered, and melted. The process actually had some advantages over amine absorption: • • • •

No acid gas recycle to the Claus unit No steam consumption <5 ppm residual H2S, obviating incineration Temporary high capacity for excessive Claus tail gas H2S or SO2 resulting from off-ratio operation.

However, these were outweighed by poor sulfur quality, high chemical make-up costs, high disposal costs from purging of by-product thiosulfate, absorber fouling, oxidizer foaming, inconsistent froth formation, troublesome filter operation, and atmospheric corrosion. A typical (tail gas) sulfur recovery using an amine system is shown in Figure 11.4. The recent sulfur recovery unit comprises three process steps: • • •

Reducing gas generation and tail gas preheat Hydrogenation/hydrolysis of SO2 and other sulfur species to H2S Gas cooling and waste heat recovery

Modern proprietary RGG design provides process gas reheating and reducing gas (H2 and CO) generation in one single process unit. No external supply of hydrogen gas is required. This feature enhances the reliability of the process unit by eliminating the uncertainties associated with the availability of external hydrogen supply and the quality of hydrogen gas. Many traditional methods use the inline burner design shown in Figure 11.5. Recent design (Figures 11.6 and 11.7) employs a brick-lined internal combustion zone for stable combustion unaffected by downstream turbulence. Optimum outer-shell skin temperatures are easily ensured, heat loss is minimized, and potential leakage through the combustion zone wall does not result in atmospheric release. Some units have been in service for 30þ years with no major refractory repairs. The RGG is typically elevated so that minor entrained sulfur will free-drain to the reactor (and vaporize). Industry consensus is apparently lacking with regard to the optimum air/fuel ratio. Many traditional units operate at stoichiometric air and rely on supplemental H2 for hydrogenation of SO2 and Sx. Perhaps contrary to intuition, equilibrium O2 is nominally 0.6% at stoichiometric air, and only goes to zero at <90% of stoichiometric. There is experience to suggest that chronic O2 leakage leads to catalyst sulfation, although there is disagreement within the industry on this point. Nonetheless, WorleyParsons generally recommends operating at 80% of stoichiometric to avoid, or at least minimize, O2 leakage (and also maximize H2 yield). The advisability of supplemental H2 is also a source of controversy. Many clients consider the availability of import H2 necessary to minimize the risk of SO2 breakthroughs, whereas in reality it is as easy to reduce Claus combustion air (with the same effect) as to increase H2 addition. In the absence of supplemental H2, the operator quickly learns the value of monitoring residual H2 as a sensitive

534

CHAPTER 11 Sulfur Recovery

FIGURE 11.4 A typical (tail gas) sulfur recovery using an amine system.

FIGURE 11.5 Common tail gas unit feed heater.

11.10 Claus tail gas treating process selection

535

FIGURE 11.6 Modern reducing gas generator.

indicator of Claus tail gas ratio, and arguably is more likely to routinely optimize Claus air demand when constrained by a limited H2 supply. Three-stage Claus units clearly do not need supplemental H2, whereas residual H2 may be marginal with 2-stage units, in which case supplemental H2 may be advisable to ensure ability to optimize the Claus tail gas H2S/SO2 ratio. H2 analyzers based on thermal conductivity measurement are very reliable, with minimal servicing. Where the TGU is coupled to a single Claus train, the H2 analyzer can in fact supplant the Claus air demand analyzer. Where multiple Claus trains are coupled to a single TGU, combustion air to a Claus unit whose air demand analyzer is out of service can be temporarily adjusted based on TGU residual H2. Low-pressure steam injection to the burner in the nominal ratio of 1:1 lb/lb steam/fuel is generally advisable for soot inhibition when firing substoichiometrically, by virtue of the following reactions: C þ H2 O/CO þ H2  DH

(11.16)

C þ 2H2 O/CO2 þ 2H2  DH

(11.17)

While modern high-intensity burners may be operable at as low as 80% of stoichiometric air without steam injection, injection is still prudent in view of the possibly of lower air/gas ratios resulting from

FIGURE 11.7 Details of modern reducing gas generator.

536

CHAPTER 11 Sulfur Recovery

meter error or localized fuel-rich zones due to burner damage or fouling. With high-intensity burners, steam injection via a dedicated steam gun is preferred. Otherwise, injection into the combustion air is the most practical.

11.10.1 Hydrogenation reactor With good catalyst activity and no excessive hydrocarbons in the acid gas feed to the reaction furnace, organic residuals in the absorber off-gas should be as shown in Table 11.3. With fresh conventional catalyst, temperatures of 400–450
F (204–232
C) are typically required to initiate the hydrogenation reactions and 540–560
F (282–293
C) for hydrolysis. As the catalyst loses activity with age, progressively higher temperatures may be required. Typically, activity loss is first evidenced by (1) reduced COS, CS2, and CO conversion, and (2) potential methyl mercaptan formed by the reaction of CS2 and H2, while hydrogenation of SO2 and Sx may still be complete because of the lower initiation temperatures required. The potential formation of methyl mercaptan at low temperature or impaired catalyst activity is perhaps not widely appreciated. In cases where the TGU tail gas is discharged without incineration, nominal mercaptan levels can result in serious nuisance odors. In Stretford units, there is reason to expect that the mercaptan is oxidized to disulfide oil, which can impair froth formation. Excessive hydrocarbons in the SRU acid gas feed will tend to increase the carbon–sulfur compounds in the reactor effluent.

11.10.2 Low-temperature hydrogenation catalyst Low-temperature catalysts eliminate use of the reducing gas generator; an indirect heating system could be used instead. Low-temperature TGU catalysts reportedly capable of operating at inlet temperatures of 210–240
C (410–464
F), achievable with steam reheat, have recently become available. The primary advantage (in a new unit) is elimination of the RGG, translating to (1) lower capital cost, (2) operating simplicity, (3) improved turndown, (4) reduced TGU tail gas volume, (5) reduced CO2 recycle to the SRU, and (6) elimination of risk of catalyst damage by RGG misoperation. Historically, Claus tail gas treating units (TGTU) have required reactor inlet temperatures of w550
F for appreciable hydrolysis of COS, CS2, and CO, typically requiring preheat by inline firing or heat exchange with hot oil or heat transfer fluid. Vendor claims of energy savings are questionable since they tend to assume the plant is long on low-pressure steam and disregard the cost of high-pressure steam. Long-term performance of low-temperature catalysts is still uncertain. The following considerations should be taken into account: • • •

A steam reheater will limit the ability to compensate for normal catalyst activity loss with age, potentially limiting its useful life. A bottom layer of titania in the first Claus converter may be required for COS/CS2 hydrolysis. Higher residual CO levels could mean operating the incinerator at 1500
F (w800
C) instead of 1200
F (w650
C).

11.10 Claus tail gas treating process selection

•

537

Incomplete CS2 destruction, and hence methyl mercaptan formation, can result in serious nuisance odors if the TGU tail gas is discharged without incineration.

Reactor inlet temperatures are only half the story; outlet temperatures are the other half. Any catalyst will probably initiate SO2 hydrogenation at 400–450
F (w205–230
C) and, with sufficient temperature rise and excess catalyst, will subsequently achieve virtually complete hydrolysis. New catalysts require lower activation temperatures achievable by indirect reheat by 600# steam, thus reducing investment cost, operating complexity, and, in some cases, energy consumption. In addition, lower reactor outlet temperatures may obviate the downstream waste heat boiler. While reduced investment and complexity are a given, whether the claimed energy savings is real is site-specific. Reduced feed preheat energy only constitutes a savings if the plant is already long on low-pressure waste heat steam (40–70 psig). Otherwise, incremental heat input is fully recovered. Furthermore, in the absence of a steam surplus, elimination of the waste heat boiler may have forfeited recoverable BTUs. Relative COS, CS2, and CO conversion efficiencies need to be compared. It is not necessarily sufficient to achieve regulatory compliance.

11.10.3 COS, CS2, and CO hydrolysis using low-temperature catalyst Relative COS, CS2, and CO conversion efficiencies can be critical. It is not necessarily sufficient to achieve regulatory compliance. • • •

Regulations could become more stringent in the future. Some plants must also buy emission credits per pound of SO2 discharged. Excessive CO residuals could require higher incinerator temperatures, or require incineration otherwise obviated in units able to achieve TGTU absorber H2S emissions <10 ppm by the use of acid-aided methyldiethanolamine (MDEA).

Hydrolysis of COS, CS2, and CO typically requires higher temperatures than hydrogenation of SO2 and Sx. Perhaps accordingly, COS, CS2, and CO conversion efficiencies are the first to suffer as conventional catalysts lose activity with age. Higher reactor inlet temperatures will tend to compensate for deactivation, thus extending catalyst life considerably. Depending on the design limits, temperatures can generally be increased by 50–150
F (28–83
C). Assuming the same holds true for the low-temperature catalysts, a steam reheater will substantially limit the extent to which temperatures can be increased, in effect potentially shortening catalyst life. The lower initiation temperature of the Criterion 734 at start-of-run is thus significant, as it affords the greatest margin for increase. At 464
F (240
C), hydrolysis of CO, COS, and CS2 approaches that of conventional hightemperature catalysts. At 428
F (220
C), however, COS/CS2 conversion must be accomplished in the first Claus stage by (1) supplementing the alumina bed with a bottom layer of expensive titania catalyst, or (2) increasing the inlet temperature to 550–600
F (288–316
C). The latter will nominally: • • •

reduce Claus recovery efficiency increase SRU tail gas rate increase TGTU sulfur load.

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CHAPTER 11 Sulfur Recovery

However, the first stage will not affect CO conversion. Conventional cobalt-moly catalyst will generate minor, but significant, levels of methyl mercaptan by the reaction of CS2 and hydrogen at 480
F (249
C) when in good condition, and at much higher temperatures if the catalyst is aged or damaged. Although the manufacturers claim no residual mercaptans with the low-temperature catalysts, there is some uncertaintydin the author’s viewdas to whether that will remain true a few years into the run.

11.10.4 Hydrogen balance using low-temperature catalyst Compared with firing the feed heater at stoichiometric air and importing H2, a steam reheater will of course have no impact on the H2 balance. However, many plants avoid the need for supplemental H2 by the use of an RGG, typically burning natural gas substoichiometrically to generate H2 and CO. In the absence of an RGG, the alternative is to operate the SRU more air-deficiently as necessary to maintain, say, 2% residual H2 downstream of the TGTU reactor. This will nominally: • • •

reduce Claus recovery efficiency increase SRU tail gas rate increase TGTU sulfur load.

11.10.5 CO2 balance using low-temperature catalyst Eliminating the inline burner has the benefit of reducing the TGTU tail gas volume (for the assumed basis with an RGG). Assuming 85% CO2 slip, the acid gas load on the TGTU amine is reduced.

11.10.6 Energy balance using low-temperature catalyst A steam reheater will not only eliminate the following natural gas required by the RGG, but will also reduce incinerator fuel by virtue of the reduced tail gas rate, resulting in: • •

RGG fuel savings incinerator fuel savings.

Assuming H2S/SO2 ¼ 2 in the SRU tail gas, a supplemental H2 will be required to maintain a 2% residual in the TGTU tail gas. As a rule of thumb, the value of relatively pure (nonreformer) H2 is four times that of natural gas. Figure 11.8 represents WorleyParsons BSR/amine with the low-temperature catalyst.

11.11 Contact condenser (two-stage quench) Common industry practice is to cool the reduced tail gas from the reactor by the generation of lowpressure waste heat steam followed by direct quench with a recirculating water stream to cool it to 90–100
F (w30–40
C), thus condensing most of the water vapor, which accounts for w35% of the

11.11 Contact condenser (two-stage quench)

539

FIGURE 11.8 A sulfur recovery amine flow scheme with low-temperature catalyst.

stream. Modern design utilizes a unique two-stage tower composed of a bottom de-superheater section and top contact condenser. •

The contact condenser has two sections: the first section de-superheats the gas and scrubs any SO2 that may break through from the hydrogenation reactor, and the second section cools the gas and condensates the water; therefore there is no need for make-up water to maintain the caustic

540

•

CHAPTER 11 Sulfur Recovery

concentration. The condensate water will provide the water to maintain the caustic concentration. We do not have continuous purge, but we provide water make-up for the water that is evaporated, just like any other quench system. Tail gas is de-superheated in the lower section of the contact condenser by a circulating water stream. This water is maintained alkaline to protect against any SO2 breakthrough from the reactor. In the upper packed section of the tower, most of the water vapor in the tail gas is condensed by direct contact with a circulating stream of cooled water. A pH analyzer with a lowpH alarm is installed in the quench water circulation line and will indicate when the pH of the quench water is reducing, from either a breakthrough of SO2 or incomplete reduction of the sulfur compounds in the gas stream from the hydrogenation reactor.

A 10%-wt NaOH solution is recirculated through the de-superheater to capture SO2 potentially resulting from a process upset, while also cooling it to its dew point of w165
F (w75
C). The only cooling is by vaporization. The gas is further cooled to 90–100
F (w30–40
C) by direct contact with an externally cooled recycle water stream in the upper contact condenser section. A recycled water slipstream is returned to the de-superheater on de-superheater level control via two bubble-cap wash trays to capture entrained caustic. A blowdown slipstream of recycled water is purged, usually to sour water, on contact condenserlevel control. While the recycle water is usually classified as sour water, the H2S content is typically <50 ppmv by virtue of CO2 saturation. In situations where the increased load on the plant sour water stripper is undesirable, a simple blowdown stripper is occasionally provided at the TGU. This typically involves low-pressure stripping steam injection (as opposed to a reboiler) and return of the uncondensed overhead stream to the de-superheater.

11.11.1 Start-up blower Recent designs provide a start-up blower on the contact condenser overhead to eliminate flaring large quantities of H2S to atmosphere and to prevent violation of the emission. For those cases that a booster blower is required, the booster blower will have dual function as a start-up blower and as a booster blower.

11.11.2 Booster blower Many of the Claus units that are in operation do not have enough pressure to handle a new tail gas unit; in other words, the provision of operating the Claus unit at the higher pressure was not considered: if the source pressure changes, the existing amine unit requires higher reboiler duty and in most cases requires significant changes in the amine unit. WorleyParsons has been offering a booster blower in the tail gas unit to overcome the pressure limitation. Retrofit tail gas units will typically require a booster blower downstream of the contact condenser to overcome the additional pressure drop. The blower is located after the contact condenser to minimize the actual volume (by virtue of cooling and condensation) and before the absorber to take advantage of the higher pressure. With proper design and operation, booster blowers are inherently very reliable, requiring minimal maintenance. Typically, the case is cast iron or carbon steel, with an aluminum impellor. N2-purged tandem shaft seals (typically carbon rings) eliminate process leakage to atmosphere on the discharge end as well as air aspiration into the process on the suction end, which is typically at a vacuum.

11.12 Solvent selection criteria in the tail gas unit

541

FIGURE 11.9 A reducing gas generator vacuum operation.

Though often viewed as a liability by clients, booster blowers arguably improve operability in several ways: • •

•

By recirculating tail gas, the TGU can be started up and shut down independent of the SRUs. Tail gas recycle ensures process stability at high SRU turndown by: (1) avoiding undue RGG burner turndown potentially conducive to sooting due to poor mixing or air/gas flowmeter inaccuracy, and (2) diluting potentially high SO2 levels often typical of high SRU turndown. With advance warning, tail gas recycle can avoid RGG shutdown in the event of an SRU trip. By routing the SRU and TGU tail gas to the incinerator via a common header, a vacuum can be maintained at the RGG (Figure 11.9) without risk of leaking air from the incinerator back into the TGU, thus potentially further increasing SRU capacity. In the event that the tail gas bypass valve leaks, clean TGU tail gas is recycled to the RGG rather than SRU tail gas bypassing the TGU (as when the RGG pressure is positive). Any such reverse flow will improve bypass valve reliability by excluding sulfur vapor, and the valve can be partially stroked periodically to verify operability without increased emissions.

In the absence of a booster blower, a single start-up blower recycle is usually provided for tail gas recycle. While these machines tend to be less sophisticated, N2-purged tandem shaft seals are still required. The overall configuration of using the booster blower is shown in Figure 11.10. This configuration could be used with low-temperature catalyst and indirect reheater instead of the RGG.

11.12 Solvent selection criteria in the tail gas unit The most common solvent is 40–45%-wt MDEA (HS-101, or similar) designed for a maximum rich loading of 0.1 mol acid gas (H2S þ CO2) per mol amine with typical emission reduction to w100 ppmv H2S. Cooling of the lean amine to at least 100
F (38
C) is important for minimization of

542

CHAPTER 11 Sulfur Recovery

FIGURE 11.10 A process flow diagram for sulfur recovery tail gas unit with booster blower configuration.

emissions and amine circulation rate. Specialty TGU amines are essentially pH-modified MDEA to facilitate stripping to lower residual acid gases for treatment to <10 ppm H2S, potentially obviating incineration. CO2 slip is also improved. These products are variously marketed as: • • •

Dow UCARSOL HS-103 Ineos Gas/Spec TG-10 Huntsman MS-300.

11.12 Solvent selection criteria in the tail gas unit

543

An alternative to MDEA is ExxonMobil’s Flexsorb SE, a proprietary hindered amine patented by Exxon in partnership with the Ralph M. Parsons Company. The main advantage is a 20–30% reduction in circulation rate. The solvent is much more stable than MDEA, but is also more expensive. Flexsorb SE Plus is also available for treatment to <10 ppmv H2S. Both solvents require a license agreement with ExxonMobil. It used to be assumed that TGU carbon filtration was not required in view of the absence of hydrocarbons. For MDEA-based solvents, at least, this has proven untrue, presumably due to the generation of surfactant amine degradation products. Solvent applications include: • •

FLEXSORBÒ SE: Selective removal of H2S FLEXSORBÒ SE Plus: Selective removal of H2S to less than 10 ppm

FIGURE 11.11 Ammonia destruction in tail gas unit (Rameshni ammonia conversion).

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•

CHAPTER 11 Sulfur Recovery

FLEXSORBÒ SE Hybrid: Removal of H2S, CO2, and sulfur compounds (mercaptans and COS) In sulfur plant tail gas applications, FLEXSORBÒ SE solvents can use as little as one-half of the circulation rate and regeneration energy typically required by MDEA-based solvents. Flexsorb solvents offer other advantages compared to the other amine solvents. For instance, most of the applications require no reclaiming, have good operating experience, have low corrosion, and have low foaming due to low hydrocarbon absorption; by providing water wash of treated gas at low pressure, system amine losses are minimum.

11.13 Ammonia destruction in a TGU (RACTM) The general industry consensus is that the amount of ammonia that can be conventionally processed in the SRU is limited to 30–35% vol on a wet basis. With what appears to be a trend toward

FIGURE 11.12 A process flow diagram for BSR Selectox.

Futher reading

545

higher-nitrogen crudes, refiners are increasingly faced with the need for alternative processing schemes, as well as SRU de-bottlenecking. With sour water stripper schemes such as Chevron’s wastewater treatment process for separating H2S and NH3, producing a pure marketable NH3 product is relatively difficult compared with bulk separation of NH3 containing minor H2S. The Rameshni Ammonia Conversion (RACTM) process, for which a patent is pending, substoichiometrically combusts a high-NH3 H2S-contaminated stream in the RGG (Figure 11.11). Typically, the NH3–gas heat release will exceed that required to reheat the Claus tail gas, thus necessitating a waste heat boiler prior to the TGU reactor. A supplemental natural gas fire ensures process stability in the event of NH3–gas curtailment. Sub-stoichiometric combustion of the NH3–gas generates supplemental H2 for the hydrogenation reactor and minimizes NOx. Most of any NOx that is made is reduced in the reactor. Minor unconverted NH3 is automatically recycled to the sour water stripper via the contact condenser blowdown.

11.14 BSR Selectox Selectox catalyst is a proprietary catalyst patented for low-temperature H2S oxidation and Clausreaction catalyst development by the Ralph M. Parsons Company and Unocal. Reduced tail gas from the BSR contact condenser is steam-reheated to about 400
F (w200
C) and combined with a stoichiometric quantity of air in the reactor to produce elemental sulfur, which is subsequently condensed (Figure 11.12). Overall recoveries of 98.5–99.5% are achievable. The reactor inlet is limited to 5% vol H2S, above which recycle dilution (or inter-bed heat removal) is necessary to limit the exothermic.

Reference [1] GPSA. Gas processors and suppliers association, engineering databook. Tulsa (OK, USA). 12th ed. 2004.

Futher reading Berben PH, Borsboom J, Lagas JA. SUPERCLAUS, the Answer to claus plant Limitations. In: 38th Canadian chemical Engineering Conference; October 2–5, 1988. Borsboom H, Clark P. New insights into the Claus thermal stage chemistry and temperatures. Banff (Alberta, Canada). In: Brimstone2002 sulfur recovery symposium; May 2–10, 2002. p. 2001. Butwell KF, Kubek DJ, Sigmund PW. Alkanolamine treating. Hydrocarbon Processing; March 1982. Campbell JM. Gas conditioning and processing, vol. 2. Campbell, Petroleum Series, Form@an,@Oklahoma @19/9. Clark PD, Lesage KL, Fitzpatrick E, Davis PM. H2S solubility in liquid sulfur as a function of temperature and H2S gas phase partial pressure, Alberta Sulphur Research Ltd. Quarterly Bulletin October–December, 1997; vol. XXXIV(No. 3). Clark PD. Alberta Sulphur Research Ltd.,. personal communication with Heigold RE; January 2002. Calabrian Corporation. SUPER process doubles Claus capacity. Sulphur Magazine; March–April, 1999. C Corporation, “Purification of amines with granular activated carbon”, Brochure. Fedich RB, McCaffrey DS, Stanley JF. Advanced gas treating to enhance producing and refining projects using ` SE solvents. Veracruz (Mexico). In: Encuentra y Exposicion Internacional de la Industria FLEXSORBO Petrolera, Meeting and international exposition of the petroleum industry (E EXITEP 2003); 2003.

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Gamson BW, Elkins RH. Sulfur from hydrogen sulfide. Chem Eng Prog April 1953;49(4):203–15. Goar BG, Sames JA. Tail gas clean up processesda review. In: Gas conditioning conference. University of Oklahoma; 1983. Goar BG. Sulfur forming and degassing processes. In: Gas conditioning conference. University of Oklahoma; 1984. Hakka LE, Parisi PJ, Cansolv Technologies Inc, Hatcher NA, Johnson JE, Black & Veatch Pritchard Inc. Integrated CANSOLV system technology into your sour gas treatment/sulfur recovery plant, Lawrence Reid gas conditioning conference. Norman: Oklahoma; March 1998. Kelley KK. The thermodynamic properties of sulphur and its inorganic compounds. Bulletin 406, U.S. Bureau of Mines; 1937. Kettner R, Liermann N. New Claus tail-gas process proved in German operations. Oil Gas J; January 11, 1988: 63–6. Kobe KA, Long EG. Pet Refin, 28; February 1949. vol. 28, 11, 127-132 (November 1949); vol. 29, 1, 126-130 (January 1950). Kohl AL, Riesenfeld FC. Gas purification. 3rd ed. Houston (TX): Gulf Publishing Co; 1979. Kwong KV. PROClaus process: an Evolutionary Enhancement to Claus performance. In: Lawrence Reid gas conditioning conference; February/March 2000. Norman (OK). Lagas JA. Stop emissions from liquid sulfur. Hydrocarbon Process October 1982;61:85–9. Lewis G, Randall M. Thermodynamics and the free energies of chemical substances. McGraw Hill; 1923. 530–550. Maddox RN, Morgan DJ. Gas and liquid sweetening. Campbell Petroleum Series; April 1998. McIntush KE, Rueter CO, DeBerry KE, Petrinec BJ. H2S removal and sulfur recovery options for high pressure natural gas with medium amounts of sulfur. Hydrocarbon Engineering; February 2001. Perry Engineering Corporation. Activated-carbon filter, Brochure. Gas conditioning fact Book, Midland (MI): Dow Chemical Co., 19. Scheirman WL. Filter DEA treating solution. Hydrocarbon Processing; August 1973. Shuai X, Meisen A. New correlations predict physical properties of elemental sulfur. Oil Gas J; October 16, 1995. Tonjes M, Hatcher N, Johnson J, Stevens D. Oxygen enrichment revamp checklist for sulfur recovery facilities. In: Lawrence Reid gas conditioning conference. Norman (OK): Black & Veatch Pritchard Inc; February/March 2000. Tuller WN, editor. The sulphur data book. McGraw Hill; 1954. Valdes AR. A new look at sulfur plants. Hydrocarbon Process Pet Refin March 1964;43:104–8. 122–124, (April 1964.