National Renewable Energy Laboratory 

Innovation for Our Energy Future 

A national laboratory of the U.S. Department of Energy

Office of Energy Efficiency & Renewable Energy

NREL is operated by Midwest Research Institute ● Battelle Contract No. DE-AC36-99-GO10337 

Equipment Design and Cost 

Estimation for Small Modular 

Biomass Systems, Synthesis 

Gas Cleanup, and Oxygen 

Separation Equipment 

Task 2.3: Sulfur Primer 

Nexant Inc. 

San Francisco, California 

Subcontract Report 

NREL/SR-510-39946 

May 2006 
Equipment Design and Cost 

Estimation for Small Modular 

Biomass Systems, Synthesis 

Gas Cleanup, and Oxygen 

Separation Equipment 

Task 2.3: Sulfur Primer 

Nexant Inc. 

San Francisco, California 

NREL Technical Monitor: Kelly Ibsen 

Prepared under Subcontract No. ACO-5-44027 

Subcontract Report 

NREL/SR-510-39946 

May 2006 

National Renewable Energy Laboratory 

1617 Cole Boulevard, Golden, Colorado 80401-3393 

303-275-3000 • www.nrel.gov 

Operated for the U.S. Department of Energy 

Office of Energy Efficiency and Renewable Energy 

by Midwest Research Institute • Battelle 

Contract No. DE-AC36-99-GO10337
This publication was reproduced from the best available copy 

Submitted by the subcontractor and received no editorial review at NREL

NOTICE

This report was prepared as an account of work sponsored by an agency of the United States government. 

Neither the United States government nor any agency thereof, nor any of their employees, makes any 

warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or 

usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not 

infringe privately owned rights. Reference herein to any specific commercial product, process, or service by 

trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, 

recommendation, or favoring by the United States government or any agency thereof. The views and 

opinions of authors expressed herein do not necessarily state or reflect those of the United States 

government or any agency thereof. 

Available electronically at http://www.osti.gov/bridge

Available for a processing fee to U.S. Department of Energy 

and its contractors, in paper, from: 

U.S. Department of Energy 

Office of Scientific and Technical Information 

P.O. Box 62 

Oak Ridge, TN 37831-0062 

phone: 865.576.8401 

fax: 865.576.5728 

email: mailto:reports@adonis.osti.gov

Available for sale to the public, in paper, from: 

U.S. Department of Commerce 

National Technical Information Service 

5285 Port Royal Road 

Springfield, VA 22161 

phone: 800.553.6847 

fax: 703.605.6900 

email: orders@ntis.fedworld.gov

online ordering: http://www.ntis.gov/ordering.htm

Printed on paper containing at least 50% wastepaper, including 20% postconsumer waste
Contents 

Section Page 

i Methodology i 

1 Introduction 1 

2 Chemical Solvents 2 

3 Physical Solvents 5 

4 Catalytic Absorbents 10 

5 Sulfur Recovery 11

Figures 

1 Typical Amine System Flow Diagram 3 

2 Typical Physical Solvent System Flow Diagram 5 

3 Typical Claus Sulfur Recovery Process 12 

4 Typical LO-CAT® System Flow Diagram 14

 

Appendix 

A Technologies Summary A-1 
Methodology 

This deliverable is Subtask 2.3 of Task 2, Gas Cleanup Design and Cost 

Estimates, as part of NREL Award ACO-5-44027, “Equipment Design and Cost 

Estimation for Small Modular Biomass Systems, Synthesis Gas Cleanup and 

Oxygen Separation Equipment”. Subtask 2.3 builds upon the sulfur removal 

information first presented in Subtask 2.1, “Gas Cleanup Technologies for 

Biomass Gasification” by adding additional information on the commercial 

applications, manufacturers, environmental footprint, and technical specifications 

for sulfur removal technologies. The data was obtained from Nexant’s 

experience, input from GTI and other vendors, past and current facility data, and 

existing literature. 

Task 2: Gas Cleanup Design and Cost Estimates 

Subtask 2.3: Sulfur Primer 

United States Department of Energy/National Renewable Energy Laboratory

i 
SECTION 1: INTRODUCTION 

Sulfur contaminants such as hydrogen sulfide (H2S), carbonyl sulfide (COS), and 

mercaptans in syngas streams can create unacceptable levels of sulfur 

emissions in power applications or poison catalysts used in chemical synthesis. 

Sulfur contaminants are usually reduced to less than 300 ppm for power 

generation and considerably lower (<1 ppm) for the synthesis of methanol, 

ammonia, and Fischer-Tropsch (FT) liquids. 

In this Subtask, previously developed technical information will be used as the 

basis for the technology discussion, with additional elaboration made on the 

drivers for technology development and rationale for technology selection. 

Information will be provided for each technology about the history of use, current 

manufacturers, industries applying each technology, and major environmental 

concerns. 

Three major sulfur removal technologies will be detailed here, with focus on H2S 

removal: chemical solvents, physical solvents, and catalytic absorbents. 

Chemical solvents create a chemical bond with H2S during contact with a gas 

stream in an absorber column. The H2S loaded solvent is then sent to a stripper 

column, where the chemical bond is broken; the solvent is reused and the H2S 

sent elsewhere for sulfur recovery. Physical solvents use the high solubility of 

H2S in the solvent to “dissolve” sulfur compounds. Their process layout is similar 

to a chemical solvent system, using absorber and stripper columns. Catalytic 

sorbents are usually single-use, fixed-bed solid catalysts that react with H2S to 

remove it from the gas stream. 

Besides information on sulfur removal technologies, information will also be 

provided on sulfur recovery technologies that convert H2S into elemental sulfur. 

There are two main types: partial combustion followed by catalytic reaction 

(Claus process) and catalytic reduction-oxidation (Redox). 

The technologies discussed in this Subtask have been in widespread commercial 

use in many applications for decades. Sulfur recovery processes have been 

known since the 1880s, chemical solvents used for commercial sulfur treatment 

since the 1920s, and physical solvents since the 1950s. Major hydrocarbon 

processing industries, such as natural gas and petroleum, were the first to apply 

these technologies. The experience developed by these industries has been 

applied to syngas treatment. Thousands of treatment facilities are in reliable 

application today, with additional research by federal agencies and private 

industry underway for enhancing selectivity and reducing cost. 

Task 2: Gas Cleanup Design and Cost Estimates 

Subtask 2.3: Sulfur Primer 

United States Department of Energy/National Renewable Energy Laboratory

1 
SECTION 2: CHEMICAL SOLVENTS 

The main type of chemical solvent used for sulfur removal from gas streams are 

amines. There are a number of different amines available for sulfur treatment; 

proper selection depends on the compounds to be removed, the process 

conditions, the level of treatment necessary, process metallurgy, and other 

considerations. Amines commonly used for sulfur removal include: 

• MEA (Monoethanolamine) – Removes both H2S and carbon dioxide (CO2) 

from gas streams. Typically used in low-pressure systems and in 

operations requiring stringent sulfur removal. 

• DGA (Diglycolamine) — Used when there is a need for COS and 

mercaptan removal in addition to H2S. 

• DEA (Diethanolamine) – Used in medium to high pressure systems 

(above 500 psi) and is suitable for gas streams with a high H2S/CO2 ratio. 

• MDEA (Methyldiethanolamine) – MDEA is used when there is a low ratio 

of H2S to CO2 in the gas stream in order to concentrate H2S in the acid 

gas effluent. 

Technology Description and Rationale for Use

Amine processes are proven technologies for the removal of H2S and CO2 (“acid 

gases”) from gas streams. Amine systems generally consist of an absorber, a 

stripper column, a flash separator, and heat exchangers. This is a lowtemperature process in which the gas to be treated enters the absorber at 

approximately 110°F. In the absorber, acid gases are removed from the gas 

stream by chemical reactions with the amine solution. The sweet (low sulfur) gas 

stream exits at the top of the absorber. 

Regeneration of the rich (sulfur containing) amine is accomplished through the 

flash separator to remove absorbed hydrocarbons, followed by a stripper column 

to remove the H2S and CO2 from the amine solution. The lean amine solution is 

cooled and returned to the absorber. The stripped acid gas stream is cooled to 

recover water and then sent to a sulfur recovery unit. A typical amine system is 

shown in Figure 1. 

Task 2: Gas Cleanup Design and Cost Estimates 

Subtask 2.3: Sulfur Primer 

United States Department of Energy/National Renewable Energy Laboratory

2 
Figure 1 Typical Amine System Flow Diagram1

Amine systems normally operate in the low to medium pressure range of 70-360 

psi, although higher pressures can be accommodated with specific types of 

amine solvents. However, in applications where the partial pressure of acid 

gases is high, the economy of an amine system declines in comparison to 

physical solvents. A sulfur removal level as low as 1 ppm can be achieved but at 

the expense of operating cost due to the large solvent circulation rate required. 

In general, amine systems provide flexibility, low cost, and high reliability to 

industries seeking a proven sulfur removal technology. For low pressure sulfur 

removal applications, amines are usually the technology of choice. Their 

selectivity can be optimized to remove the compounds desired, while minimizing 

process gas losses. 

Commercial Manufacturers and Applications

Design and construction of amine units is a standard practice for most major 

engineering firms. Selection of amine vendors tends to be more specialized, with 

a few firms available for packages that include process licensing and amine 

supply. These firms include Dow (through UOP and Union Carbide subsidiaries), 

BASF, Shell, Huntsman, and INEOS. 

 

1

 GPSA Engineering Data Book, 10th ed., “Hydrocarbon Treating,” Volume II, 1987 

Task 2: Gas Cleanup Design and Cost Estimates 

Subtask 2.3: Sulfur Primer 

United States Department of Energy/National Renewable Energy Laboratory

3 
Amine treating technologies have been the process of choice for the natural gas 

industry for decades, due to the limited affinity of amines for hydrocarbons. 

Petroleum refiners also have extensive experience with amines for similar 

reasons, using the technology for hydrocarbon gas sweetening and off-gas 

treatment. The first commercial amine applications began in the 1920’s2

, with 

hundreds of units in active operation today. Operators of Integrated Gasification 

Combined Cycle (IGCC) units operating on coal, coke, and biomass also have 

extensive experience with amine technology. In fact, amines have been the 

process of choice for acid gas removal in IGCC projects, and it continues to be 

selected for new projects3

. 

Environmental Footprint

The major direct emissions from the amine process are an acid gas stream (H2S 

and CO2, predominantly), a vent stream from the flash tank, waste water from 

heat exchangers, and sour water from the stripper column. Standard processes 

are usually integrated into a plant containing an amine unit to handle these 

emissions: 

• Sulfur recovery units, such as a Claus or catalytic Redox unit for 

processing the acid gas stream. The sulfur is either sold if recovered in 

pure form, sent for further processing, or landfilled. 

• A recycle stream to the syngas process, connection to the fuel gas 

system, or connection to a flare for the flash tank vent. This stream 

usually contains hydrocarbons or other light ends. 

• Waste and sour water to appropriate water treatment facilities. These 

units are typically standard on any industrial hydrocarbon or syngas 

facility. 

Besides these direct emissions, indirect emissions are generated in this process 

due to the need for electricity (for pumps) and steam (for reboilers and the 

stripper column). Since the generation of these energy sources create their own 

emission streams, these emission rates should be considered when determining 

the overall environmental footprint of the process. The amount of the footprint 

will vary considerably depending on the gas being treated and the depth of 

treatment required. In general, amine processes tend to use less electricity but 

more steam than units applying physical solvents. 

 

2

 Bullin, J., and Polasek, J, “Selective Absorption Using Amines”, Bryan Research and Engineering, Bryan, 

TX, 2001. 

3

 Korens, N., Simbeck, D., Wilhelm, D., “Process Screening Analysis of Alternative Gas Treating and 

Sulfur Removal for Gasification”, SFA Pacific, prepared for the US Department of Energy, National 

Energy Technology Laboratory, December 2002. 

Task 2: Gas Cleanup Design and Cost Estimates 

Subtask 2.3: Sulfur Primer 

United States Department of Energy/National Renewable Energy Laboratory

4 
SECTION 3: PHYSICAL SOLVENTS 

This removal technology uses an organic solvent to remove acid gases from gas 

streams by physical absorption without chemical reaction. The driving force of 

this process is the high solubility of acid gases in the organic solvent. In most 

cases, solubility increases as the temperature decreases and the pressure 

increases. Thus, physical absorption is a low-temperature, high-pressure 

process, with high partial pressure of acid gases required for the economy and 

efficiency of this process. The two most common physical solvent processes are 

Selexol and Rectisol, which use the dimethyl ether of polyethylene glycol and 

chilled methanol, respectively, as the active solvents. 

In general, physical solvent systems consist of an absorber, a stripper column, a 

series of flash separators, and heat exchangers, similar to that of a chemical 

solvent unit. In the absorber, acid gases in the feed stream are absorbed into the 

solvent solution. The sweet process stream exits the top of the absorber. 

Regeneration of the rich solvent stream is accomplished through a series of flash 

separators at reduced pressures to remove absorbed hydrocarbons followed by 

the stripper column to remove the acid gases from the solvent. The lean solvent 

solution is cooled and returned to the absorber. The stripped acid gas stream is 

cooled to recover water and then sent to a sulfur recovery unit. A typical physical 

solvent system is shown in Figure 2. 

Figure 2 Typical Physical Solvent System Flow Diagram4

The temperature of the solvent should be as low as possible, while the 

temperature of the gas to be treated usually enters the absorber at about 100°F. 

The Selexol solvent typically operates at 20 to 80°F, while Rectisol solvents are 

 

4

 GPSA Engineering Data Book, 10th ed., “Hydrocarbon Treating,” Volume II, 1987 

Task 2: Gas Cleanup Design and Cost Estimates 

Subtask 2.3: Sulfur Primer 

United States Department of Energy/National Renewable Energy Laboratory

5 
kept chilled at –40 to –80°F. The minimum operating pressure for physical 

solvent systems is around 150 psi, but typical operation for these systems is 

usually much higher (500 to 1200 psi)5. 

SELEXOL 

Technology Description and Rationale for Use

The solubility of sulfur compounds present in gas process streams, coupled with 

high solvent stability and excellent operation at high pressure, gives Selexol 

some advantages over other sulfur removal processes. Besides removal of H2S 

and CO2, hydrogen cyanide (HCN), mercaptans, COS, and heavy hydrocarbons 

can all be removed to some extent by the Selexol solvent. Process developers 

concerned about removal of these compounds from gas streams may find 

physical solvents superior to chemical ones. Depending on the level of CO2 and 

H2S removal desired, a Selexol system can be modified to meet a range of 

different needs. 

Commercial Manufacturers and Applications

The Selexol process was first commercially used in the late 1960’s. The 

technology is currently owned and licensed by Dow, with commercial packages 

available from a variety of engineering companies including UOP, Udhe, and 

Coastal. Roughly 60 Selexol plants are in commercial application worldwide6

. 

Selexol technology is used in high pressure natural gas, IGCC, and petroleum 

refinery applications. At the refinery level, Selexol units can be seen upstream of 

reforming and partial oxidation (POX) units. This technology is currently a main 

competitor of amine processes for IGCC applications. Some of the key 

considerations for process selection for IGCC use are the gasifier technology 

chosen, feedstock type, and syngas end-use.

Environmental Footprint

As can be seen in Figure 2, the process configuration for a physical solvent unit 

is similar to that of an amine system. In general, the direct and indirect emission 

sources will be very similar to that of an amine unit, with differences in the 

relative amount of emissions and where the waste streams are emitted. Key 

differences of the Selexol process relative to amine units include: 

 

5

 Gerhard Ranke, “Advantages of the Rectisol-Wash Process in Selective H2S Removal from Gas 

Mixtures,” office communication, 30 January 2005. 

6

 Gas Processes 2004, Hydrocarbon Processing, Gulf Publishing Company, 2004. 

Task 2: Gas Cleanup Design and Cost Estimates 

Subtask 2.3: Sulfur Primer 

United States Department of Energy/National Renewable Energy Laboratory

6 
• Different acid gas and off-gas compositions. Since CO2 has lower 

solubility than H2S, the flash drum off-gas will usually contain a greater 

amount of CO2. The acid gas stream will also contain a greater amount of 

mercaptans and heavy hydrocarbons, if these species are present in the 

process gas stream. 

• Greater electricity use. The higher pressures and lower temperatures 

usually seen in a Selexol system require additional process electricity. 

• Lower steam use. In general, physical solvents are easier to regenerate 

in the stripper column, making the steam requirements lower. 

As with amine units, treatment processes for the waste streams generated are 

standard commercial equipment. Sulfur recovery system configurations can vary 

due to the different acid gas stream compositions. 

RECTISOL 

While many different configurations of the Rectisol process exist, the flow 

scheme is, in general, similar to that displayed in Figure 2. The typical difference 

is an additional column or process unit to aid in the regeneration of the chilled 

methanol. In addition, refrigeration is required to keep the methanol solvent 

between –40 and –80°F for process use. These additional steps add greater 

cost and complexity to the sulfur removal scheme. 

Technology Description and Rationale for Use

The solubility of a number of sulfur compounds and other process gas 

contaminants is greater in the Rectisol process than in other physical solvents. 

This allows for very deep contaminant removal, making Rectisol a good choice in 

applications such as chemicals synthesis, where downstream processes are very 

sensitive to sulfur or other contaminants. The selectivity for H2S over CO2 is 

similar to that of the Selexol process, but the process can be configured for deep 

removal of both compounds if required. 

Commercial Manufacturers and Applications

The German firm Lurgi GmbH first developed the Rectisol process back in the 

1950’s. They remain the main licenser of the technology for commercial 

applications. Over 50 units have been licensed and built worldwide7. 

Gasification plants with processes that are sensitive to sulfur, such as ammonia, 

methanol, or Fischer-Tropsch synthesis reactors, have employed Rectisol 

technology. While typically higher in cost than other sulfur removal technologies, 

 

7

 Information from Lurgi, available at www.lurgi.de. 

Task 2: Gas Cleanup Design and Cost Estimates 

Subtask 2.3: Sulfur Primer 

United States Department of Energy/National Renewable Energy Laboratory

7 
any process looking to obtain very deep sulfur removal will usually consider 

applying the Rectisol process. 

Environmental Footprint

The direct and indirect emissions from the Rectisol process are similar to that of 

Selexol, with main two differences for indirect emissions. The first is due to the 

use of a compressor to circulate refrigerant to keep the process cold. The 

addition of this unit to the Rectisol process adds greater electricity requirements 

to the overall process. In addition, some Rectisol process designs require 

multiple absorber or stripper columns for contaminant removal and solvent 

regeneration. This will lead to greater steam and power requirements relative to 

other treatment processes. 

MIXED CHEMICAL AND PHYSICAL SORBENT SYSTEMS 

The technologies available for sulfur removal are not limited to the ones outlined 

above. Two major commercially available technologies use a mix of chemical 

and physical sorbents to take advantage of the unique properties inherent in 

each type of solvent. Each process uses a proprietary hindered amine/physical 

solvent blend to allow selective removal of H2S and other contaminants, such as 

organic sulfur compounds and CO2. 

The first is Sulfinol, developed and licensed by Shell. Since the 1960’s over 200 

Sulfinol units have been installed and operated worldwide8. Sulfinol technology 

has been used in natural gas and refinery applications for selective H2S removal. 

The other is FLEXSORB, developed by ExxonMobil in the 1970’s. Similar in 

nature to Sulfinol, roughly 50 commercial plants are currently in operation9. 

PHYSICAL SOLVENTS AND TAR REMOVAL 

Most biomass gasification units produce some level of heavy hydrocarbons, or 

“tars”, that must either be removed or process conditions maintained so that they 

do not create plugging problems. The majority of the tars are typically aromatic 

compounds with six carbons or more. Tar removal is currently performed by 

catalytic cracking of the tars just after the gasifier into lighter molecules that can 

be handled by the downstream process equipment. With physical solvents 

having an affinity for aromatic compounds, the possibility exists that they could 

be used in place of catalytic cracking. Aromatics are very soluble in both the 

Selexol and Rectisol solvents, with solubilities for benzene at ~30 times that of 

H2S. 

 

8 Hydrocarbon Processing, ibid. 9

 Fedich, R., Woerner, A., and Chitnis, G., “Selective H2S Removal”, Hydrocarbon Engineering, Volume 

9, Number 5, May 2004. 

Task 2: Gas Cleanup Design and Cost Estimates 

Subtask 2.3: Sulfur Primer 

United States Department of Energy/National Renewable Energy Laboratory

8 
There does not appear to be any physical solvents in commercial operation for 

the removal of large amounts of tars, although Dow has stated that they have 

successfully removed “trace” amounts of aromatics from syngas streams with 

Selexol10. While aromatics are very soluble in physical solvents, aliphatic 

hydrocarbons have a much lower solubility—C6 compounds (hexanes) are 

roughly as soluble as H2S, but this factor quickly drops off when dealing with 

lighter hydrocarbons. For example, methane is roughly 100 times less soluble 

than H2S, and ethane is roughly 20 times less soluble. 

Using physical solvents in this mode would not be a course of action that is 

recommended at this time. More detailed investigation could be performed, 

requiring vendor input and small scale testing. There are a number of concerns 

about using physical solvents for this application: 

1. The syngas stream would need to be cooled to ~100°F or lower for feed to 

the physical solvent system. Cooling down the gas coming right out of the 

gasifier could condense oils, chlorides, ammonia, fatty acids, alkali 

species, and others which could create plugging problems, especially if 

particulates were present (due to agglomeration). Typical syngas streams 

from biomass gasification have a tar dew point at around ~450-500°F. 

One potential way to reduce the plugging risk would be to partially cool 

above the dew point, then have a water wash/quench to remove water 

soluble compounds. While this would reduce the plugging potential, the 

condensate would contain a considerable amount of dissolved material. 

This step would also likely lead to a lower process efficiency than using 

catalytic tar cracking. 

2. Steps still need to be taken to guard against breakthrough of aliphatic 

hydrocarbons (~10% of the hydrocarbons in the tar). Depending on the 

type of aliphatic compounds present, physical solvents may or may not be 

very effective, especially in operations where the downstream catalyst is 

sensitive to residual hydrocarbons. A reformer to destroy the methane 

and ethane components would probably still be necessary. 

3. High concentrations of tars and oils in the acid gas stream would create 

problems for a sulfur recovery unit, including black sulfur and VOC 

emissions from the incinerator. It is not clear at this time how much 

experimental data exists for removing a high concentration of tars from the 

physical solvents during the stripping step, although Lurgi has done some 

work in this area11. 

 

10 Jotaro Itoh, Dow Chemical Japan, “Chemical and Physical Absorption of CO2”, RITE International 

Seminar, 14 January 2005. 

11 Dennis Leppin, Gas Technology Institute, office communication, June 2005. 

Task 2: Gas Cleanup Design and Cost Estimates 

Subtask 2.3: Sulfur Primer 

United States Department of Energy/National Renewable Energy Laboratory

9 
4. Hydrocarbons in physical solvents have caused significant foaming and 

operational problems in the past, especially with Selexol. While some 

steps can be taken to minimize this, it can become a major operational 

issue. 

5. It is unclear due to limited data how removing large quantities of tars and 

oils will impact the ability of the physical solvent to remove H2S. As the 

physical solvent becomes more loaded (with preferential solubility to 

aromatic compounds over H2S and CO2), greater recycle rates and larger 

vessels would likely be necessary. 

SECTION 4: CATALYTIC ABSORBENTS 

Catalytic absorbents, such as zinc oxide (ZnO) or copper oxide (CuO), are often 

used as a polishing step for sulfur removal in gas streams where the incoming 

sulfur level is 10 to 20 ppm or lower. For hydrocarbon and IGCC applications, 

catalytic absorbents are usually not a primary sulfur removal process. They are 

typically applied downstream of either a chemical or physical solvent to assure 

the sulfur level entering other process equipment, such as chemical synthesis 

reactors, is very low. Since ZnO is the technology most commonly deployed, it 

will be focused upon here. 

Technology Description and Rationale for Use

H2S in a gas stream reacts with the ZnO absorbent in a fixed bed reactor, where 

it is converted to zinc sulfide. According to technology providers, sulfur removal 

down to 20 to 50 ppb is attainable with ZnO12. Since the sulfur specifications for 

alcohols and FT liquids are <1 ppm in the syngas stream, ZnO could be used to 

assist in achieving these requirements. 

ZnO is active over a wide range of temperatures from ambient to 750°F; 

however, operating temperatures between 660°F and 750°F are normally used to 

maximize absorption efficiency. Operating pressure limits are usually not a 

concern for the use of ZnO absorbent. 

While catalysts that could be regenerated were used for many years prior to the 

application of the current breed of catalysts, regulations limiting air sulfur 

emissions have spurred the use of hot ZnO catalysts that are disposed of after 

their useful lifetime. Spent catalyst usually contains a sulfur content that is low 

enough to enable it to be landfilled or used as an agricultural fertilizer. 

 

Task 2: Gas Cleanup Design and Cost Estimates 

Subtask 2.3: Sulfur Primer 

United States Department of Energy/National Renewable Energy Laboratory

10 

12 Considerable information in this section provided by Ronald Huber, Sud-Chemie Technical Service 

Engineer, personal correspondence, 2 June 2005. 
The main rationale for the use of ZnO catalysts is for systems where very low 

sulfur content is a key priority. For chemical synthesis, these systems can be 

placed downstream of amine or Selexol units to act as a secondary removal step 

(a “polishing” step), or downstream of a Rectisol unit (a “guard” step) to prevent 

sulfur breakthrough. The lifespan of the catalyst between changeouts is longer in 

guard operation than as a polishing step. 

Commercial Manufacturers and Applications

A catalyst bed for polishing or guard sulfur removal duty is a conventional unit 

process that has been effectively been applied for decades. Processes for 

chemical synthesis from natural gas or syngas, such as ammonia, methanol, and 

FT liquids production, have all employed catalytic absorbents. The current hot 

oxide catalysts have been recently employed since the 1980’s, with the current 

number in service estimated from the high hundreds to the low thousands. Major 

vendors for this technology include Sud-Chemie, BASF, Synetix, Unicat, and 

Haldor Topsoe. 

Environmental Footprint

Catalytic absorbents are a much simpler, more environmentally benign process 

relative to chemical or physical solvents. This is due in large part to the lower 

level of sulfur removal, since absorbents act as a secondary removal step. The 

only environmental concern for catalytic processes is the removal of spent 

catalysts. As mentioned earlier, this is usually not a hazardous waste; the spent 

catalyst can be landfilled or, in some instances, be used as a fertilizer. 

SECTION 5: SULFUR RECOVERY 

Removing sulfur from a natural gas or syngas process stream is only part of the 

story. The residual sulfur present in an acid gas stream must then be recovered 

to prevent environmental and safety harms, as well as meet operator permit 

requirements. Two main technologies are commercially available to recover 

sulfur: the Claus process (partial combustion) for high levels of sulfur, and 

catalytic Redox processes, for relatively low levels of sulfur. 

CLAUS PROCESS 

Technology Description

In the Claus process, a high H2S concentration stream is the feedstock for 

recovery to elemental sulfur. Roughly 1/3rd of the H2S is burnt (partial 

combustion) to form sulfur dioxide (SO2). The remaining H2S reacts with the 

synthesized SO2 over an alumina or bauxite catalyst to produce elemental sulfur. 

Depending on their concentrations, the unreacted components (tail gas), such as 

Task 2: Gas Cleanup Design and Cost Estimates 

Subtask 2.3: Sulfur Primer 

United States Department of Energy/National Renewable Energy Laboratory

11 
residual SO2, CO2, and H2S, are either emitted, thermally oxidized, or further 

treated in an additional recovery process. A graphical depiction of the process 

can be seen in Figure 3. 

Figure 3 Typical Claus Sulfur Recovery Process13

The Claus process is thermodynamically limited to ~97% sulfur recovery, 

although additional treatment steps, such as tail gas sulfur recovery, can 

increase the recovery rate. 

Commercial Manufacturers and Applications

The Claus process is the oldest commercial process covered in this paper, with 

development dating back to the late 19th century. Today, Claus processes are 

the main step used for elemental sulfur production worldwide—in fact, 90 to 95% 

of the sulfur recovered in the United States was from the Claus process. 38 

companies operate 108 Claus processes in the United States, recovering nearly 

9 million tons per year of sulfur14. The petroleum and natural gas industries are 

the main users of the technology, with IGCC applications making up a small but 

growing segment of the user population. 

Since application of the Claus process is so widespread across the world, a 

number of major engineering firms offer licenses for the technology. These 

include companies such as Parsons, KBR, and Jacobs for the overall technology, 

and Almatis, Axens, and UOP for the process catalyst. 

 

13 US Environmental Protection Agency, AP42, 5th Edition, “Compilation of Air Pollutant Emissions 

Factors Volume 1: Stationary Point and Area Sources, 1995. 

14 US Geologic Survey, Mineral Commodity Summary, Sulfur, January 2005. 

Task 2: Gas Cleanup Design and Cost Estimates 

Subtask 2.3: Sulfur Primer 

United States Department of Energy/National Renewable Energy Laboratory

12 
In operations where the sulfur recovery is more than 20 TPD, a Claus unit is 

generally the most economical approach. For efficient process operation, the 

concentration of H2S in the acid gas stream entering the Claus unit should be a 

minimum of ~40%; lower concentrations can be handled with some modifications 

to the process including acid gas bypass of the reaction furnace and the addition 

of oxygen to the air used for combustion. 

Environmental Footprint

The main direct outlet streams from the Claus process are elemental sulfur, 

spent catalyst, tail gas, and wastewater. The sulfur is of very high purity, and can 

be used for industrial processes such as the production of sulfuric acid. The tail 

gas stream contains the major emissions from the process. Thermal oxidation of 

this stream could lead to emissions of SO2, CO2, CO, NOx, and other pollutants. 

When a tailgas treatment unit is added, the emissions of sulfur oxides are 

reduced and overall sulfur recovery can be 99% or more. The wastewater 

generated from the sulfur condensers typically requires downstream treatment in 

a standard treatment unit. 

The Claus process has a relatively small amount of indirect emissions coming 

predominantly from the number of reheaters used to maintain process heat. The 

majority of the process heat comes from the exothermic reactions involving H2S. 

CATALYTIC REDOX SULFUR RECOVERY 

A catalytic sulfur recovery process is suitable for small-scale applications that 

require less than 20 TPD of sulfur recovery capacity, have a concentration of H2S 

in the acid gas stream too low for the Claus process, or are subject to high 

fluctuations in acid gas rate or composition. The two main technologies for this 

application are marketed as LO-CAT® (by Gas Technology Products LLC (GTP), 

a unit of Merichem) and Sulferox (developed by Shell and Dow and currently 

licensed by Le Gaz Integral (LGI)). While the two technologies are relatively 

similar (differing in catalyst concentration and type), the LO-CAT® technology will 

be elaborated upon here. 

Technology Description and Rationale for Use

LO-CAT® is an oxidation process that uses iron catalyst held in a chelating agent 

to oxidize H2S to elemental sulfur15. H2S is the only acid gas being removed in 

this process. A LO-CAT® process consists of 3 sections that include an 

absorber, an oxidizer for catalyst regeneration, and a sulfur handling unit. Figure 

4 illustrates a typical LO-CAT® unit. When the gas stream comes in contact with 

 

Task 2: Gas Cleanup Design and Cost Estimates 

Subtask 2.3: Sulfur Primer 

United States Department of Energy/National Renewable Energy Laboratory

13 

15 Information provided by GTP/Merichem, personal communications and www.gtp-merichem.com 
the LO-CAT® solution in the absorber, H2S in the gas stream is converted to 

elemental sulfur. The spent catalyst along with the elemental sulfur exits the 

absorber and then enters the oxidizer where the spent catalyst is regenerated by 

contact with oxygen. The elemental sulfur is then concentrated into a sulfur 

slurry, which moves to the sulfur handling unit to recover any entrained catalyst 

solution. 

Figure 4 Typical LO-CAT® System Flow Diagram 

Commercial Manufacturers and Applications

As mentioned above, GTP and LGI are the two active manufacturers of catalytic 

sulfur removal technology. GTP first commercialized the LO-CAT® technology in 

1978, with the SulFerox process coming to market in the early 1980’s. 300 to 

400 units are currently in operation in a number of different industries that require 

recovery of low levels of sulfur16. These include natural gas sweetening, syngas 

operations, air purification, biogas/landfill gas units, and refinery “off-gas” 

streams. 

Environmental Footprint

Due to the simpler make-up of the catalytic recovery process relative to the Claus 

process, the direct and indirect emissions are lower. Similar to the Claus 

process, sulfur, tail gas, and spent catalysts are all process products. The sulfur 

removed from this process is not directly suitable for industrial use; the product is 

a “cake” that contains up to 70% water. The sulfur recovered contains a small 

amount of entrained residual catalyst and is considered low-value sulfur that is 

suitable for agricultural purposes but is undesirable as a chemical feedstock. 

 

Task 2: Gas Cleanup Design and Cost Estimates 

Subtask 2.3: Sulfur Primer 

United States Department of Energy/National Renewable Energy Laboratory

14 

16 Combination of information provided by both GTP/Merichem and Shell. 
The catalyst can either be landfilled or used as an agricultural fertilizer. Finally, 

the tail gas stream, depending on composition, can either be vented or burned in 

a thermal oxidizer. While this stream may still be a source of SO2, CO2, and CO, 

the concentrations tend to be lower than in a Claus process. 

Since no additional process equipment is required outside of what is listed in 

Figure 4, the indirect emissions are negligible. 

Task 2: Gas Cleanup Design and Cost Estimates 

Subtask 2.3: Sulfur Primer 

United States Department of Energy/National Renewable Energy Laboratory

15 
Task 2: Gas Cleanup Design and Cost Estimates 

Subtask 2.3: Sulfur Primer 

United States Department of Energy/National Renewable Energy Laboratory

Appendix A Technologies Summary

Appendix A includes a summary of the technologies discussed in the above 

sections. Information is provided on the operating conditions, clean-up 

parameters, advantages, and disadvantages.

A-1 
Summary of Acid Gas Removal Technologies 

Technologies Size range Operating range Cleanup Parameters Advantages DisadChemical Solvents 

Designed for specific application 

Low-temperature operations-inlet gas at about 110°F 

Low to medium operating pressures (70-360 psi) with many solvents; some can be used for > 500 psi (nat. gas) 

Can remove H2S down 

to 1ppm with a high solvent circulation rate CO2 removal dependent 

on amine selected 

Proven technologies; can selectively remove H2S only, if 

desired 

Limitebe remCorroconce

Physical Solvents 

Designed for specific application 

Low-temperature operation-process conditions from 80 to –80°F 

High pressure operation (500 to 1200 psi) 

Can remove to  ~0.1 ppm H2S with 

Rectisol, 1 ppm H2S 

with Selexol 

Can provide wide depth or breadth for contaminant removal 

Capitafor soUsualrequir

Catalytic Absorbents 

Feed gas with inlet H2S < 10-

20 ppm 

Operating temperatures range of 660 – 750°F 

Operable over a wide range of pressures 

50 ppb H2S achievable Able to meet 

stringent sulfur specs Ease of use 

CannrequirInlet H

low to 

Sulfur Recovery: Catalytic Redox 

Used for < 20 TPD sulfur recovery 

Low-temperature operations-inlet gas at about 110°F 

Operating pressures range from 15 to 600 psi, but is normally used in lowpressure applications 

99.9%+ removal efficiency 

Low cost and significant turndown flexibility Ability to treat wide range of gas compositions 

H2S is 

removcontaLow-v

Sulfur Recovery: Claus 

Greater than 20 TPD sulfur recovery, acid gas H2S 

concentrations >40% 

1800 to 2800°F in the combustion 

chamber, 400 to 600°F in the catalytic 

reactors Close to atmospheric pressure 

94 to 97% S recovery, depending on process configuration Can increase recovery if additional tail gas treatment performed 

Extensive operating experience Sulfur recovered is pure; can be sold as a commodity 

Can bto Resulfur High t

Task 2: Gas Cleanup Design and Cost Estimates 

Subtask 2.3: Sulfur Primer 

United States Department of Energy/National Renewable Energy Laboratory
F1146-E(12/2004) 

REPORT DOCUMENTATION PAGE Form Approved 

OMB No. 0704-0188

The public reporting burden for this collection of information is estimated to average 1 hour per response, including the time for reviewing instructions, searching existing data sources, 

gathering and maintaining the data needed, and completing and reviewing the collection of information. Send comments regarding this burden estimate or any other aspect of this 

collection of information, including suggestions for reducing the burden, to Department of Defense, Executive Services and Communications Directorate (0704-0188). Respondents 

should be aware that notwithstanding any other provision of law, no person shall be subject to any penalty for failing to comply with a collection of information if it does not display a 

currently valid OMB control number. 

PLEASE DO NOT RETURN YOUR FORM TO THE ABOVE ORGANIZATION.

1. REPORT DATE (DD-MM-YYYY)

May 2006 

2. REPORT TYPE

Subcontract Report 

3. DATES COVERED (From - To)

 

5a. CONTRACT NUMBER

DE-AC36-99-GO10337 

5b. GRANT NUMBER

4. TITLE AND SUBTITLE

Equipment Design and Cost Estimation for Small Modular Biomass 

Systems, Synthesis Gas Cleanup, and Oxygen Separation 

Equipment; Task 2.3: Sulfur Primer 

5c. PROGRAM ELEMENT NUMBER

5d. PROJECT NUMBER

NREL/SR-510-39946 

5e. TASK NUMBER

BB06.3710 

6. AUTHOR(S)

Nexant Inc. 

5f. WORK UNIT NUMBER

7. PERFORMING ORGANIZATION NAME(S) AND ADDRESS(ES)

Nexant Inc. 

101 Second St., 11th Floor 

San Francisco, CA 94105 

8. PERFORMING ORGANIZATION 

REPORT NUMBER

ACO-5-44027 

10. SPONSOR/MONITOR'S ACRONYM(S)

NREL 

9. SPONSORING/MONITORING AGENCY NAME(S) AND ADDRESS(ES)

National Renewable Energy Laboratory 

1617 Cole Blvd. 

Golden, CO 80401-3393 11. SPONSORING/MONITORING 

AGENCY REPORT NUMBER

NREL/SR-510-39946 

12. DISTRIBUTION AVAILABILITY STATEMENT

National Technical Information Service 

U.S. Department of Commerce 

5285 Port Royal Road 

Springfield, VA 22161 

13. SUPPLEMENTARY NOTES

NREL Technical Monitor: Kelly Ibsen 

14. ABSTRACT (Maximum 200 Words)

This deliverable is Subtask 2.3 of Task 2, Gas Cleanup Design and Cost Estimates, of NREL Award ACO-5-44027, 

“Equipment Design and Cost Estimation for Small Modular Biomass Systems, Synthesis Gas Cleanup and Oxygen 

Separation Equipment”. Subtask 2.3 builds upon the sulfur removal information first presented in Subtask 2.1, “Gas 

Cleanup Technologies for Biomass Gasification” by adding additional information on the commercial applications, 

manufacturers, environmental footprint, and technical specifications for sulfur removal technologies. The data was 

obtained from Nexant’s experience, input from GTI and other vendors, past and current facility data, and existing 

literature. 

15. SUBJECT TERMS

biomass; Nexant; small modular; synthesis gas; syngas; scaling; cost estimation; equipment design; National 

Renewable Energy Laboratory; NREL 

16. SECURITY CLASSIFICATION OF: 19a. NAME OF RESPONSIBLE PERSON 

a. REPORT 

Unclassified 

b. ABSTRACT 

Unclassified

c. THIS PAGE 

Unclassified

17. LIMITATION 

OF ABSTRACT

UL 

18. NUMBER 

OF PAGES 

19b. TELEPHONE NUMBER (Include area code)

Standard Form 298 (Rev. 8/98) 

Prescribed by ANSI Std. Z39.18