Small Capacity Sulfur Recovery Units

Gary J. Nagl


“In the good old days,” natural gas production was a lot easier. Gas was relatively plentiful, easy to find, and sweet. Today, it is generally accepted that natural gas production is becoming more sour. Gas sweetening technologies tend to be expensive, which can be especially troublesome for the small natural gas producer. This paper examines the natural gas sweetening technologies at the “small capacity” end of the spectrum, and the issues involved in selecting one method versus another.

“Small capacity” for the purpose of this paper is defined as less than 20 tonnes per day of sulfur production. Above 20 tons per day of sulfur, amine gas sweetening units in conjunction with catalytic Claus type reactors are generally the process scheme of choice, with some notable exceptions. The most notable exception is the processing of very dilute “acid gas” streams. CO2:H2S ratios above 5:1 can become troublesome for the Claus reactor.

The processes of choice for small capacity applications tend to be solid and liquid scavengers, which have non-regenerable reaction systems, aqueous iron-redox based systems, which are regenerable catalytic systems, and certain gas phase catalytic processes, which are at various stages of development. Selection of the best technology for a given situation need to examine factors well beyond the capital and operating cost of the process itself, and evaluate factors such as operational simplicity, operator attention, footprint and weight, and waste generation and disposal costs.

Solid Scavengers

Solid scavengers are generally iron-based materials. The “original” solid-scavenger was “iron-sponge,” which consists of hydrated ferric-oxide impregnated on wood chips. The ferric oxide reaction can be characterized by the following equation:

2 Fe2O<sub">3 + 6 H<sub">2S 2 FeS + 2 H2O (1)

This process works very well until the media becomes spent and needs to be changed. Unless kept wet, the iron sulfide will react exothermically with oxygen in the air and cause the wood media to catch fire. Due to safety concerns, iron-sponge has fallen from favor in the gas processing industry. The solid scavengers employed in the industry today, such as Sulfa-Treat® and SULFUR RITE® use an iron oxide, which reacts with H2S to form innocuous iron pyrite as the reaction product. Unlike iron sulfide, iron pyrite is not pyrophoric.

The design of the solid scavenger system is dependent on the mass flowrate of the H2S over the media, so large gas flow rates with low H2S concentrations will tend to have large vessels, with long reactor bed lives. The opposite is true for high H2S concentration gas streams. Also the gas should be water saturated to achieve maximum efficiency. A key benefit of this system is that there is virtually no operator involvement. The gas flows over the media and reacts. A downturn in flowrate and/or H2S concentration doesn’t require any involvement, as the media will simply react with whatever H2S is in the gas stream.

One design decision facing the operator deals with the reactor configuration and associated operating costs. The decision was whether to use a single reactor vessel, or a dual vessel, lead-lag configuration.

In a single vessel configuration, when the catalyst is spent, and H2S “breakthrough” occurs, the vessel must be taken out of service and the media replaced, possibly causing an interruption in production and/or an undesirable H2S in the product gas stream… In contrast, a dual vessel, lead-lag system allows the “lag” vessel to become the “lead” vessel, allowing continued plant operation while the spent media in the former “lead” vessel is taken out of service and the media changed-out. A diagram of the “lead-lag” configuration is shown in Figure 1. The benefit of this system is more efficient use of the media, as the media in the “lead” vessel can be reacted to virtual completion because of the “back-up” afforded by the “lag” vessel.

In a properly operating solid scavenger system, approximately 5 pounds of spent media is required per pound of H2S removed. This equates to a media cost of about $3.50 per pound of H2S removed. As the spent media is stable iron-pyrite, the waste generated is non-hazardous and typically disposed of in a landfill. This is generally not a problem in the Western Hemisphere, but is a big problem in Europe and parts of the Far East where disposal in landfills is severely restricted.

Media change-out can typically be done in a day. This can be a messy operation with high pressure water hoses required to cut the spent material out of the vessel, but the infrastructure for media changeout is well-developed in the Western Hemisphere with a number of service companies capable of performing this operation.

Solid scavenger systems are very common onshore. However, logistics and media changeout have prevented broad use of this system on offshore platforms. The cost of shipping fresh and spent media to and from the platform, and the space requirement for vessel changeout are issues. Vessel size for sweetening dilute gas streams is also an issue.

One potential application for the solid scavenger on offshore platforms is potentially the sweetening of the gas required to power the platform. In this case, only a limited amount of gas needs to be processed, limiting the vessel size and media consumption and the simplicity of the solid scavenger system become a major advantage. For this application, Gas Technology Products has designed SULFUR RITE® systems where the entire vessel is replaced on the platform. The vessel with the spent media is shipped to shore where fresh media is installed, and the vessel is readied for delivery back to the platform.

Liquid Scavengers

The most common liquid scavenger is an amine-aldehyde condensate manufactured from monoethanolamine and formaldehyde. The resulting “scavenger” product is a hexahydrotriazine, and is commonly called “triazine” in the industry. The “triazine” is typically offered in a water-based solution. In most applications, the reaction products are also water soluble, with very low toxicity characteristics and biodegradable, making this a relatively simple system to handle.

Liquid scavengers can also be employed in two different processing schemes. After separation of liquid hydrocarbons and water from the gas, the liquid scavenger can be either injected directly into the gas stream or the system can be operated in a batch mode by passing the gas through a vessel filled with the scavenger. Numerous tests have shown(1) that the direct injection method is much more efficient and has a lower capital cost. A typical direct inject flow scheme is shown in Figure 2. The scavenger is injected into the pipeline through a nozzle and either a static mixer or a long length of pipe mixed the gas/liquid mixture. The mixture is then separated in a coalescing filter.

Direct injection of liquid scavengers does have problems. First, the degree of gas/liquid contact is dependent on the type of contacting device, the gas velocity and the residence time. Consequently, the degree of mixing and hence efficiency is sensitive to changing gas flow. In addition, positive separation of the gas and liquid must be achieved since the triazine can interfere with the operation of a glycol dehydration unit by causing severe foaming.

As the most common triazine products are water-based, with water soluble and biodegradable reaction products, the system has the potential for a relatively simple disposal option. In many onshore and offshore operations, the amount of water requiring treatment is very large relative to the amount of liquid scavenger consumed. Thus, the incremental cost of treating this incremental, low-toxicity, biodegradable waste stream can be very small. In the North Sea, spent liquid scavenger is dumped directly into the sea.

Assuming efficient mixing and efficient reaction, the cost of the liquid scavenger can range from a low of $5/pound of H2S to $15/pound. This relatively high chemical cost can often be offset by the low capital cost and often small incremental disposal costs.

The combination of low capital, particularly in the direct injection scheme, simple logistics, and simple wastewater treatment has made this scheme a favorite for gas treatment offshore where there is a very small amount of H2S that needs to be treated. The same feature can be just as attractive onshore as well.

An indicative capital cost comparison of solid and liquid scavengers is shown in Figure 3 as a function of gas flowrate.

Liquid Redox

The iron-based liquid redox process has been continuously improved since it was first introduced in the early 1980’s, with significant improvements tin the areas of operation, capital cost, and operating cost. Currently, the liquid redox of choice is the LO-CAT® process licensed by Gas Technology Products.

The liquid redox process employs aqueous-based solutions containing metal ions, usually iron, which are capable of transferring electrons in reduction-oxidation (redox) reactions. In the LO-CAT process, a non-toxic, chelated iron catalyst is employed to accelerate the reaction between H2S and oxygen to form elemental sulfur.

H2S + ½ O2 So + H2O (2)

All reactions take place in the liquid phase, and 99.9+ % removal efficiency of the H2S is routine.

When treating natural gas streams, liquid redox systems may treat the gas stream directly or may treat the acid gas stream produced from an amine unit. The direct treatment scheme is generally economical for low volume systems while the amine/liquid redox (autocirculation LO-CAT) scheme is more economical at higher flowrates or higher pressures. In the past, much has been made about pressure limitations in direct treating high-pressure gas with liquid redox. However, direct treat installations have demonstrated the ability of the direct treat configuration to treat gas streams up to 900 p.s.i. pressure.

The liquid redox process operates at ambient temperature; consequently, the sulfur is produced as a solid that is most often removed in the form of a filter cake that is 65% sulfur, 35% water. This sulfur product can be upgraded to a 99.9% pure molten sulfur product; however, there is a significant unmet demand for the LO-CAT sulfur cake in North America for the sulfur in cake form makes a superior fertilizer product, acting as a soil amendment and plant nutrient. Registrations of the product as a fungicide is underway and tests show very promising results. Commercial activities are also in process to expand this fertilizer business to parts of Europe.

Most liquid redox installations are in onshore processing facilities, though there have been several successful offshore applications, including both new platform and retrofit installations. However, the footprint and weight can be issues for applying this technology offshore. These issues are being addressed through the development of modified mass transfer devices in the oxidizer system, which promise to reduce capital cost and dramatically shrink the overall size of the system.

Compared to scavenger systems, liquid redox systems are relatively expensive to install but very inexpensive to operate. Total operating costs (utility + chemicals) usually range between $0.13/pound of sulfur and $0.16/pound of sulfur. A diagram of the autocirculation LO-CAT is shown in Figure 4.

The capital cost of the autocirculation LO-CAT is largely dependent on the amount of sulfur being processed. Approximate capital costs for autocirculation LO-CATs are illustrated in Figure 5. The combination of operating and equipment costs, generally makes the liquid redox systems economical up to 20 to 25 tons per day of sulfur, although much larger systems have been installed, such as when the H2S concentration is too low for successful Claus operation.

Claus Systems

Claus systems are well established in oil and gas processing facilities; however, the process has limitations at low capacities. The Claus process converts H2S to elemental sulfur by the following reactions:

H2S + 3/2 O2 SO2 + H2O (3)
2 H2S + SO2 3 So + 2 H2O (4)
Overall: H2S + ½ O2 So + H2O (5)

The Claus system consists of a combustion furnace followed by two or three catalytic reactors with intermediate cooling and reheating. Reaction 3 occurs entirely in the combustion furnace while reaction 4 occurs in the combustion furnace and the subsequent reactors. In a well run unit up to 90% of the sulfur can be formed by non-catalytic means in the combustion furnace. While the scavenger and liquid redox systems operate at ambient temperatures, the Claus reactions require high temperatures with the combustion furnace operating at approximately 1830°F and the catalytic reactors operating at approximately 725°F. Unfortunately, the chemical equilibrium of reaction 4 towards the formation of elemental sulfur is favored at low temperatures; consequently, the overall conversion to sulfur is limited to 95–97% depending on the number of catalytic reactors. To achieve higher removal efficiencies a tail gas cleanup unit is required.

Although there are thousands of Claus units in operation today, the process does have some drawbacks and limitations. Since it is a combustion process, Claus units can only process acid gas streams. Combustible components other than H2S make it impossible to control the SO2/H2S ratio, which is critical to good Claus operation. In addition, acid gas streams containing less than 15–20% H2S are very difficult to process requiring more elaborate Claus processing schemes. Ammonia also presents plugging and corrosion problems, which require special design and operating techniques to overcome.


Each application for sulfur removal will have a unique set of circumstances. However, the first screening criteria in the selection of the most cost effective sulfur removal technology is likely to be sulfur removal capacity. In cases where the application can economically be served by more than one technology, other factors to be considered are: the end user’s sensitivities to capital vs. operating costs, operator involvement, sulfur movements and disposal of waste streams. As a rule of thumb, systems with less than 200 kg/day of sulfur should employ scavengers, while systems with greater than 20 tons per day should employ amine/Claus/tailgas systems. Anything in between should seriously consider liquid redox.

These findings are summarized in the following selection table


 Liquid ScavengerSolid ScavengerLiquid
Amine + Claus + Tailgas
Gases treated        
Acid gas Yes Yes Yes Yes
Natural gas Yes Yes Yes No


Products streams Biodegradable
Sulfur cake for fertilizer Pure
Operating $10/lb. of S $3.50/lb. of S $.15/lb. of S Very small
Equipment Low Moderately
General application guidelines 100 lb. of sulfur per day 300 lb. of sulfur per day Less than 20 tons per day of sulfur Greater than 15 tons per day of sulfur and greater than 15% H2S