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Cleaning Up Gasification Syngas

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Documento sin título Introduction

By definition, gasification is the art of changing a non-gaseous substance, such as a liquid or a solid, into a gas. By this definition, processes such as combustion, anaerobic digestion and pyrolysis would be classified as gasification. However, in today’s world, gasification is defined as any process, which produces a “synthesis gas” or a “syngas”, which is a gas consisting mainly of CO and H2. With this definition, the substance to be gasified may be a gas. The syngas can be used for producing power and/or hydrogen, methanol, Fischer-Tropsch liquids, etc. Gasification is extremely environmentally friendly in that if properly designed, gasification systems produce very minimal pollution even when processing dirty feedstocks, such as high sulfur coals. In addition, gasification can effect large volume reductions in solid wastes while producing an environmentally friendly slag-type byproduct. Also as the prices of natural gas and crude oil continue to increase, gasification can be economically attractive even without governmental subsidies.

In a gasification process, a feedstock is heated to very high temperatures (1000°C to 1500°C) under pressure (20 bar to 85 bar) in the presence of controlled amounts of steam and pure oxygen. As indicated below, two sets of reactions occur in the gasifier. First, partial oxidation (Equation 1) occurs, which is exothermic and provides the heat required for the second set of pyrolysis reactions (Equations 2 through 4), which are endothermic.

CnHm + (n2) O2
nCO + (m/2) H2 (1)
CO2 + C
2CO (2)
C + H2O
CO + H2 (3)
CO + H2O
CO2 + H2 (4)

In addition to CO, H2 and CO2, small amounts of CH4, HCl, HF, COS, NH3 and HCN are also formed. H2S is also formed with the amount dependent on the sulfur content of the feedstock.

Gasification feedstocks can consist of anything organic-based such as coal, petroleum coke, biomass, wood-based materials, agricultural wastes, tars, coke oven gas and asphalt. Gasification provides a means of upgrading the value of very low or even negative value materials. In refineries, cokers use to provide the same function; however, the fuel market for petroleum coke is disappearing, and petroleum coke is becoming a waste product in and of itself.

Gasifiers are classified into three different types—fixed bed units, fluidized bed units and entrained flow units. The best known fixed bed unit is the British Gas/Lurgi process as shown in Figure 1. In this unit, the feedstock is fed into the gasifier from the top and is deposited on the top of a fixed bed of material, which is maintained in the vessel. Steam and oxygen is fed into the bottom of the unit. As the feedstock is consumed, all inorganic materials melt and are removed from the bottom of the vessel where the molten material is fused into a non-leachable, non-hazardous slag. Syngas is removed from the top of the vessel. The best known entrained flow gasifier is the Texaco downflow gasifier as shown in Figure 2. In this process, the material to be gasified is slurried with water and fed into the top of the gasifier along with oxygen. Slag and syngas are removed from the bottom of the gasifier. A fluidized bed gasifier is shown in Figure 3. In this type of unit, the material to be gasified along with steam and oxygen are fed into the bottom of the gasifier and the velocities are such that a percolating bed of material is maintained in the vessel. Syngas is removed form the top of the vessel and slag is removed from the bottom.

In all of these processes, essentially all of the organic material is gasified, and the only solid material remaining is the inorganic slag, which can be used as road base and other building material. This tremendous volume reduction in solid wastes is extremely attractive, especially in Europe where it is becoming very difficult and very expensive to dispose of solid wastes.

Combining a gasification process with power generation is called “Integrated Gasification Combined Cycle” or IGCC. As shown in Figure 4, a typical IGCC facility combines the gasification process with a Brayton cycle (gas turbine/generator) and a Rankine cycle (steam turbine/generator). In petroleum refinery applications, a pressure swing adsorption unit (PSA) can be added to produce hydrogen for use in the refinery.

IGCC’s generally consists of four processing blocks or “islands”—an air separation unit (ASU), the gasifier, the syngas purification island and finally the power generation island. These islands are generally designed and furnished by totally different vendors. The air separation unit is provided by a merchant gas company, which sometimes owns and operates the ASU. The ASU may be sized to provide other customers in the area with oxygen and nitrogen. As previously mentioned, there are many suppliers of gasifiers and the number of suppliers and types of gasifiers are increasing as the global gasification market expands. The power generation equipment is supplied by the same vendors as conventional power plant equipment. And finally, there are many approaches and consequently, many suppliers of purification equipment, which is the main focus of this article.

Syngas Purification

In an IGCC plant (Figure 4), the feedstock generally needs to be processed to make it suitable to feed to the gasifier. Generally, feed preparation consists of milling and screening, and in the case of the Texaco gasifier, the feed needs to be slurried with water.

The feed is then fed to the gasifier where it is combined with oxygen and steam. Two streams exit the gasifier, a molten slag stream which is composed of all the inorganic material in the feed and a syngas stream consisting mainly of CO and H2 but also containing entrained soot and ash, various amounts of H2S depending on the sulfur content of the feed, and trace quantities of CO2, NH3, COS, HCl and HCN. Various treatment processes are required to remove the H2S and other trace contaminants. A description of these processes follows. The clean syngas from the purification island is then saturated with water prior to be combusted in a gas turbine. The moisture reduces NOx formation in the gas turbine. The chemical energy contained in the syngas is recovered as both power and steam generation via a gas turbine/generator set followed by a waste heat boiler/steam turbine/generator set.

The gas exiting the gasifier is hot and contains fine soot and ash particulate. The particulate is removed by either hot, dry candle filters located upstream of the high temperature heat recovery devices or by water scrubbers located downstream of the cooling devices. Hot candle filters are advantageous since the particulate is removed as a dry solid; however, these filters are subject to blinding and breakage. In water scrubbers, the particulate is removed as a slurry which must be dewatered; however, the water scrubber also removes the trace quantities of chlorides which may be present in the syngas and which if not removed will poison the hydrolysis catalyst and cause metallurgy problems in downstream equipment. In both cases, the recovered particulate is recycled back to the gasifier.

 The high temperature heat recovery is generally accomplished by a firetube or radiant boiler followed by water tube boiler. Both boilers produce high pressure steam while reducing the syngas temperature to approximately 425°C.

The next step in the purification process is to remove the carbonyl sulfide (COS) from the gas stream; otherwise, SO2 emission limits may be exceeded after combustion in the gas turbine. There are two means of accomplishing this removal. The more conventional means is to pass the syngas through a fixed bed, catalytic hydrolysis reactor, which will hydrolyze the COS to CO2 and H2S and the HCN to NH3 and CO. Activated alumina type catalysts are generally employed for these applications, and COS concentrations approaching equilibrium levels (1–10 ppm) can be achieved.

When hydrolysis reactors are employed, the reactor effluent gas is cooled and then processed through an acid gas removal system to separate the H2S from the syngas. In syngas applications, physical solvent systems are generally more economical than chemical solvent systems, and the processes of choice are either Rectisol or Selexol. Rectisol tends to remove all of the acid gas components while Selexol is more selective for sulfur compounds. However, chemical solvents such as MDEA are also in use in gasification facilities.

A different approach to removing the COS and the other acid gas compounds from the syngas, is to process cooled (< 50°C) digester gas, free of particulate, through a diglycolamine® (DGA) unit. In the process, the DGA reacts with COS as follows,

 2R-NH2 + COS
R-N-C-N-R + H2O + H2S ­ (5)

In the above equation R is HO-CH2-CH2-O-CH2-CH2 - and R-NH2 is DGA.

The degradation product, R-N-C-N-R, is converted back to DGA in a reclaimer which operates at of temperature of approximately 190°C. The reclaimer reaction is as follows,

R-N-C-N-R + 2H2O
2R-NH2 + CO2 ­ (6)

In addition to removing COS, DGA also removes H2S and CO2 to very low levels.

An economic comparison should be done for each application to determine which acid gas removal scheme should be employed—Hydrolysis/Rectisol, Hydrolysis/Selexol or DGA.

For straight IGCC applications, the effluent syngas from the acid gas removal step is ready to be processed in the power generation island of the facility. The gas is first combusted in a gas turbine/generator set. Usually steam is injected into the combustion zone of the gas turbine to decrease NOx formation. The effluent gas from the gas turbine is then directed through a high pressure, waste heat recovery boiler. The high pressure steam is directed through a steam turbine/generator set. Low pressure steam from the turbine is directed to export, and the effluent gas from the waste heat boiler is exhausted to atmosphere.

For some refinery applications, it may be advantageous to separate some or all of the hydrogen from the syngas for use in the refinery. This is accomplished by passing the syngas through a pressure swing adsorption unit. In this type of unit, the syngas is passed through a bed of adsorbent in which all components other than hydrogen are adsorbed onto a molecular sieve at relatively high pressure. Thus producing a very pure hydrogen stream. The adsorbent bed is then isolated and depressured which releases the CO and other impurities. A water gas shift reactor may also be installed to increase the yield of H2.

Sulfur Recovery

As previously stated, in a gasification process an acid gas stream consisting primarily of CO2 and H2S is produced from whichever acid gas removal process (DGA, hydrolysis/Rectisol, hydrolysis/Selexol, etc.) is employed. It is imperative that the H2S contained in the acid gas stream be recovered in a safe and efficient manner to ensure that the entire process remains “Clean.” Consequently, the selection of the sulfur recovery technology or technologies is an extremely important step in the design process of a gasification facility.

Since essentially all of the sulfur in the gasifier feedstock is converted to H2S, the amount of H2S produced is totally dependent on the sulfur content of the feedstock. As a point of reference, coal has a relatively high sulfur content while biomass has a relatively low sulfur content. Generally, the acid gas removal processes will lower the H2S content of the syngas to less than 4 ppm, which means that, in essence, all of the H2S produced in the gasifier must be processed in the sulfur recovery system.

The type of sulfur recovery system required is dependent on the required sulfur recovery efficiency, the quantity of sulfur to be removed and the concentration of the H2S in the acid gas. The required sulfur removal/recovery efficiency will vary depending on location; however, the gasification industry claims that the technology has “near zero” pollution, so it behooves the industry to install the best available control technology. Currently, H2S removal efficiencies of 99.9+% can be economically achieved.

The Claus process has been the sulfur recovery workhorse for applications with large amounts of sulfur (>20 LTPD), relatively high H2S concentrations (>15%) and consistent inlet conditions. However, the Claus process is limited by chemical equilibrium to removal efficiencies of approximately 98% if three catalytic reactor stages are employed. To achieve higher removal efficiencies, a tail gas treating unit is required.

For over 30 years, the tail gas treating process of choice has been the SCOT process. A simple schematic flow diagram of the SCOT process is shown in Figure 5. In the process, the tail gas from the Claus unit is heated to approximately 300°C in an in-line burner, which serves the dual purpose of heating the gas stream and producing a reducing gas, which is needed in the downstream reactor. The effluent from the burner is then passed over a cobalt-molybdenum catalyst. In the reactor, all of the SO2, COS, and CS2 are converted to H2S by a combination of hydrogenation and hydrolysis reactions. The reactor effluent gas is then cooled and processed through a typical amine unit, which is selective to the absorption of H2S. The recovered H2S is then recycled back to the Claus unit, and the remaining gas is sent to an incinerator prior to exhausting to atmosphere.

It is important to select the proper amine and to design the absorber in such a manner to minimize the absorption of CO2. Otherwise, a large CO2 recycle stream will develop in through the Claus unit. Since the rate of absorption of H2S in alkanolamines is much quicker than CO2, absorbers should be designed to minimize gas–liquid contact. Regarding amine selection, MDEA is a good selection for syngas. If the absorber is designed properly and the correct amine is chosen, CO2 absorption can be limited to between 10% and 40% of the CO2 in the feed gas to the absorber(1).

In some cases, the SCOT unit can be integrated with the upstream amine unit, which is treating the syngas and producing the acid gas for the Claus unit. For instance, if the syngas is being treated with an MDEA amine unit, the system can be designed with two absorbers, one for the syngas and one for the Claus tailgas; however, only one regenerator would be required.

When using MDEA, the sulfur content of the treated effluent gas will be less than 250 ppm, and the overall sulfur recovery of a Claus/SCOT system is typically 99.8%(2). The treated effluent gas is always processed through an incinerator prior to exhausting to atmosphere.

Another method of increasing the overall sulfur recovery of a Claus unit is to replace the amine portion of the SCOT process with a liquid redox process such as LO-CAT® as illustrated in Figure 6. This approach differs from that of SCOT because 99.9+% of the H2S in the effluent gas from the hydrolysis/hydrogenation unit is converted directly to sulfur in the redox process(3) without having to recycle gas back to the inlet of the Claus unit.  Because the liquid redox system is so efficient in removing H2S, overall (Claus + tail gas cleanup) sulfur recoveries of 99.9+% can be easily realized. Thus, incineration of the liquid redox effluent gas is not required prior to exhausting to atmosphere; consequently, the capital and operating cost of the incineration system are removed from the project economics. In addition, by operating the Claus unit at high H2S:SO2 ratios (sub-stoichiometric oxygen), it is possible to eliminate the hydrolysis/hydrogenation unit and still maintain overall sulfur recoveries of 99.9+%. This approach is shown in Figure 7.

Another unique feature of employing a liquid redox system as a tail gas treating unit is that the turndown capability of the Claus/tail gas system can approach 100% if the system is design properly. The liquid redox system differs from SCOT in that the liquid redox process is a sulfur recovery process in and of itself, which has 100% turndown capability. Consequently, by correctly sizing the liquid redox unit, the acid gas feed to the Claus unit can be routed directly to the liquid redox unit when the turndown capability of the Claus unit is reached.

For syngas applications in which the sulfur capacity is less than 20 LTPD and/or the H2S in the acid gas is less than 15% and/or a great deal of turndown is required, Claus units may not be a good choice due to difficulties in keeping the unit running. However, these are ideal conditions for a liquid redox process.


Cleaning up syngas from gasification units is not a straightforward proposition. Each application must be investigated in regards to both the technical and economic aspects of the specific requirements of the application. Feedstock variability is also an important characteristic, which must be evaluated since many of the cleanup requirements will be dependent upon the nature of the feedstock. In addition, great care should be taken in the selection of the sulfur recovery portion of the system, since the sulfur recovery unit will determine how really “Clean” the system is.

  1. Kohl, A.L. and Riesenfeld, F.C., “Gas Purification, Third Edition” p-686.
  2. Holub, P.E. and Sheilan, M., “LRGCC 200 Conference Fundamentals Manual”, p-106.
  3. Nagl, G.J., “Employing Liquid Redox as a Tail Gas Cleanup Unit”, February 2001, yet unpublished.
  4. Holub, P.E. and Sheilan, M., “LRGCC 200 Conference Fundamentals Manual”, p-105

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