Acid Gas Removal

Raw synthesis gas (syngas) produced from coal gasification needs to be cleaned of sulfur-bearing acid gases (primarily hydrogen sulfide, [H2S], and carbonyl sulfide, [COS]) to meet either environmental emissions regulations, or to protect downstream catalysts for chemical processing applications. For integrated gasification combined cycle (IGCC) applications, environmental regulations require that the sulfur content of the product syngas be reduced to less than 30 parts per million by volume (ppmv) in order to meet the stack gas emission target of less than 4 ppmv sulfur dioxide (SO2)[1]. In IGCC applications, where selective catalytic reduction (SCR) is required to lower NOX emissions to less than 10 ppmv, syngas sulfur content may have to be lowered to 10 to 20 ppmv in order to prevent ammonium bisulfate fouling of the heat recovery steam generator's (HRSG) cold end tubes. For chemical production, the downstream synthesis catalyst sulfur tolerance dictates the sulfur removal level, which can be less than 0.1 ppmv.

Acid gases in a gasification process typically consist of H2S, COS, and carbon dioxide (CO2). Current processes of removing these gases from the raw syngas typically involve countercurrent absorption with a regenerative solvent, in an absorber column. Acid-gas-rich solvent from the absorber bottom is then stripped of its acid gas in the regenerator by applying heat through reboiling. Lean solvent from the regenerator bottom is cooled and recycled to the top of the absorber and the cycle is repeated. Depending on the solvent used, COS may first need to be converted to H2S via a COS hydrolysis unit. H2S and CO2 can be removed either simultaneously or selectively, depending on the raw syngas composition and conditions, and the end syngas specifications. H2S removed by the regenerator is sent to a sulfur recovery unit, such as a Claus Plant, to recover the sulfur as a salable byproduct. Regenerative solvent based acid gas removal (AGR) processes are commonly used in refining, chemical, and natural gas industries. These processes can be grouped into three general types: chemical solvents, physical solvents, and hybrid mixtures of chemical and physical solvents.

Chemical SolventsChemical solvents include primary, secondary and tertiary amines, and potassium carbonate as listed in Table 1, below. Through acid-base reactions, aqueous solutions of these basic alkanolamines, or alkaline salts, capture and remove acid gases by forming weak chemical bonds with dissolved acid gases in the absorber. The bonds are broken by heat in the regenerator to release the acid gases and regenerate the solvent for reuse. Chemical solvent absorption processes normally operate at slightly above ambient temperature. Chemical solvents are more effective for low acid gas partial pressure applications, than physical solvents.

Table 1: Common Chemical Solvents

SOLVENT ACRONYM TYPE OF AMINE

Monoethanolamine MEA Primary

Diglycolamine DGA Primary

Diethanolamine DEA Secondary

Diisopropanolamine DIPA Secondary

Hindered Amine Flexsorb SE Secondary

Triethanolamine TEA Tertiary

Methyldiethanolamine MDEA Tertiary

Potassium Carbonate Hot Pot Not Amine

Physical SolventsPhysical solvents are organic solvents that have a high affinity for acid gases. Some of the solvents that are commercially available are listed in Table 2. Acid gases are removed from sour syngas (syngas which contains significant amounts of H2S and COS) by dissolving the acid gases into the solvent under high partial pressure and low temperature in the absorber. Solvent, rich with acid gases from the absorber, is then subjected to multistage controlled pressure decreases, followed with hot stripping in the regenerator, to release the acid gases and regenerate the solvent for reuse. Physical solvent absorption processes normally operate at cryogenic temperatures (below –150 °C, –238°F or 123 K). In general, physical solvents are more effective for high acid gas partial pressure applications.

Table 2: Common Physical Solvents

SOLVENT TRADE NAME

Methanol Rectisol

Methanol and toluene Rectisol II

Dimethy ether of poly ethylene glycol Selexol

N-methyl pyrrolidone Purisol

Polyethylene glycol and dialkyl ethers Sepasolv MPE

Propylene carbonate Fluor Solvent

Tetrahydrothiophenedioxide Sulfolane

Tributyl phosphate Estasolvan

Hybrid Solvent Systems

Hybrid solvents are mixtures of amine chemical solvents and physical solvents to take advantage of the high treated-gas purity performance of chemical solvents, and the low energy requirement associated with flash regeneration of physical solvents. Hybrid solvents commercially available include Sulfinol-D (aqueous DIPA plus sulfolane), Sulfinol-M (aqueous MDEA plus sulfolane), FLEXSORB SE (aqueous hindered amines plus unspecified physical solvents), and FLEXSORB PS (aqueous MDEA plus unspecified physical solvents), Amisol (methanol with MDEA or diethylamine), and Selefining (methanol and toluene). Hybrid solvents allow for better acid gas absorption at high partial pressures, and feature higher solubility of COS and organic sulfur compounds than aqueous amines. The amine portion allows AGR under very low partial pressures. In general, hybrid solvents are effective over a wide range of acid gas partial pressures at near room temperatures.

ApplicationsThere are over 30 AGR processes available commercially, but only four of these have been demonstrated or implemented in the 18 commercial-size coke or coal-based gasification plants worldwide, as reported by SFA Pacific in 2002:[2]  Rectisol, Selexol, Sulfinol, and MDEA. Half of these18 plants are for chemical production while the other half are IGCC applications.

Eight of the nine chemical production plants, in operation as of 2002, use Rectisol (typically operates at -40°F to -80 °F), and one uses Selexol (typically operates at 20°Fto 40 °F). This is consistent with the general perception that physical solvent-based AGR is normally selected to protect synthesis catalysts against poisoning from sulfur and other trace contaminants in chemical production from coal applications. While Rectisol is more costly, it is preferred for treating coal-based syngas because it allows for very deep sulfur removal (<0.1 ppmv H2S plus COS), and also because it can remove HCN, NH3, and many metallic trace contaminants (including iron- and nickel-carbonyls, and mercury) to provide additional catalyst protection.

Six of nine IGCC plants, in operation as of 2002, use MDEA with the remaining three using Rectisol (Sokolovska Uhelna, Lurgi gasifier), Selexol (Cool Water, GE gasifier), and Sulfinol (Nuon Buggenum, Shell gasifier). Figure 1 shows a simplified process flow diagram (PFD) of a typical MDEA-based AGR process. Figure 2 shows a simplified PFD for the Selexol process. Due to the need for refrigeration, as well as a more complex flashing arrangement, a typical physical solvent process can be two to three times more costly than an amine based chemical solvent system.

CLICK ON GRAPHICS TO ENLARGEFigure 1: Simplified MDEA Flow Diagram

Figure 2: Simplified Selexol Flow Diagram

Water-Gas-Shift / COS Hudrolysis

Depending on application, after particulate removal, raw syngas from gasification may need to be conditioned with a water-gas shift (WGS) reaction to adjust the hydrogen-to-carbon monoxide (H2/CO) ratio to meet downstream process requirements. In applications where very

low sulfur (< 10 ppmv) synthesis gas (syngas) is required, converting carbonyl sulfide (COS) to hydrogen sulfide (H2S) before sulfur removal may also be necessary.

Water Gas Shift

In applications where a high H2/CO ratio is needed, syngas is passed through a fixed-bed reactor containing shift catalysts to convert carbon monoxide (CO) and water into additional H2

and CO2 according to the following reaction: 

CO  +  H2O   ↔  H2  +  CO2

The shift reaction will operate with a variety of catalysts between 400°F and 900°F.  The reaction is equal molar and therefore the effect of pressure on the reaction is minimal.  The equilibrium for H2 production is favored by high moisture content and low temperature for the exothermic reaction.  The WGS reactor can be located either before the sulfur removal step (sour shift) or after sulfur removal (sweet shift).

Sour shift uses a cobalt molybdenum catalyst and is normally located after the water scrubber, where syngas is saturated with water at about 450°F to 500°F, depending on the gasification conditions and the amount of high temperature heat recovery. The scrubber syngas feed is normally re-heated to 30°F to 50°F above saturation before entering the shift reactor to avoid catalyst damage by liquid water.  An important benefit of sour shift is its ability to also convert COS and other organic sulfur compounds into H2S to make downstream sulfur removal easier. Therefore, syngas treated through WGS does not need separate COS hydrolysis conditioning.

A conventional high temperature (HT) sweet shifting operates between 550°F to 900°F and uses chromium or copper promoted iron-based catalysts.  Because syngas from the sulfur removal process is saturated with water at either near or below ambient temperature, steam injection or other means to add moisture to the feed is normally needed for HT sweet shifting.

A conventional low temperature (LT) sweet shift, typically used to reduce residual CO content to below 1%, operates between 400°F to 500°F and uses a copper-zinc-aluminum catalyst. LT sweet shifting catalysts are extremely sensitive to sulfur and chloride poisoning and are normally not used in coal gasification plants.

Sweet shift is normally not used for coal gasification applications.  This is due to the inefficiency of having to cool the syngas before sulfur removal, which condenses out all of the moisture gained in the water scrubber, and then reheating and re-injecting the steam into the treated gas after H2S removal to provide moisture for shift.  Sour shift is normally preferred for coal gasification applications since the moisture gained in the water scrubber is used to drive the shift reaction to meet the required H2/CO ratio.  For most slurry-fed gasifiers, a portion of the syngas feed may need to be bypassed around the sour shift reactor to avoid exceeding the required product H2/CO ratio.  Depending on the gasification process and the required H2/CO ratio, additional steam injection before sour shift may be needed for dry-fed gasifiers.

Shifted syngas is cooled in the low temperature gas cooling (LTGC) system by generating low pressure steam, preheating boiler feed water, and heat exchanging against cooling water before going through the acid gas removal system for sulfur removal.

COS Hydrolysis

Most of the sulfur in the coal is converted to H2S in the gasifier.  Depending on the gasification temperature and moisture content, approximately 3 to 10% of the sulfur is converted to COS.  To produce sweet syngas with less than 10 ppmv sulfur for downstream applications, the COS needs to be converted to H2S before sulfur removal in most current commercial acid gas removal (AGR) processes.  This is done by passing syngas from the water scrubber through a

catalytic hydrolysis reactor where over 99% of the COS is converted to H2S according to the following reaction:

COS  +  H2O   ↔  H2S  +  CO2

The scrubbed syngas feed is normally re-heated to 30°F to 50°F above saturation before entering the reactor to avoid catalyst damage by liquid water.  COS hydrolysis uses an activated alumina-based catalyst and is normally designed to operate at 350°F to 400°F.  The reaction is equal molar and is therefore largely independent of pressure.  The equilibrium for COS conversion is favorable at low temperatures due to the exothermic nature of the reaction, however the heat of reaction is normally dissipated among large amount of non-reacting components, yielding isothermal reactor conditions. 

COS hydrolysis product gas is cooled in the LTGC system by generating low pressure steam, preheating boiler feed water, and heat exchanging against cooling water before going through the acid gas removal system for sulfur removal.

Sulfur Recovery and Tail Gas Treating

The sulfur compounds from the coal feed of a gasification process are generally removed from the synthesis gas (syngas) via an acid gas removal (AGR) process as a concentrated hydrogen sulfide (H2S) stream.  Sulfur is then recovered as either liquid or solid elemental sulfur, or as sulfuric acid, depending on market demands. For an elemental sulfur product, a Claus sulfur recovery unit produces elemental sulfur from H2S in a series of catalytic stages, achieving about 98% recovery of the sulfur in the syngas. Part of the H2S is oxidized to produce sulfur dioxide (SO2), which is then reacted with the remaining H2S to give elemental sulfur and water. Tail gas from the Claus process is sent for further treatment to an amine-based Shell Claus Offgas Treatment (SCOT) unit to achieve an overall sulfur recovery of 99.8%.

For recovery as a sulfuric acid, H2S is first oxidized to SO2, then to sulfur trioxide (SO3), which is then scrubbed with water or a recycled weak sulfuric acid stream to yield saleable 98% sulfuric acid. Typically, 99.8% of the H2S can be recovered in the sulfuric acid plant.  The Claus Process

The basic Claus process for sub-stoichiometric combustion of H2S to elemental sulfur follows the following reactions:

H2S  + 1 ½ O2 → SO2  +  H2O2 H2S   +   SO 2  → 2 H 2O   +   3 S

3 H2S  +  1 ½ O2  → 3 H2O  +  3 S

Figure 1 shows a typical block flow scheme of a 3-stage split-flow Claus sulfur recovery unit (SRU).  Acid gas from the acid gas removal (AGR) process, along with the recycle gas stream from the tail gas treating unit and from the sour water stripping plant, is burned with sufficient air to produce an overall SRU feed with the desired 2 to 1 stoichiometric ratio of H2S to SO2 for conversion to sulfur and water. The hot burner exhaust is cooled in the waste heat boiler (WHB) before being mixed with the remaining AGR acid gas prior to entering the first stage catalytic converter.  Approximately 75% of the sulfur conversion occurs in the 1st stage catalytic converter.  The remaining sulfur species in the 1st stage catalytic converter exhaust are converted in subsequent catalytic converters. Reaction heat produced in the burner is recovered in the integrated WHB by generating 650 psig steam.

Sulfur products are cooled and condensed by generating low pressure steam. Condensed sulfur product is stored in an underground molten sulfur pit, where it is later pumped to truck loading

for shipment. Claus tail gas from the last stage sulfur condenser is sent to the SCOT tail gas treatment unit to remove unconverted H2S, SO2, and carbonyl sulfide (COS) before disposal.

Figure 1: A Typical Claus Process Block Flow Diagram

SCOT Tail Gas Treating

Figure 2 shows a simplified SCOT tail gas treating unit (TGTU).  Tail gas from the Claus SRU is heated in an in-line burner before entering the hydrogenation reactor, where all sulfur species are converted to H2S.  Hydrogenation reactor effluent is then cooled by generating low pressure (LP) steam, followed by cooling with heat exchange between cooling water.  Residual H2S in the cooled tailgas is removed with amine in a counter-current packed absorber. The treated tail gas from the absorber top is incinerated before being vented the to atmosphere. The rich solvent from the amine absorber is pumped to the regenerator after heat exchange against the hot lean solvent from the regenerator. Acid gases are stripped from the solvent in the trayed regenerator via a steam reboiler. The hot lean solvent from the regenerator bottom is pumped back to the absorber after being heat exchanged with rich solvent and cooling water to lower its temperature. Acid gas from TGTU amine regenerator overhead is recycled back to the Claus plant for sulfur recovery.

Figure 2: A Simplified SCOT Tail Gas Treating Scheme

Sulfuric Acid

The option to recover sulfur in the form of sulfuric acid is practiced at the Tampa Electric’s IGCC demonstration plant. The sulfuric acid plant receives the H2S from the AGR unit and other offgas streams. The gas streams are then burned in a decomposition furnace, producing primarily SO2

with trace amounts of SO3, sulfuric acid and elemental sulfur.  The decomposition furnace exit gas is cooled from about 1,950°F to 650°F in a waste heat boiler to produce steam.  The SO2

and oxygen (from either air or an air separation plant) then react over a vanadium based catalyst bed in a converter according to the reaction;

SO2  +  ½ O2  → SO3

The produced SO3 is then reacted with water as follows:SO3  +  H2O  → H2SO4

The catalytic oxidation of SO2 to SO3 is highly exothermic, and the equilibrium becomes increasingly unfavorable for SO3 formation as temperature increases to about 800 °F. For this reason, special catalytic converters (reactors) are designed as multistage reactor bed units with air cooling between each bed for temperature control.

Figure 3 shows a simplified flow of the Tampa Electric IGCC sulfuric acid plant. In the plant, the H2S from the acid gas removal unit is first burned to form SO2 in the decomposition furnace. The furnace also processes H2S and ammonia from the water stripper, and ammonia is converted into harmless N2 and water. A waste heat boiler at the outlet of the decomposition furnace cools the gas to generate a medium pressure steam for in-plant use.  The gas is then further cooled and dried. This step produces a ‘weak acid’ waste stream which needs to be neutralized before discharging into the cooling pond.

Oxygen from the air separation plant is then added to the produced SO2 to convert it into SO3, in a series of catalytic reactors, with inter-reactor-bed cooling as shown. Gas from the final reactor beds enters the absorbing towers, where the produced SO3 reacts with the excess water in a circulating, strong (98%) sulfuric acid stream, creating additional H2SO4.  This incrementally raises the concentration of the sulfuric acid so that water is introduced as needed to maintain the H2SO4 at 98.5% as the final product.

The Tampa Electric sulfuric acid plant is very efficient, converting over 99.5% of the incoming H2S to H2SO4.

Figure 3: Tampa Electric IGCC Sulfuric Acid Plan Flow Diagram

Sulfur and Other Chemicals

In the course of cleaning synthesis gas (syngas) in a variety of gasification applications, several chemicals can be removed and processed into useful products. This page first looks at the chemical byproducts of the Great Plains Synfuels Plant (GPSP) and then sulfur and ammonia in general.

Example: Great Plains Synfuels Plant

Run by the Dakota Gasification Company, the GPSP in Beulah, North Dakota, gasifies locally mined lignite coal and processes it into synthetic natural gas (SNG). It has taken advantage of gasification’s product flexibility to adapt to changing product markets, by adding an ammonia synthesis plant in the late 1990s.

The GPSP also produces a number of saleable byproducts, in particular ammonium sulfate. The syngas produced by the gasifiers is cleaned in a Rectisol unit (see Gas Cleaning for more information). The “acid gas” streams from this unit are sent to a boiler that has its flue gas “scrubbed.” A Flue Gas Desulfurization (FGD) unit uses ammonia to remove sulfur (in the flue gas as sulfur dioxide [SO2]), producing ammonium sulfate [(NH4)2SO4], a fertilizer. The sale of ammonium sulfate helps to recoup some of the cost of cleaning the syngas—required for further processing and by environmental regulations.

Practical Experience Gained During the First Twenty Years of Operation of the Great Plains Gasification Plant and Implications for Future Projects [PDF-3.1MB]

Sulfur

Sulfur is a component of coal and other gasification feed stocks. The sulfur typically must be removed from the gasifier syngas product prior to additional processing.

There are many methods for syngas clean-up, and specifically for sulfur removal, which is normally separated from the syngas stream as hydrogen sulfide (H2S) and processed into elemental sulfur. These options are detailed in the sections on Syngas Clean-Up and Sulfur Removal, but are discussed in general here.

In a typical design, a process called MDEA/Claus/SCOT is used. Each of these processes can be used independently, but many plant designs (e.g., NETL IGCC Base Cases) run similar sulfur removal systems. Methyl diethanolamine (MDEA) is a chemical solvent that is used as an absorber. In the gas cleanup process, cooled syngas is contacted with the MDEA in an absorber unit, where, as the gas passes through, almost all of the H2S and some carbon dioxide (CO2) are removed. The MDEA is now rich with H2S and it moves on to a stripping unit to clean and recycle the MDEA and separate the H2S.

The syngas that passes through the MDEA absorber still contains some sulfur compounds and so this gas continues on to the Claus/SCOT unit. In the Claus unit, the century-old Claus process turns H2S and SO2 into elemental sulfur. A catalyst, typically titanium or alumina based, is used to facilitate the reaction.

The last commonly used unit in this desulfurization process example is the Shell Claus Off-gas Treating (SCOT) unit. This process removes most all of the remaining sulfur—in the form of a tail-gas stream of unreacted sulfur, H2S, SO2, and carbonyl sulfide (COS)—that the MDEA and Claus units miss. The SCOT unit uses a cobalt-molybdenum catalyst to convert SO2 to H2S, which is then removed in an absorber. The H2S rich stream continues on to another stripping unit, while the remaining acid gas that passes through the absorber is recycled to the Claus unit.

Finally, the H2S-rich streams are stripped from their solvents. The stripper units remove the H2S, and the solvent is regenerated and stored for reuse. The H2S then continues to a sulfur plant, where it is converted to elemental sulfur and stored with the sulfur generated in the Claus unit. Alternatively, sulfur compounds can be converted to SO2 then to sulfur trioxide (SO3) and finally to sulfuric acid (H2SO4) in a sulfuric acid reactor.

Coal-to-Chemicals

Gasification and the chemical industry have a long history, with modern gasification used by the industry since the 1950s. With rising crude oil and natural gas prices, as well as concerns about these fuels’ ability to meet demand into the future, coal gasification is increasingly being used as a source for chemical production. Please see the Markets section below for more information about the growth of the coal-to-chemicals industry.

In coal-to-chemicals, synthesis gas (syngas)—a gaseous mixture of primarily carbon monoxide and hydrogen—is produced by gasification of coal (note: other feedstocks are also capable of gasification to produce syngas). The syngas can then be fashioned into a number of useful chemical building blocks, like methanol or acetyls for example. Ammonia and urea are significant products of coal-to-chemicals for use in fertilizers. The syngas composition—specifically, the ratio of hydrogen to carbon monoxide—is important for some downstream processes, so a water-gas shift reactor is sometimes used to change this balance. Different required composition ranges and the water-gas shift reaction are discussed in the more detailed subsections at right.

This page will serve as a brief introduction to the coal-to-chemicals technology and markets as well as the advantages and challenges of coal-to-chemicals.

Market

Producing chemicals from coal through gasification has been used since the 1950s and, as such, has already carved out a share of the chemicals market. One important example is the production of methanol, of which, 9% worldwide is produced by gasification (Gasification, Higman C., Van der Burgt M., 2003). Many chemicals are high-value products and gasification provides the option of using relatively inexpensive coal to produce them. Methanol and ammonia are especially important as key building blocks for further chemical synthesis. According to the 2010 Worldwide Gasification Database, a survey of current and planned gasifiers, from 2004 to 2007 chemical production increased its gasification product share from 37% to 45%. From 2008 to 2010, 22% of new gasifier additions will be for chemical production. (For more on the markets for other gasification products and in general, see the Markets section.)

The quickly growing Chinese economy has given rise to a number of coal-to-chemical facilities, some already operating—21 plants came online from 2004 to 2007—and many planned for the near future. China, like the United States, has large domestic coal supplies and growing demand for chemical products like ammonia-based fertilizers and methanol, for direct use and as a building block in other chemical syntheses. The World Gasification Database 2007 shows that of 41 coal-to-chemicals plants worldwide in operation or planned by 2010, 35 are in China: 22 active and 13 planned.

While no new United States coal-to-chemical plants are planned to come online before 2010 (see below for information on the existing Eastman Coal-to-Chemicals Plant), the U.S. chemical industry as a whole shipped $629.3 billion in 2007, a 9% increase over 2006. In particular, agricultural chemicals, like ammonia-based fertilizers (see the Great Plains Synfuels Plant for more on the coproduction of ammonia and SNG) rose 14.5% in price. Overall, the high price of natural gas led to a 7.4% drop in agricultural chemical production, which indicates an opportunity for coal-to-chemical plants (data from Facts & Figures, July 7, 2008, Chemical & Engineering News).

Eastman Coal-to-Chemicals Plant

   

 

 Ammonia storage tanks in Starbuck,

MN.Photo by Nic McPhee

 

 Eastman Coal-to-Chemicals PlantKingsport, TN

In addition to agricultural chemicals like ammonia and urea for fertilizer, methanol is a substantial product of coal-to-chemicals gasification worldwide. One of the earliest and most notable coal-to-chemicals plants in the United States is owned and operated by Eastman Chemical Company and based in Kingsport, Tennessee, where the plant produces methanol and acetyl chemicals, produced from methanol and carbon monoxide through a reaction called carbonylation. Acetic acid and acetic anhydride are commonly used in pharmaceutical and industrial applications and can be processed into products like paints, fibers, photographic film, tool handles, cigarette filters and more. Methanol also has important uses, as a fuel or fuel additive, for example.

The Eastman coal-to-chemicals plant, first opened in 1983, was designed to process syngas from the gasification of Southwest Virginia and Eastern Kentucky coal into 500 million pounds per year of acetic anhydride and acetic acid, enough to supply half of Eastman’s raw acetyl needs. Acetyl chemicals are important to many of Eastman’s products, but especially those at the Kingsport site, where five of seven manufacturing divisions rely on acetyls as a raw material. The success of the operation led to a decision to expand the plant capacity to an excess of 1 billion pounds per year to meet all of Eastman’s needs, a testament to the ability of gasification to reliably, economically, and efficiently meet the coal-to-chemical requirements of Eastman’s Kingsport facility.

Huayi Group Coal-to-Chemicals Plant

Located in Shanghai, the Huayi Group’s facility is one of the earliest and most successful coal-to-chemical plants in China. Partnered with Praxair for air separation technology and currently using GE gasifiers, it produces 800 kilotons (kt) methanol and 500 kt glacial acetic acid (glacial indicates without water, in this case). The plant brought in $4.68 billion in revenue in 2007 and intends to develop further downstream processes to balance acetic acid production and to manufacture products like olefins, dimethyl ether, and others. (Huayi – Praxair Partnership in Integrated Coal to Chemical Site, Presentation, Gasification Technologies Conference, Oct 7, 2008.)

Advantages

The synthesis of many chemicals often begins with a hydrocarbon source, frequently crude oil or natural gas. As both crude and natural gas increase in price and increased demand raises questions about supply, coal is an attractive solution. Coal can be cleanly gasified and is relatively inexpensive and domestically abundant with estimates of over two centuries in reserve at current consumption rates. Producing chemicals from coal is a way to increase energy security and diversity and as the Eastman Coal-to-Chemicals plant has shown (described above), it can be done profitably and with good reliability. From a market standpoint, chemicals are growing in demand, especially in rapidly developing China. Environmentally, the syngas cleaning process can reduce emissions below regulated standards and is well-positioned if carbon dioxide capture becomes regulated. Although coal, petroleum and natural gas are most common, chemical production through gasification can potentially use a wide variety of feedstocks including refinery waste, biomass, and municipal waste. Steam produced by the gasification process can often be effectively integrated to meet a chemical plants needs, increasing efficiency. Coal-to-chemicals is also well-suited to cogeneration with an IGCC power plant, because of the way each can respond to product demand, explained in more detail on the Co-generation page.

   

 

 Huayi Group coal to chemical plant,

Shanghai, China. Photo courtesy Huayi and Praxair.

Challenges

Of the “coal-to-” processes, coal-to-chemicals is potentially the most stable, having been demonstrated by Eastman and several other projects to be profitable and reliable. Coal-to-chemicals technology is seeing a large market growth, especially in China, indicating confidence in the technology. However, challenges to coal-to-chemicals are still similar to the challenges that face other uses of gasification, mainly cost (capital and operating/maintenance) and availability. For the production of some chemicals like methanol, ammonia, acetyls, etc., the economics of coal-to-chemicals are favorable—the Eastman Coal-to-Chemicals plant is profitable, for example—and so cost is not a barrier to project realization. The economics of gasification can continue to be improved, however. Increased availability, either through new materials or better maintenance methods, is also an area where research and development could lead to substantial improvements. These general gasification challenges are discussed in the linked Challenges section. Research and development ideas are also discussed below and in the linked Research & Development section.

The Eastman Coal-to-Chemicals Plant in Kingsport, Tennessee, lists production rate, reliability, maintenance cost, and safety as primary importance to the facility’s operation. Increasing process efficiency to produce more product over a period of time or per coal input helps defer high initial capital costs. Related to, and perhaps more important than, production rate is reliability. An outage can have drastic consequences on the economics of a plant, so availability is an important factor to consider during planning. Through a well-defined maintenance schedule, redundant units, and improvements to problem areas (identified through a consistent “run review” schedule), the Eastman plant has been able to demonstrate over 98% gasifier uptime since 1986. Eastman also found that having more frequent, planned maintenance—even though it increased turnaround time—has lowered the number of failures, increased production, and decreased overall maintenance costs. Similarly, by having plans and procedures in place, the plant has been able to establish an excellent safety record.

Problem areas identified by Eastman are similar to other gasifiers, mainly materials issues such as feed injector (burner) failure from corrosion and refractory wear. Eastman has found that routine maintenance and improvements from research and development have substantially reduced these problems.

Research and Development

Many of the research and development avenues being undertaken for other gasification applications will also have beneficial results for coal-to-chemicals. For example, novel membrane-based air separation methods, show promise towards lowering the cost of pure oxygen supply for gasification. This would lower the energy and operation costs of the gasifier system and possibly the air separation unit’s capital costs. Clean-up methods could allow for higher temperature or more efficient syngas clean-up, which would also reduce costs associated with heat loss and operation. Research into increasing gasifier availability, much of which has been done by Eastman specifically related to coal-to-chemicals, will increase the productive and profitable periods of gasifier operation while also reducing maintenance costs.

Some of Eastman’s research and developments include:

← Fuel injector (burner) design improvements (six patents) ← Knowledge leading to improved shut-down/start-up procedures and decreased downtime ← Procedures for virtually seamless switching between gasifiers (cycling the spare) for

maintenance

Source: Simplified Diagram of the AGR Process

Sulfur compounds need to be removed in most gasification applications due to environmental regulations or to avoid catalyst poisoning. Whether it is electricity, liquid fuels, or some other product being output, sulfur emissions are regulated, and sulfur removal is important for this reason, along with the prevention of downstream component fouling. Being able to recover saleable sulfur is an important economic benefit.

In 2007, 8.2 million tons of elemental sulfur was produced, with the majority of this coming from petroleum refining, natural gas processing and coking plants. Total shipments were valued at $400 million, with the average mine or plant price of $40 per ton, up from $32.85 in 2006. The United States currently imports sulfur (24% of consumption, mostly from Canada), meaning the market can support more domestic sulfur production.

← USGS Mineral Commodity Information: Sulfur

Ammonia

In a similar MDEA system to remove CO2, byproduct ammonia can be recovered. Following the MDEA absorber, some of the CO2 gas contains what is called “sour water.” This sour water condenses as it is cooled. It dissolves almost all the nitrogen compounds and any chloride and fluoride present. It also dissolves smaller amounts of H2S, COS, CO, and CO2. The water is removed in low temperature syngas coolers and a knock-out drum (vapor-liquid separator), where it is then sent to a sour water treatment system.

Ammonia is recovered as anhydrous ammonia which can then be used in selective catalytic reduction (SCR), converted, or sold as is for fertilizer or other chemical markets.

A general overview of the CO2 scrubbing process is given in the 2006 paper, Impact of CO2 Capture on Transport Gasifier IGCC Power Plant, commissioned by DOE and partners.

Warm Gas Cleanup

In any gasification process, the production of clean syngas—free of contaminants such as particulates, sulfur, ammonia, chlorides, mercury, and possibly carbon dioxide—is crucial to final

product quality and environmental emission levels.  The gas cleanup step is also an important factor in plant economics, as it can account for a substantial portion of the overall capital cost.  Conventional gas cleaning is typically carried out at low temperature by scrubbing the syngas using chemical or physical solvents that require cooling the gas to below 100°F.  The cooling equipment required, and the need to reheat the syngas before being sent to the combustion turbine, for example, result in economic and thermodynamic penalties that decrease the efficiency of a gasification plant.

Challenges of High Temperature Gas Cleanup

The extremely heterogeneous nature of coal and other carbonaceous feedstocks used to produce syngas by gasification presents a very complex and technically challenging situation for any comprehensive syngas cleaning system.  These challenges include:

← Multiple contaminants at different concentrations ← Different product requirements for various syngas utilization processes ← Simultaneous removal of multiple contaminants including trace elements ← Process, materials and equipment handling issues

The focus of most high temperature syngas cleanup was the removal of particulates, sulfur, chloride and alkalis, of which, particulate removal (via devices such as candle filters) and sulfur removal have been commercially demonstrated. Preliminary efforts of the so-called “hot gas” cleanup focused at a maximum operating temperature of about 1000°F so that the alkalis in the hot syngas can be condensed out on the particulates so not to cause corrosion problem with downstream equipment.  Substantial syngas cooling is still required. Although particulates, sulfur and alkali compounds could be removed to very low levels, serious material durability problems were encountered.  It was also difficult to remove the other contaminants, including ammonia, chlorides, and mercury.  DOE recognizes many of these issues and challenges, and the desire to overcome them by operating gas cleanup at a lower temperature of 700-800°F - Warm Gas Cleanup - to minimize equipment and material handling problems. A more comprehensive multi-component syngas cleanup system is also being developed.

Recent Developments

Research Triangle Institute (RTI), under a cooperative agreement with DOE, is developing warm gas cleanup (WGCU) technology.  The program has an objective of developing a warm multi-contaminant syngas cleaning system for operation between 300 to 700°F. This system will be composed of a bulk contaminant removal stage and a polishing removal stage. Specific goals are to:

← Reduce the hydrogen sulfide (H2S) and carbonyl sulfide (COS) to less than 5 parts per million by volume (ppmv) using a regenerable solid sorbent (e.g., RTI’s RT-3 sorbent) in a bulk removal stage

← Reduce the hydrochloric acid (HCl) to less than 5 ppmv with the use of disposable sodium bicarbonate (nahcolite) sorbent in a bulk stage

← Reduce Arsenic (As), selenium (Se) using the regenerable RTI-3 sorbent ← Reduce sulfur species and HCl to less than 50 ppbv and less than 800 ppbv, respectively, in the

polishing stage

RTI has demonstrated that its attrition-resistant RTI-3 zinc oxide-based sorbent can reduce sulfur gas concentrations to less than 1 ppmv in syngas at 650°F and 300 to 600 psig.  The RTI-3 sorbent is regenerable at 1230-1300°F for numerous absorption cycles.

The technology, along with RTI’s proprietary direct sulfur recovery process was pilot tested at Eastman Chemical Company’s Kingsport, Tennessee coal gasification facility.

(source: Eastman/RTI)

The project team performed preliminary techno-economic assessment of RTI’s WGCU technology for IGCC application, and found that WGCU compared favorably against conventional acid gas removal (AGR) technology; WGCU plants were about 5% less expensive to build and reduced the cost of electricity produced by 5-10%. 

 Syngas Cleanup and Conditioning

Raw synthesis gas (syngas) from the high temperature high temperature gas cooling (HTGC) system needs to be cleaned to remove contaminants including fine particulates, sulfur, ammonia, chlorides, mercury, and other trace heavy metals to meet environmental emission regulations, as well as to protect downstream processes.  In the case of carbon sequestration, carbon dioxide (CO2) is also removed.  Depending on the application, syngas may need to be conditioned to adjust the hydrogen-to-carbon monoxide (H2-to-CO) ratio to meet downstream process requirement.  In applications where very low sulfur (<10 ppmv) syngas is required, converting carbonyl sulfide (COS) to hydrogen sulfide (H2S) before sulfur removal may also be needed. Typical cleanup and conditioning processes include cyclone and filters for bulk particulates removal; wet scrubbing to remove fine particulates, ammonia and chlorides; solid absorbents for mercury and trace heavy metal removal; water gas shift (WGS) for H2-to-CO ratio adjustment; catalytic hydrolysis for converting COS to H2S; and acid gas removal (AGR) (acid gas removal) for extracting sulfur-bearing gases and CO2 removal.

Fine Particulate Removal

Raw syngas leaving the HTGC system in today’s commercial gasification plant is normally quenched and scrubbed with water in a trayed column for fine char and ash particulate removal prior to recycle to the slurry-fed gasifiers.  For dry feed gasification, cyclones and candle filters are used to recover most of the fine particulate for recycle to the gasifiers before final cleanup with water quenching and scrubbing.  In addition, fine particulates, chlorides, ammonia, some H2S, and other trace contaminants are also removed from the syngas during the scrubbing process.  The scrubbed gas is then either reheated for COS hydrolysis and/or a sour WGS when required, or cooled in the low temperature gas cooling (LTGC) system by generating low pressure steam, preheating boiler feed water, and heat exchanged with cooling water before further processing.    

Spent water from the scrubber column is directed to the sour water treatment system, where it is depressurized and decanted in a gravity settler to remove fine particulates.  Solid-concentrated underflows from the settler bottom are filtered to recover the fine particulate as the filter cake, which is then either discarded or recycled to the gasifier depending on its carbon content.  Water from the settler is recycled for gasification uses with the excess being sent to the wastewater treatment system for disposal.

COS Hydrolysis and Water-Gas-Shift

Most of the sulfur in the coal is converted to H2S during gasification.  Depending on the gasification temperature and moisture content, approximately 3 to 10% of the sulfur is converted to COS.  To generate low sulfur syngas, the COS in the product gas needs to be converted to H2S before sulfur removal via current commercial AGR processes.  This is done by passing syngas from the water scrubber through a catalytic hydrolysis reactor where over 99% of the COS is converted to H2S.  The scrubbed syngas feed is normally re-heated to 30 to 50 °F above saturation to avoid catalyst damage by liquid water. 

In applications where a high syngas H2-to-CO ratio is needed, syngas from the water scrubber is passed through a multi-stage reactor containing sulfur-tolerant shift catalysts to convert CO and water into additional H2 and CO2.  Normally, excess moisture is present in the scrubber syngas from slurry-fed gasifiers to drive the shift reaction to achieve the required H2-to-CO ratio.  For most slurry-fed gasification systems, a portion of the syngas feed may need to be bypassed around the sour shift reactor to avoid exceeding the required product H2-to-CO ratio.  Depending on the gasification process and the required H2-to-CO ratio, additional steam injection before the sour shift may be needed for dry-fed gasifiers. The scrubber syngas feed is normally re-heated to 30 to 50 °F above saturation to avoid catalyst damage by liquid water.  Shifted syngas is cooled in the LTGC system by generating low pressure steam, preheating boiler feed water, and heat exchanging it against cooling water before going through the AGR system for sulfur removal.

Mercury and Trace Elements

Current commercial practice is to pass cooled syngas from LTGC through sulfided, activated carbon beds to remove over 90% of the mercury and a significant amount of other heavy metal contaminants.  Due to the sulfur in the activated carbon, these beds are normally placed ahead of the AGR system to minimize the possibility of sulfur slipping back into and contaminating the cleaned syngas.

Acid Gas Removal (AGR)

Raw syngas exiting the particulate removal and gas conditioning systems, typically near ambient temperature at 100°F, is routed to the AGR system where H2S and CO2 are removed from the syngas using either physical or chemical solvent absorption. For chemical synthesis applications which require syngas with less than 1 ppmv sulfur, physical solvent processes such as Rectisol and Selexol are normally used.  For power generation applications, which allow higher sulfur levels (approximately 10 to 30 ppmv sulfur), chemical solvent processes such as Methyl diethanolamine (MDEA) and Sulfinol are normally used.  The physical solvent absorption processes operate under cryogenic temperatures while the chemical solvent absorption processes operate slightly above ambient temperature.  

In both physical and chemical absorption processes, the syngas is washed with lean solvent in the absorber to remove H2S.  Cleaned syngas from the AGR is sent to downstream systems for further processing.  Rich solvent leaving the bottom of the absorber is sent to the regenerator, where the solvent is stripped with steam under low pressure to remove the absorbed sulfur.  The concentrated acid gas stream exits the top of the stripper and is sent to the Sulfur Recovery Unit (SRU) for sulfur recovery.  The regenerated lean solvent from the bottom of the stripper is

cooled by a heat exchanger against the rich solvent, followed by water cooling before being sent back to the absorber to start the absorption process again.   The physical solvent processes tend to co-absorb more CO2 than MDEA.  Multiple step depressurization of the rich solvent, supplemented with nitrogen stripping, is employed by the physical solvent processes to reject sufficient CO2 to concentrate the acid gas from the regenerator overhead to at least 15 to 25 Vol% H2S  in order to feed the Claus SRU.

Because of the need for refrigeration, as well as more complex solution flashing arrangements, physical solvent processes are two to four times more costly than MDEA-based chemical solvent processes.  While the physical solvent processes have higher power consumption than the chemical solvent processes, the chemical processes have higher steam consumption which translates to reduced power output from the power train.  Thus overall net power output may be similar between the two types of AGR processes.

Methanation

Synthetic natural gas (SNG) can be produced from coal-derived syngas, via a methanation reaction, as outlined in the page on Coal-to-SNG and H2. With the recent escalation in the price of natural gas, there have been tremendous interests in developing commercial scale coal-to-SNG projects, both in the U.S. and abroad. Coal-to-SNG technology is commercially available. The Great Plains Gasification Plant in Beulah, North Dakota is a coal-to-SNG facility producing 160 million cubic feet per day of SNG, and has been in operation since 1984. The plant uses Lurgi dry-ash gasifiers and a conventional methanation process for SNG synthesis. Advanced entrained-flow gasifers are of more interest in recent designs. New gasification technologies are also being developed, specifically for coal-to-SNG production, which also involves methanation chemistry. Examples include hydrogasification and catalytic gasification.

Methanation Chemistry

Conventional SNG production is based on a methanation process, which converts carbon oxides and hydrogen in syngas to methane and water by the following reactions:

CO + 3 H2 → CH4 + H2O ΔH = -210 kJ/molCO2 + 4 H2 → CH4 + 2 H2O ΔH = -113.6 kJ/mol

The reactions take place over nickel catalysts in fixed-bed reactors. The reactions are highly exothermic, thus a key challenge for the process is to manage the heat of reaction, and designing a catalyst system that can maintain its activity after prolonged exposure to high temperatures. The methanation process has been used extensively in commercial ammonia plants, where it is the final syngas purification step in which small residual concentrations of carbon monoxide (CO) and carbon dioxide (CO2) are removed catalytically by reacting with hydrogen. Effective sulfur removal is also necessary prior to methanation, since sulfur in the syngas will poison the methanation catalysts.

Methanation Reactor Configuration

Many different types of reactor design have been studied in the past, with emphasis on controlling the adiabatic reaction temperature rise. Methanation in coal gasification to SNG processes presents a considerable challenge in that the CO concentration in coal-derived syngas is much higher than that of an ammonia plant syngas. As a result, a much higher temperature rise in the reactor is expected. If not controlled properly, the temperature rise could be high enough to cause catalyst sintering and decomposition of the product methane to carbon. Novel reactor designs and configurations are used to circumvent this problem. In many

ways, this development is similar to that in syngas-based exothermic catalytic synthesis of methanol, as well as Fischer-Tropsch liquid (FTL) production.

Examples of three different types of methanation reactor configuration/design include:

← Equilibrium-limited fixed bed reactors in series - where the bulk of the conversion is carried out in multiple reactors arranged in a series/parallel configuration (Bulk Methanation). Fresh syngas feed can be split between each reactor. Sufficiently cooled equilibrium discharge from the last reactor is compressed and recycled to mix with fresh feed to the 1st reactor to limit the 1st reactor’s temperature rise. Equilibrium discharge from the 1st reactor is cooled and mixed with fresh feed to the 2nd reactor to limit the 2nd reactor’s temperature rise. This procedure is continued to the 3rd and subsequent bulk methanation reactors. Net discharge from the last bulk methanation reactor, after recycle extraction, is further cooled to condense out the water generated from bulk methanation before being sent to a final adiabatic cleanup reactor to complete the conversion. This design is similar to that being used/proposed in current coal-to-SNG designs of Lurgi and Haldor Topsoe.

← Throughwall-cooled fixed bed reactor - where the conversion is carried out isothermally in multiple parallel catalyst-packed tubes encased in a vessel shell (similar to a vertical shell-and-tube exchanger arrangement) filled with water. Reaction heat is removed by generating steam in the shell side. This design is similar to that being investigated by Lurgi for isothermal methanol synthesis. Currently, this type of methanation reactor is not in commercial practice.

← Slurry bubble reactor - in which the conversion is carried out by bubbling fresh feed through an oil/catalyst slurry filled reactor. Reaction heat is removed by generating steam in the internal tubular boiler. This design is similar to that being used in Air Products and Chemical’s LPMEOH™ methanol synthesis process, and that being used in SASOL’s FT synthesis process.

Methanation is a commercially proven technology. Current technology is primary based on fixed-bed reactors operating in series. Technology vendors include Lurgi, Haldor Topsoe, and others.

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