Non-gasification Uses of Coal

Non-gasification Uses of Coal

CHAPTER 2 Non-gasification Uses of Coal Contents Home Heating and Cooking vs. Industrial Use Coal Combustion Pollutants Pulverized Coal Combustion Su...

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Non-gasification Uses of Coal Contents Home Heating and Cooking vs. Industrial Use Coal Combustion Pollutants Pulverized Coal Combustion Supercritical Pulverized Coal Combustion Carbon Capture with Pulverized Coal Combustion Plants Oxy-combustion Sargas Coal-to-liquids ENCOAL Direct Hydrogenation of Coal References

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HOME HEATING AND COOKING VS. INDUSTRIAL USE The simplest use of coal is to burn it for heat. Coal was once used as a household heating and cooking fuel in Western nations; but it was largely replaced by natural gas, propane, electricity and fuel oil. Coal is still used for household heating and cooking in China, where it is a major source of air pollution. In Western nations, coal is used primarily as a fuel for large industrial boilers, especially for electric power generation. Large users are able to get more complete combustion, which reduces odor and soot, and are able to install complex and expensive air pollution equipment. Since pollution control equipment strongly influences the configuration of a modern coal-burning plant, emissions from coal combustion will be described next.

COAL COMBUSTION POLLUTANTS The US Environmental Protection Agency developed a list of priority pollutants, which are common air pollutants that are primarily generated by combustion. The following is a partial list of these pollutants. SOx consists primarily of SO2 but may also contain small amounts of SO3. In the atmosphere, SO2 oxidizes to SO3. This combines with water to form sulfuric acid, H2SO4, the primary acid component in acid rain. Combustion of sulfur-containing fuels creates SOx, and coal typically has high sulfur levels compared to other fossil fuels. Coal Gasification and Its Applications. ISBN B978-0-8155-2049-8.10002-6, doi:10.1016/B978-0-8155-2049-8.10002-6

Ó 2011 Elsevier Inc. All rights reserved.

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NOx consists of several nitrogen-oxygen compounds that contribute to photochemical smog, ozone depletion and global warming. There are two primary sources of NOx. Fuel NOx forms when nitrogen-containing fuel is burned. Not all nitrogen in the fuel forms NOx. Some of the fuel nitrogen may be converted to N2. Thermal NOx is created by direct combination of N2 and O2 in a flame. Thermal NOx is favored by high flame temperatures and high oxygen concentrations. At ambient conditions, NOx is not thermodynamically stable; but it is very difficult to decompose once formed. CO is formed when carbon-containing fuels are burned. In a flame, carbon is burned to form CO; which is then further oxidized, at a slower reaction rate, to CO2. In nearly all combustion processes, some of the intermediate product, CO, escapes into the flue gas. Carbon monoxide emissions are favored by low oxygen/fuel ratios. Particulates are divided into two categories, PM10, which consists of particles less than 10 microns in diameter; and PM2.5, a subset of PM10 which consists of particles less than 2.5 microns in diameter. When inhaled, these particles, especially PM2.5, tend to remain in the lungs. This can lead to chronic health conditions such as black lung in coal miners, silicosis in people who have prolonged exposure to dust and smoker’s lungs. Some dust is generated when coal is mined, crushed, and shipped. When coal is used for home heating and cooking, the flue gas can contain significant quantities of soot, which is a fine carbon-rich dust. In industrial boilers, combustion is more complete and little soot is produced. Particulate emissions are primarily due to fly ash, which are the fine ash particles entrained in the flue gas. Volatile organic compounds, VOCs, are nearly all organic compounds that have a significant vapor pressure at ambient conditions. In home heating and cooking applications, VOCs in the flue gas cause disagreeable odors. Since combustion is more complete in industrial boilers, little odor is produced. VOCs are a major issue in organic chemical plants, including coal-to-chemical and coal-to-liquid fuels plants. Air toxics include a long list of specific toxic compounds. Coal contains small quantities of volatile heavy metals; which vaporize during combustion and may leave with the flue gas. Mercury1 has received the most attention. Mercury is a neurotoxin, and tends to accumulate in aquatic systems. Mercury bio-accumulates, meaning that large fish that eat smaller mercury-containing fish do not excrete the mercury. Consequently, mercury concentrations are highest at the top of the food chain, including large fish and the people who eat them. The US Environmental Protection Agency issued the first Clean Air Mercury Rule in 2005. Greenhouse gasses include CO2, CH4, and NOx compounds. Because of the large volume emitted, CO2 has received the most attention. Most members of the scientific community believe that global warming is largely due to greenhouse gasses released by fossil fuel combustion. Since coal has lower H/C ratios than other fossil fuels, coal combustion releases more CO2 per unit of energy than other fossil fuels.

Non-gasification Uses of Coal

PULVERIZED COAL COMBUSTION The most common type of coal-fired power plant is pulverized coal combustion (PCC), shown in Figure 2.1. A mixture of pulverized coal and air is blown into a low NOx burner. This burner has an annular arrangement. Coal and a portion of the air are fed to the center tube. The remainder of the air is fed through the space between the inside and outside tubes. The main portion of the flame has a low oxygen/fuel ratio and a relatively low temperature, both of which inhibit formation of NOx. The additional air oxidizes CO to CO2. A low NOx burner reduces NOx emissions from about 11 kg to about 5.5 kg per ton of sub-bituminous coal.2 The walls of the furnace have a water wall construction, meaning that side-by-side tubes are welded together to form a continuous wall. Hot combustion gas first rises through the boiler section where pressurized water is boiled to make steam. Next comes the superheater section, where the steam temperature is raised above its boiling point. Then the economizer section preheats the boiler feed water. Finally there is a rotating plate exchanger. Iron plates rotate into the path of the warm flue gas. The warm plates then rotate out of the flue gas path and into the air path, where the plates preheat combustion air. Flue gas then enters the selective catalytic reactor (SCR). Ammonia is injected into the SCR where it reacts with NOx (here shown as NO) to form N2 and H2O. This eliminates 75 to 85% of the NOx.

Superheater section

Economizer section

Boiler section

Air flue gas

Low NOx burner Rotating plate exchanger

Coal + air

Preheated air

air

Bottom ash

Figure 2.1 Pulverized coal combustion plant.

Flue gas to SCR

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6NO þ 4NH3 /5N2 þ 6H2 O

R-2.1

The flue gas then enters the bag-house, which removes fly ash. The flue gas is forced to flow through a bag filter that captures the fly ash. Some power plants use an electrostatic precipitator in place of a bag-house. In this process the flue gas flows between two electrified parallel plates. These plates attract the fly ash to the surface of the plates where it is held through the electro-static force. The de-ashed flue gas flows on through the plates. A flue gas desulfurization unit (FGD) uses a wet or dry limestone (CaCO3) stream to convert SO2 to gypsum (CaSO4$2H2O), which is land-filled. SO2 ðgÞ þ CaCO3 ðsÞ/CaSO3 ðsÞ þ CO2 ðgÞ

R-2.2

2CaSO3 ðsÞ þ O2 ðgÞ þ 4H2 OðlÞ/2CaSO4$2H2 OðsÞ

R-2.3

At the time this was written, there was no standard method for mercury control. Control techniques under consideration include flotation of the coal to remove mineral matter and injection of activated carbon into the flue gas ahead of the bag-house. Mercury in the flue gas can be in either oxidized or un-oxidized form. Halide salts have been used to converted un-oxidized mercury to mercuric halides, which are more readily removed in the bag-house or FGD. The Western Research Institute has also patented a process where mercury is removed by preheating the coal to a particular temperature prior to combustion.

SUPERCRITICAL PULVERIZED COAL COMBUSTION In a simplistic thermodynamic analysis, a pulverized coal combustion plant may be viewed as a classic heat engine, shown in Figure 2.2. Although a real PCC unit is much more complex than what is shown here, this simplistic picture can be used to illustrate a trend. The theoretical maximum efficiency, hmax, is given by the Carnot cycle: hmax ¼ Heat in

Steam turbine

Heat out

TH  TC TC ¼ 1 TH TH

TH = temperature of steam from boiler

work

electricity

TC = temperature of cooling water

Figure 2.2 Pulverized coal combustion plant as a classic heat engine.

Eqn. 2.1

Non-gasification Uses of Coal

In theory, one may increase the efficiency by increasing TH or decreasing TC. Most power plants use cooling water from an evaporative cooling tower. Smaller numbers of power plants use cooling water on a once-through basis or use air cooling. The temperature of the water or air used to cool the power plant effectively sets TC. This means that to increase efficiency TH must be increased. The maximum steam temperature and pressure is set by the steam tube materials of construction. Metal strengths fall with increasing temperature, therefore these tubes must resist the corrosive environment in the furnace. Steam tube metallurgy is an active research area. The latest steam tubes allow operation above the critical pressure of water, as shown in Table 2.1. Table 2.1 Steam conditions and efficiency for subcritical and supercritical pulverized coal combustion.3 Subcritical pulverized Supercritical pulverized Water critical coal combustion coal combustion point

Boiler pressure, MPa Boiler temperature,  C HHV efficiency,%

16.5 566 36.8

24.1 593 39.1

21.94 374

The higher efficiency of the supercritical plant means that less coal is needed to produce the same amount of power. This also reduces the corresponding emissions. This is a small but significant effect.

CARBON CAPTURE WITH PULVERIZED COAL COMBUSTION PLANTS The clean coal concept generally refers to a power plant that burns coal, or a coal-derived fuel such as the syngas produced by a coal gasifier. It then separates the CO2 and sequesters it to prevent emission of CO2 to the atmosphere. Sequestration can take a variety of forms, but the most common approach is to compress CO2 and store it underground. In a pulverized coal combustion plant, the following three steps are required: 1. Separate CO2 from flue gas. 2. Compress CO2, typically to about 15 MPa. 3. Inject CO2 into a porous geologic formation. To illustrate the difficulty of step 1, consider a perfect membrane illustrated in Figure 2.3. This hypothetical membrane has perfect selectivity for CO2 and offers no resistance for CO2 transport. Since the membrane offers no resistance for CO2 transport, the CO2 partial pressure is the same on both sides of the membrane: PCO21 ¼ PCO22

Eqn. 2.2

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membrane

PCO2-1

PCO2-2

CO2 flue gas

Figure 2.3 Hypothetical perfect membrane for CO2 separation from flue gas.

If the flue gas is at standard atmospheric pressure, 101 kPa and the flue gas contains 13% CO2; then CO2 separation will not begin until the pressure on the CO2 side drops below 13 kPa. Removal of 90% of the CO2 requires a 1.3 kPa CO2 pressure and 99% removal requires a 0.13 kPa CO2 pressure. Even a perfect membrane would require large and expensive vacuum pumps to separate CO2 from the flue gas. Real membranes with less than perfect selectivities and significant transport resistance would be more costly. The usual approach to CO2 removal is to use a liquid absorbent or a solid adsorbent that has an affinity for CO2. This allows the CO2 to be removed at atmospheric pressure. A weak bond is formed between the CO2 and the liquid or solid. This bond is then broken, usually by heating. This will regenerate the absorbent or adsorbent and free the CO2. A strong bond between CO2 and the liquid or solid leads to fast and nearly complete removal of CO2 from flue gas. This strong bond requires a large amount of energy to break; so selection of the absorbent or adsorbent is a compromise between effective CO2 removal and ease of regeneration. Aqueous amine solutions have long been used for removal of CO2 and other acid gasses, such as SO2 and H2S, from gas streams. One of the more common commercial amines is mono-ethanol-amine (MEA), shown in Figure 2.4. HH N-C-C-O-H H HH

H

Figure 2.4 Mono-ethanol-amine (MEA), an absorbent used for CO2 removal.

Figure 2.5 shows a simplified process for the removal of CO2 from power plant flue gas. The warm flue gas is cooled by water evaporation in a direct contact cooler. An aqueous solution of MEA is then used to absorb CO2 from the flue gas. A water wash section above the MEA absorption section removes traces of MEA from the flue gas. The CO2-loaded MEA solution is then sent to a stripper, where CO2 is boiled off the MEA solution. The regenerated MEA solution is cooled and sent to the absorber. The CO2 is compressed and sequestered. Woods et al.3 compared designs for a subcritical pulverized coal combustion power plant with and without carbon capture and sequestration (CCS). For both cases, the feed

Non-gasification Uses of Coal

CO2 to compression

CO2-free flue gas to atmosphere

condenser water MEA solution

water

cooler

Stripper

Absorber

water

CO2 – loaded solution

Direct Contact Cooler

reboiler

flue gas water recycle

Figure 2.5 Mono-ethanol-amine (MEA) based process for CO2 removal from flue gas.

was an Illinois No. 6 bituminous coal. The CCS case used an MEA process similar to that shown in Figure 2.5. Table 2.2 shows a comparison of estimated costs and efficiencies for these two plant designs. The carbon capture and sequestration system requires considerable energy, especially for the stripper reboiler heat and for the CO2 compressors. This lowers the net HHV efficiency from 36.8% to 24.9%. This study assumed that new power plants would be Table 2.2 A comparison of the costs and efficiencies for a subcritical pulverized coal combustion power plant with and without carbon capture and sequestration (CCS).3 Without CCS With CCS

Net power output, MW Coal feed rate, t/hr Efficiency, HHV Plant cost, million $ Cost of electricity, cents/kw-hr Cost of CO2 emissions avoided, $/ton

550 219 36.8% 853 6.4

550 323 24.9% 1,591 11.9 68

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built, as opposed to modifying an existing power plant. This increases the coal feed rate for the CCS case was from 219 to 323 t/hr, a 47% increase, in order to maintain 550 MW of net output power. If a CCS system were added to an existing power plant, then the net power output would be reduced to about 68% of its former level. Widespread retrofitting of existing power plants would require substantial construction of new power plants to maintain power production levels. Adding a CCS system nearly doubles both the plant cost and the cost of electricity. Katzer et al.4 reviewed the CCS literature and concluded that adding CCS to coal-fired power production would about double the cost of electric power production. Distribution costs would not change, so CCS would increase residential power costs by about 50%. The enormous investment cost and steep electric power cost predicted for PCC with CCS prompted intense research into alternative CO2 absorbents and adsorbents. If a new power plant is to be built, then PCC with CCS is not the most economical approach to producing electricity with low CO2 emissions. The large number of existing power plants, however, provides a powerful incentive for adapting PCC technology. Alternative clean coal power production technologies are also being investigated. For example, much of the current interest in coal gasification is due to the predicted cost of electric power for coal-based integrated gasification combined cycle (IGCC) plant with CCS is substantially lower than PCC with CCS. Woods et al.3 studied IGCC with CCS using three different gasifiers. The concluded that electric power could be made for 10.3 cents/kw-hr. This is a substantial increase over PCC without CCS, but less than PCC with CCS. The high cost of clean coal technology has raised interest in power production technologies that produce less CO2.

OXY-COMBUSTION In simplistic terms, removal of CO2 from flue gas may be regarded as a CO2/N2 separation. The need for this separation may be eliminated if the furnace is fed oxygen instead of air. This is the basic concept of oxy-combustion. Figure 2.6 shows a simplified version of an oxy-combustion plant designed by Haslbeck et al.5 Oxygen is produced by an air separation unit (ASU). Typically, this is a cryogenic air distillation process; but other air separation techniques, such as pressure swing adsorption, have also been used. The oxygen purity from the cryogenic distillation unit is 95%. The impurities are argon, 3.4% and nitrogen, 1.6%. Flames fed nearly pure oxygen are much hotter than flames fed air. The materials of construction in the furnace cannot withstand these higher temperatures. Consequently, CO2-rich flue gas is recycled to the furnace to give an oxygen partial pressure that is comparable to air. Flue gas leaving the flue gas desulfurization unit is nearly saturated with water. So the flue gas is reheated slightly to avoid water droplets in the recycled flue gas.

Non-gasification Uses of Coal

N2

Air

Air Separation Unit

Limestone, Water

O2 Coal

Pulverized Coal Combustion

Flue Gas Desulfurization

Ash

Gypsum

Flue Gas Recycle

Reheat Fan

Vent gas Cool Flash

Drier Compressor Water Pump Flue gas to sequestration

Figure 2.6 Oxy-combustion power plant based on the design by Haslbeck et al.5

A portion of the flue gas is withdrawn, compressed and then dried using a temperature swing adsorption unit. The flue gas is rich in CO2, but contains significant quantities of other gasses. This entire stream may be compressed and sequestered. Alternatively, the gas may be purified by cooling the gas and then separating liquid CO2 from a vent gas that contains most of the impurities. Table 2.3 shows the stream compositions when the purification process is used. The combined weight percent of the vent gas and the sequestered gas is less than 100% due to the small quantity of water removed from the moist flue gas. Note that the vent gas contains CO2 and SO2. These emissions can be eliminated if the purification process is removed. The need for CO2 purification depends on the gas specification limits required for sequestration.

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Fogash and White6 studied a process that would further purify the sequestered CO2 and reduce the release of pollutants in the vent gas. They used multistage flue gas compression combined with interstage cooling and condensation of water. Most of the NOx in the flue gas consists of NO. The conditions of the compression train favor the oxidation of NO to NO2. Given sufficient residence time, NO2 reacts with SO2 to form SO3 this in turn, reacts with water to form sulfuric acid (H2SO4). The NO2 also reacts with water to form nitric acid (HNO3), and mercury reacts with nitric acid to form mercuric nitrate. Consequently, the bulk of the SO2, NOx and mercury in the flue gas leaves with the condensed water. The values shown in Table 2.3 are data from Haslbeck et al. for a supercritical pulverized coal combustion unit fed Illinois No. 6 bituminous coal. Haslbeck et al. noted that the flue gas desulfurization unit could be eliminated and that SO2 could be co-sequestered with CO2. This would substantially reduce capital and operating costs. They kept the flue gas desulfurization unit in their design because, without it, the recycled flue gas would increase the SO2 concentration to 3.4 to 3.5 times as high as the same unit without a flue gas recycle. With a high sulfur coal like Illinois No. 6, this would cause corrosion problems in the boiler. Haslbeck et al. suggested eliminating the flue gas desulfurization unit when a low sulfur coal, such as Powder River Basin coal, is used. Table 2.4, also using data from Haslbeck et al., compares the cost and efficiency of a pulverized coal combustion plant with and without oxy-combustion. The addition of an oxy-combustion system substantially lowers the efficiency and increases the cost of electric power production. Comparing the values in Table 2.4 and Table 2.2, we see that, compared to carbon capture and sequestration using amine absorption, oxy-combustion is a more efficient and less costly means of capturing and sequestering CO2. For a greenfield plant, the cost of power from an oxy-combustion plant is comparable to an IGCC plant. Oxy-combustion, unlike IGCC, can be retrofitted to an existing pulverized coal combustion plant. Table 2.3 Flue gas compositions when CO2 is purified by liquefaction.5 Component, % Moist flue gas Vent gas

Sequestered gas

Ar CO2 H2O N2 O2 SO2 Wt.% of flue gas Temp.,  C Press., MPa

0 95.85 0.01 1.46 2.67 0.01 80.87 21 15.17

3.66 83.40 0.21 9.81 2.92 0.01 100 104 3.35

19.31 31.10 0 45.56 4.01 0.01 18.94 9 3.21

Non-gasification Uses of Coal

Table 2.4 A comparison of the costs and efficiencies for a supercritical pulverized coal combustion power plant with and without oxycombustion.5 The oxy-combustion case does not use CO2 purification. Without oxy-combustion With oxy-combustion

Net power output, MW Coal feed rate, t/hr Efficiency, HHV Plant cost, million $ Cost of electricity, cents/kw-hr Cost of CO2 emissions avoided, $/ton

550 185 39.4% 868 6.32

550 249 29.6% 1,263 10.07 43

SARGAS Figure 2.3 illustrates that part of the difficulty in separating CO2 from flue gas is due to its low partial pressure. As will be shown later, one of the attractive features of IGCC is that CO2 is separated from a high pressure gas stream, with a higher CO2 partial pressure. A similar approach is used by the Sargas process,7,8 in which CO2 is separated from flue gas from a pressurized combustion process. A Sargas demonstration plant was installed at the Va¨rtan combined heat and power plant in Stockholm, Sweden. This plant uses a pressurized fluidized bed combustor (ABB Carbon P200 PFBC cycle). As shown in Figure 2.7, air is fed to a compressor/turbine on a common shaft. Air is compressed to about 1.3 MPa, and fed to the pressurized fluidized bed combustor. Coal is fed to the combustor as a coal/water slurry. Limestone fed to the combustor reduces SO2 emissions. The low bed combustion temperature, typically 850e880  C, reduces NOx emissions. A hydro-cyclone is used to remove fly ash from the flue gas. The flue gas then is cooled in a heat exchanger, and fed to a Benfield process9e11 to separate CO2. This process is similar to the MEA process shown in Figure 2.5, with potassium carbonate (K2CO3) used instead of MEA. The Benfield process, as marketed by UOP,11 also uses a proprietary soluble catalyst and a corrosion inhibitor. An advantage of the Benfield process is that, unlike amines, the inorganic chemicals used in the process do not degrade in the presence of oxygen. Flue gas is initially contacted with water to remove residual dust, NO2, and partially remove SO2. The gas then contacts the K2CO3 solution, where CO2 absorbs and reacts to form potassium bicarbonate (KHCO3). The bicarbonate solution is heated in a stripping column to decompose the bicarbonate, releasing CO2 and regenerating K2CO3. The CO2-free flue gas is used to cool the flue gas fed to the Benfield process. This also reheats the flue gas, which is then fed to the turbine side of the compressor/turbine set. Warm, low pressure flue gas leaving the turbine is used to preheat boiler feed water before it is vented to the stack. The flue gas turbine produces about 20% of the power generated by the plant. The other 80% is generated by the steam turbine.

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Stack

CO2

Benfield process Flue gas

Steam

Pressurized fluidized bed combustion

Coal/ limestone slurry

Fly ash

CO2-free flue gas

Boiler feed water

Air

Compressor

Turbine

Generator

Figure 2.7 The Sargas process combines a pressurized fluidized bed combustion process with a postcombustion CO2 removal process, here shown as the Benfield process.

COAL-TO-LIQUIDS The production of liquid fuels from coal is expected to be a major application of coal gasification. The following is a brief description of coal-to-liquid processes that do not rely on gasification.

ENCOAL Coking is the oldest form of processing coal, other than simply burning it. Coal is heated in the absence of oxygen to produce solid coke, liquid coal tar, and a flammable gas. Coal tar was a major source of liquid fuel and chemical feedstock until petroleum became abundant in the 1950s and 1960s. The ENCOAL process12 is a mild coking process that was demonstrated in a 1000 ton per day plant near Gillette, Wyoming, in the 1990s. An updated version of this process is marketed by ConvertCoal.13 A goal of this process is to upgrade PRB subbituminous coal to a solid fuel product called Process-Derived Fuel (PDF); which has an

Non-gasification Uses of Coal

HHV value comparable to bituminous coals from the eastern USA. Skov et al.14 show that the heating value of a Powder River Basin sub-bituminous coal can be increased from about 19.6 MJ/kg (8,400 Btu/lb) to about 26.4 MJ/kg (11,200 Btu/lb). This increase is primarily due to the removal of water from the coal, which is about 30 wt.% of the feed coal (see Equation 1.1). Only about 60% of the volatiles were removed during pyrolysis, so the PDF has ignition characteristics that are similar to bituminous coal. Drying and pyrolysis also remove much of the sulfur and mercury from the coal. The process also yields Coal Derived Liquid, which has characteristics similar to a No. 6 petroleum heating oil. This is a heavy oil that is used in industrial boilers. The gas produced by the process was burned to provide heat for coking. Run-of-mine coal is crushed and then screened to 2  1/8 inch. The coal is then dried and pyrolyzed at 538  C (1,000  F). The gasses are cooled to condense the CDL product, and the cooling temperature is just high enough to prevent the condensation of water. There have been numerous attempts to increase the heating value of PRB by drying it or, as in the case of ENCOAL, by mild pyrolysis. A recurring problem with these upgrading processes is that dried PRB tends to reabsorb moisture. Another problem is that dried PRB is prone to low temperature oxidation, which can lead to spontaneous combustion. As can be seen in Figure 1.2, when dried coal is exposed to oxygen, the tendency to oxidize upon further exposure to oxygen is reduced. The ENCOAL plant sought to reduce the tendency of PDF to spontaneously ignite by exposing the material to oxygen in a controlled fashion. Pyrolyzed solids were quenched, and then sent to a vibrating fluidized bed. There they were exposed to a gas with a controlled concentration of oxygen. This treatment was found to be insufficient, so PDF was further deactivated by spreading PDF on the ground in 30 cm (12 in) thick layers. This exposed the PDF to oxygen at ambient conditions. Each ton of PRB coal yielded about 1 ton of PDF and 1 barrel of CDL. Skov et al.15 gave a detailed analysis of the CDL. The specific gravity of this liquid is 1.06 (2 API gravity), so 1 barrel of CDL per ton corresponds to a 9 wt.% yield of CDL. This yield will vary with feed coal and pyrolysis conditions. Pyrolysis processes are attractive because of their simplicity, but liquid yields are typically low. The CDL was sold as a No. 6 heating oil replacement. This is a low grade petroleum product with a shrinking market. Consumers of No. 6 heating oil are switching to natural gas or coal. Petroleum refiners have made considerable investments to convert heavy oils to lighter, and more valuable, transportation fuels. CDL can be upgraded to produce more valuable liquids. The primary difference between CDL and petroleum products is that the CDL contains high levels15 of oxygen (12.5 wt.%), nitrogen (0.9 wt.%), and sulfur (0.2 wt.%); which are collectively known as heteroatoms in the petroleum industry. In a typical petroleum liquid, the intermolecular

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forces between the hydrocarbon molecules are predominately weak dispersive, also known as van der Waals, forces. The hetero-atoms in coal tar introduce stronger polar, induced polar, and hydrogen bonding forces. Removal of the hetero-atoms by hydrogenation results in large reductions in boiling point, density, and viscosity. Only a few hydrogenation tests have been carried out with CDL.15

Direct Hydrogenation of Coal The goal of most coal-to-liquids processes is to convert coal to a liquid that resembles a petroleum product. Compared to petroleum, coal: • • • • •

is a solid has a higher molecular weight has a lower hydrogen/carbon ratio has higher concentrations of hetero-atoms: oxygen, sulfur and nitrogen contains ash.

Catalytic hydrogenation of coal can produce a petroleum-like product. Hydrogen is added to carbonecarbon double bonds and aromatic rings to produce carbonecarbon single bonds. Large molecules are split, or hydrocracked, to produce lower molecular weight compounds. Oxygen, sulfur, and nitrogen are removed as water, H2S, and NH3. Hydrocracking, plus the removal of polar hetero-atoms; converts solid coal into a liquid, with some byproduct gas. The ash can be filtered from the liquid. A thorough description of coal hydrogenation processes would fill several books. Included below is a brief overview of the hydrogenation process. The Bergius process was used in Germany during World War II to produce liquid fuels from coal. Several related processes were intensively developed during the 1970s and early 1980s, but development halted when the price of crude oil dropped during the mid 1980s. The Shenhua16 direct liquefaction plant in China started operations in 2009. Coal hydrogenation catalysts are closely related to petroleum hydrogenation catalysts. For petroleum, the catalyst is typically a sulfided bimetallic catalyst on a porous ceramic base; generally Co/Mo, Ni/Mo, or Ni/W on a silica, alumina, or silica-alumina base. Since coal hydrogenation is a less mature technology, a wider range of catalysts have been used. In a porous, (solid) heterogeneous catalyst, fluid reactants diffuse into the pores, adsorb onto the surface, react, desorb, and then diffuse out of the pores. The obvious problem with coal hydrogenation is that coal is a solid, and cannot directly access the catalytic sites inside the catalyst pellet. This problem is solved using two mechanisms. The mechanism first is that the coal is slurried in a hot, heavy, highly aromatic recycle liquid. This partially dissolves the coal, and the dissolved coal molecules can contact the catalytic surfaces. Compared to petroleum hydrogenation catalysts, coal catalysts have large pores to accommodate the large coal molecules.

Non-gasification Uses of Coal

naphthalene 2 H2

catalyst pellet coal

tetrahydronaphthalene

Figure 2.8 The donor solvent mechanism in catalytic coal hydrogenation.

The second mechanism is the donor solvent process, shown in Figure 2.8. An aromatic compound in the liquid, shown here as naphthalene, is partially hydrogenated, saturating one of the aromatic rings. This hydrogenated molecule then reacts with the solid coal surface. Hydrogen from the saturated ring is transferred to the coal surface, which reforms the aromatic ring. Petroleum hydrogenation is typically done at 4 to 20 MPa with a large stoichiometric excess of hydrogen. A gas/liquid separator after the reactor recovers the catalyst addition

gas/liquid separator expanded catalyst level

oil recycle coal/oil slurry distributor plate hydrogen catalyst, ash withdrawl ebullating pump

Figure 2.9 Ebullating bed hydrogenation of coal.

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unconverted hydrogen, and this gas is compressed and recycled. A trickle bed reactor is used. Oil and hydrogen are fed to the top of a packed catalyst bed, and oil trickles through the catalyst. This type of reactor will not work when the feedstock contains solids, as it does during coal hydrogenation. Instead, an ebullating bed reactor (also called a slurry bubble bed), shown in Figure 2.9, is used. The catalyst pellets are fluidized by hydrogen and recycle oil. Since the catalyst is rapidly poisoned during coal hydrogenation, fresh catalyst need to be continuously added through the top of the reactor. Spent catalyst is withdrawn as a catalyst/ash/unreacted coal/oil slurry through the Recycle H2 Recycle compressor Makeup H2 Ebullating bed hydrotreater

Coal

Recycle solvent

Naphtha

Slurry tank Preheat Recycle H2

Distillate fuel oil Vacuum distillation

Recycle compressor

Liquids

Flexicoker

Coke to gasification

Trickle bed hydrotreater Preheat

Figure 2.10 Exxon Donor Solvent process for direct hydrogenation of coal to produce liquid fuels.

Non-gasification Uses of Coal

bottom of the reactor. Zhang17 measured the rate of deactivation of a Co/Mo on alumina catalyst in a laboratory reactor. Reaction rates declined to thermal, noncatalytic, levels after hydro-treating about 1,000 g of Powder River Basin coal per gram of catalyst. An examination of the spent catalyst showed that the pores were filled with coke, and a calcium carbonate shell coated the exterior of the catalyst pellets. Figure 2.10 shows the Exxon Donor Solvent process,18 one of several direct coal hydrogenation processes. Coal is slurried with a heavy recycle oil, mixed with hydrogen, preheated, and then fed to an ebullating bed hydrotreater. The oil product from the hydrotreater is distilled to yield naphtha (unfinished gasoline), distillate fuel oil (diesel and home heating oil), and a heavy recycle solvent. The vacuum distillation bottoms are coked to produce liquids and coke that can be fed to a gasifier to produce hydrogen. The recycle solvent is hydrotreated in a trickle bed hydrotreater before it is recycled to the slurry tank.

REFERENCES 1. www.epa.gov/mercury 2. www.epa.gov/ttn/chief/ap42/ch01/final/c01s01.pdf. 3. Woods MC, Capicotto PJ, Haslbeck JL, et al. Cost and performance baseline for fossil energy plants, volume 1: Bituminous coal and natural gas to electricity, DOE/NETL-2007/1281, ; 2007. 4. Katzer J, Ansolabehere S, Beer J, et al. The future of coal, options for a carbon-constrained world, an interdisciplinary MIT study 2007. 5. Haslbeck JL, Black J, Kuehn N, Lewis E, Rutkowski MD, Woods M, et al. Pulverized coal oxycombustion power plants. DOE/NETLd2007/1291 ; 2008. 6. Fogash K White V. Oxycoal combustion: opportunities and challengesdpurification of oxyfuelderived CO2. Am Inst Chem Engrs National Meeting, Salt Lake City, UT 2007. 7. Hetland J, Christensen T. Assessment of a fully integrated SARGAS process operating on coal with near zero emissions. Appl Thermal Engr 2008;vol. 28:2030-2038. 8. Bryngelsson M, Westermark M. CO2 capture pilot test at a pressurized coal fired CHP plant. Energy Procedia, 2009;vol. 1:1403-1410. 9. Benson HE, Field JH, Jimeson RM. CO2 absorption employing hot potassium carbonate solutions. Chem Engr Prog 1954;vol. 50:356-364. 10. Benson HE, Field JH, Hayes WP. Improved process for CO2 Absorption uses hot carbonate solutions. Chem Engr Prog 1956;vol. 52:433-438. 11. UOP. Gas processing: Benfield process, . 12. The ENCOAL mild gasification project, a DOE assessment DOE/NETL-2002/1171, ; 2002. 13. ConvertCoal, Inc., . 14. Skov ER, England DC, Henneforth JC, Rinker FG. Synthetic crude oil and coal-char production by mild-temperature pyrolysis processing of low-rank coals. Am Inst Chem Engr Spring Nat Meeting; April 22-26, 2007. 15. Skov ER, England DC, Rinker FG, Walty RJ. Coal-tar chemicals and synthetic crude oil production from low-rank coals using mild-temperature pyrolysis. Am Inst Chem Engr Spring Nat Meeting; April 22-26, 2007.

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16. China Shenhua, . 17. Zhang T. Development of a catalytic coal liquefaction microreactor and testing of novel supports for coal liquefaction catalysts. PhD. Dissertation, University of Wyoming; 1994. 18. Technology Status Report: Coal Liquefaction, Technology status report 010. United Kingdom: Dept. of Trade and Industry; 1999.