heat producing coal equipment

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Henan Dianyan New Energy Technology Co., Ltd. is a high-tech enterprise specializing in green energy, energy-saving technology development and related equipment manufacturing. The manufacturing plant is located at No. 19, Longjiang Road, Shangjie District, Zhengzhou City, covering an area of 20000. The company is developed on the basis of the former Kunming Dianyan New Energy Research Institute. After years of technical research, the new generation high-temperature pyrolysis technology of biomass ...

combustion equipment - an overview | sciencedirect topics

Combustion equipment, when first commissioned, can be set to operate at its optimum efficiency. With time, however, there will be a deterioration due to blockage of air filters and breather holes, wear in valve linkages, etc. Such changes may have safety implications if gas-rich firing is a consequence.

Regular checking of measured parameters and comparison with commissioning data will enable adjustments to be made to optimize efficiency. Replacement of items subject to wear, filters, etc. and items subject to thermal distortion such as some burner components will be necessary.

For combustion equipment operators, the most important performance metric is the readiness and reliability of the equipment to deliver the amount of heat needed for the processes. As much of the equipment is installed in urban areas, another significant consideration is to meet local air-quality rules which often are the most stringent because of their status as stationary sources. It is from these perspectives that the combustion properties of the biogases are being analyzed and discussed in this and the following subsection.

The analysis focuses on two fuel groups: gasified biomass and landfill/digester gases (highlighted in Table6.1) that would be available in many commercial and industrial settings. Because the fuel components for both groups vary over wide ranges, representative fuels are used so to limit the analysis to a manageable size. For syngases, the concentrations used in the analysis are 19%

Showed in Fig.6.11 are the fuel-loading maps for the two fuel groups. The key dependent parameter is the adiabatic flame temperature, Tad, expressed in terms of the equivalence ratio, , and the ratio of the respective fuel components CO/H2 and CO2/CH4. The Tad results were compiled from Chemkin calculations using the premixed flame modules and GRI 3.0 reaction mechanism. Also shown as colored background are the contours of bulk flow velocities, Uo, calculated for a hypothetical system with a burner of 10cm diameter with heat output of 200kW at standard atmospheric condition.

The fuel-loading maps are the lookup-table for setting when the fuel components change. The main goal is to maintain Tad in the combustion chamber at a constant value. This is necessary for NOx control and also for maintaining energy efficiency. For the representative sygases with fixed inert components, it can be seen that the Tad contours for Tad<2000K do not show strong dependency on CO/H2. The Uo contours in the background show Uo increasing with decreasing which is the consequence of the increases in air flow rate for lean burn. The Uo contours are mostly parallel to the Tad contours. The main implication from the syngas fuel-loading map is as follows. If a system is operating at a Tad below 2000K, when a change in the syngas composition occurs (within the range being considered in this study), the performance of the combustion system would not be affected significantly even if no adjustment is made to the burner settings. In contrast, Tad contours on biogas fuel-loading map are much more sensitive to CO2/CH4 while the corresponding Uo contours show the same features as those shown on the syngas fuel-loading map. Consequently, when the compositions of the biogas change, adjustment of the burner settings is necessary to maintain consistent performance of the combustion system.

The analysis on the combustion properties of syngases and biogases shows that the controls for fuel-flexible burners are highly dependent on the type of fuels being used. Fuel-loading maps calculated for various fuel groups are essential as the foundation for developing the fuel delivery and the control systems.

The design of combustion equipment, in the form of burners, for the hydrocarbon processing industry (HPI), the chemical processing industry, and to a major extent the power generation industry has critical restrictions on the shape, size, and consistency of the flame generated. All burners providing energy to a process will be restricted in flame qualities by the design of the chamber, or furnace, into which it is fired.

The furnace chamber and burner flame in every process furnace are designed to provide for the efficient transfer of heat to the process load. Flame size and shape for the HPI is especially critical due to the sensitivity to overheating of the hydrocarbons being processed. The rate of heat transfer to the process tubes must be limited to prevent overheating of the process tubes leading to the formation of carbon or coke inside the process tubes. As a result, there are generally strict guidelines for the flame dimensions. Typical specifications for flames include maximum flame lengths and widths. The number, heat release, and layout of the burners in the furnace are designed to provide the proper heat transfer pattern.

Patterning of the airflow through approach distribution, tile throat sizing and shape, and the tile exit configuration provides the most reliable method for flame pattern control. Introduction of the fuel into the established airflow streams provides the primary function in a raw gas burner. The proper flame pattern is generated by the combination of fuel injection pattern provided by the fuel injectors and the burner tile and flame holder which controls the airflow. The fuel injectors are also often called spuds or tips. The injectors have fuel injection ports that introduce the main portion of the fuel into the air stream in a manner that generates the desired flame pattern or shape. In conjunction, the air stream must be shaped in an appropriate manner by the airflow passages provided by the shape of the tile and flame holder. In many cases, the flame shape is round or brush shaped and acceptable in length and diameter. In this case, the burner tile is typically round and the fuel is injected symmetrically. Some furnaces require a fan-shaped flame, often termed a flat flame. In that case, the burner tile is generally rectangular and the fuel is injected in a manner producing a flame that is essentially rectangular or flat rather than round.

The following case studies are presented to highlight the use of biomass for heating in Sweden in small, medium, and large scale. High system efficiencies are obtained based on the use of heat in co-generation plants. In 2013, the number of biomass CHP units accumulated to 133 including some 42 industrial units. In addition, many units produce only heat on small and medium scales. Waste fuels will continue to be important in the future when challenges include higher steam data for co-generation. Finally, the transition to a bioeconomy provides new opportunities for highly resource-efficient energy combines.

Pellet burners were the first generation of combustion equipment developed for use of pellets at domestic scale (Table 11.2). Pellet burners were developed in Sweden to replace oil burners in existing oil or multifuel boilers. With the introduction of the Swedish carbon dioxide tax in 1991, the conversion from oil to pellets became very profitable. Today, in principle, all domestic oil burners have been replaced with alternative and renewable technologies such as pellets.

As an example of small scale installations Osby Parca has a container-based system (Eliasson, 2014). The system is fully automatic and include boiler and systems for fuel and ash handling and flue gas cleaning (see Figure11.13 and Table 11.3).

A middle-size heat central cover between 3 and 20MWth and is suitable in heating systems for smaller to mid-size district heating grids, energy-intensive industries such as saw mills, and process industries or a small-scale CHP. It is possible to get hot water, saturated steam, or overheated steam according to customer requirements.

The boiler manufacturer takes care of the design and planning, manufacturing, assembling, and start-up of the plant. The plant is in fully automatic operation from the fuel feeding and combustion to ash removal and flue gas cleaning. The combustion system ensures low emission and high efficiency without impact on the availability and maintenance (Figure 11.14 and Table 11.4).

With an annual production of 8300GWh heat, 400GWh cool, and 1500GWh electricity, Fortum AB is one of the largest suppliers of heat and power in the Stockholm area. As part of the development to carbon dioxide-free production, one of the largest boilers for biomass in the world is now under construction at the production site of Vrtaverket in central Stockholm (Figure11.15 and Table 11.5). The new biofueled CHP plant in Vrtan is an important step in the development of a sustainable energy supply in Stockholm, Sweden, and the rest of Europe. The renewable energy will be obtained from waste products from the forestry industry such as chips, bark, branches, tops, and twigs. The boiler will consume about 3 million m3 of fuel annually, or 12,000m3 per day. The new boiler will have a steam power of 330MW with an electrical output of 130MW. The boiler technology is a circulating fluidized bed (CFB) delivered by Andritz, and the steam turbine is delivered by Doosan Skoda Power. The CFB technology ensures good fuel flexibility including different forest residues as well as peat and coal.

The fuel will be supplied by ships (60%), train (>30%), and trucks (<10%) preliminary from Sweden, Finland, the Baltic States, and Russia. To minimize emissions from the ships, they will be connected to the electrical grid in the harbor. Special concern has been taken regarding the unloading to ensure low emissions of dust and noise and during nighttime the operation will be run in silent mode at lower capacity. The fuel will be transported in a tunnel (108m wide) to an underground storage (rock cavity) of some 50,000m3 (corresponding to 4 days of operation). The bottom ash and fly ash will be transported in the tunnel in the opposite direction.

When the new plant is commissioned in 2016, 1700GWh of heat and 750GWh of electricity will be produced annually. That is enough to heat around 190,000 apartments. The produced renewable electricity will have a positive impact on the global climate by replacing electricity that would otherwise be produced from fossil fuels in the Nordic Region and in Europe. That means that the new biofueled CHP plant alone will reduce Europe's CO2 emissions by 650,000tons per year. TheCO2 emissions in Stockholm will be reduced by 126,000tons per yearequivalent to the amount emitted by vehicles in Stockholm in 1.5months.

Valmet Power Oy has long experience in advanced CFB4technology for waste to energy using solid recovered fuels (SRF). The size of the plants start at 50MW fuel input, with a maximum size expected of 250MW with the present technology. Main benefits of CFB combustion technology are high fuel flexibility (wide span in heating value, ash, and moisture contents), high combustion efficiency, and low emissions. Also the availability is high with reference data from SRF combustion, indicating that an availability of more than 97% is achievable (Luomaharju and Viljanen, 2013).

Valmet is delivering the so far largest boiler in the world for solid recovered fuel to Mlarenergi in Vsters (Figure11.16). The fuel input will be 167MW, corresponding to 60tons of fuel per hour. The boiler is designed to burn household waste up to 70% and industrial waste up to 100% of heat input. Other fuels include wood, peat, and biomass (cf. Tables11.6 and 11.7).

The demand for ethanol as biofuel is expected to increase strongly as a means to reduce greenhouse gas emissions. Sweden, where ethanol, fossil biofuel, and protein feed are imported and where cereals are normally exported, provides an interesting market for ethanol production. Furthermore, there is no conflict with food or feed production as the used farmland in Sweden is decreasing.

In Norrkping, Lantmnnen Agroetanol AB is operating an ethanol production plant. The first production line was inaugurated in 2001 and the second in 2008. The ethanol production is integrated into the energy combine of Hndel in Norrkping (Figure11.17 and Table 11.8), producing CHP from biomass and waste. Heat is fed to the district heating network of Norrkping, and process heat in the form of steam is delivered to the ethanol factory. This ensures very high system efficiencies. In addition to ethanol, the plant produces protein for animal feed and renewable carbon dioxide for use in the food industry. The residues that cannot be used for higher value products is fed to a biogas plant together with straw producing biogas from anaerobic digestion. The energy combine is discussed in detail in the thesis of Martin (2013).

Wood-based solid biofuels are the biomass sources most commonly used in heat production. Combustion is the normal conversion method. Traditionally, of course, firewood was used for thousands of years to provide heat for domestic purposes, i.e., local heating and food preparation. Today, the availability of biomass-derived fuels in clean and convenient forms (e.g., chips, pellets, and briquettes) and of modern, automatically operating combustion equipment have created renewed interest in the use of solid biofuels for domestic heating. The use of liquid biofuels is also making headway for small-scale heating. For the commercial and industrial sectors, fixed-bed, fluidized-bed, and dust combustion equipment now available allow efficient production of heat from biofuels of different types and forms on a larger scale. Cofiring of biofuels with coal is also practicable. All these processes are discussed in more detail below.

For domestic, commercial, and industrial combustion equipment, it is advisable to use solid biofuels that have undergone some form of pre-treatment and processing (e.g., washing, drying, size reduction, and compacting) to achieve greater uniformity and ease of handling and reduce the moisture content to an acceptable level.

At the domestic level, appliances that burn wood and similar biofuels are popular because they not only provide heat, but also help create a pleasant atmosphere and decorative space. Commonly available appliances include fireplaces, heat storage stoves, pellet stoves, and burners, and central heating furnaces and boilers for wood logs and wood chips.

There is also a range of automatically operating appliances for wood chips and pellets on the market. The excellent handling properties of pellets make them a good fuel for domestic and other small-scale use. Good automatic pellet-fueled boilers with low emissions and high efficiencies have been on the market for about ten years now. Existing oil-fired boilers can be adapted for pellet use by replacing the existing burner by one constructed to take pellets. If this burner-boiler combination is well designed, an efficiency of over 90% can be achieved, which is comparable to the efficiency of a modern oil burner. Changing an oil burner to a pellet burner or replacing electric heating with a pellet-burning stove can be profitable. A pellet boiler takes a little more effort to run than an oil boiler because the chimney has to be swept and the ash removed a few times a year. Apart from this, the system is completely automatic and therefore requires less effort than a traditional wood-fired boiler. Environmentally, a good pellet burner is preferable to a fossil fuel burner. Pellet burners meet the demands of national and international eco-label schemes. Their emissions are well below the building regulations requirements of most EU member states and will not contribute to the greenhouse effect. A further advantage of moving from fossil fuels to biofuels for small-scale heating is that it will help the rural economy.

Fixed-bed combustion includes grate furnaces and underfeed stokers. Grate furnaces, which generally have capacities up to 20 MWth, are suitable for burning biomass with a high moisture content. Primary air passes through a fixed bed where drying, gasification, and charcoal combustion take place in consecutive stages. The combustion gases are burned in a separate combustion zone using secondary air.

Underfeed stokers, which represent a cheap and safe technology for systems up to 6 MWth, are suitable for biofuels with low ash content and small particle size such as wood chips, pellets, and sawdust. The fuel is fed into a combustion chamber from below by screw conveyors and transported upwards to a grate.

Fluidized-bed combustion systems are suitable for large-scale applications exceeding 30 MWth in size. The biomass is burned in a self-mixing suspension of gas and solid bed material (usually silica sand and dolomite) in which air for combustion enters from below. The high heat transfer and mixing encourage complete combustion. Fluidized-bed systems allow a good deal of flexibility regarding fuels, although attention has to be paid to particle size.

Dust combustion systems are suitable for biofuels, such as wood dust, in the form of small, dry particles. A mixture of fuel and air is injected into the combustion chamber. Combustion takes place while the fuel is in suspension. Fuel gasification and charcoal combustion take place simultaneously because of the small particle size. Quick load changes and efficient load control can be achieved.

Cofiring of biomass with coal in traditional coal-fired boilers is becoming increasingly popular, as it capitalizes on the large investment and infrastructure associated with existing fossil-fuel based power systems and at the same time reduces the emission of traditional pollutants (sulphur dioxide, nitrous oxide, etc.) and greenhouse gases (carbon dioxide, methane, etc.). Up to 10% biomass can be added to nearly all coal-fired plants without major modifications. Wood chips, willow chips, sawdust, and organic waste are the forms of biomass most often used.

Cofiring is normally realized by what is termed direct cofiring, i.e., firing the biomass and coal together in one combustion chamber of the power plant boiler. However, a number of other systems exist that fall into the category of indirect cofiring. One indirect system, known as a hybrid system, uses 100% biomass firing to generate steam. This steam is then mixed with the steam coming from the conventional coal-fired boiler for sending to the steam turbines for electricity generation. A second type of indirect system involves burning the biomass in a pre-furnace and feeding the resulting flue gases into the existing coal boiler. In a third type, the biomass is gasified and the resulting combustible gas fed to the coal combustion chamber.

Appropriate techniques exist for treating all the emissions that emerge from biomass combustion plants. For large installations, flue gas cleaning is economically viable. As explained in the section on solid biofuels, NOx emissions can usually be controlled by appropriate combustion techniques. Secondary reduction measures to remove Sulphur Oxides are not usually necessary because biomass combustion does not yield as much of these pollutants as does coal combustion. Solid ash and soot particles are, however, emitted by biomass combustion. As these cause aerosol formation, additional gas cleaning is required to remove them.

SOx and particulate matter emission controls apply to all fuel oil combustion equipment onboard including main and auxiliary engines, boilers and inert gas generators. The global sulphur cap is being reduced progressively from 3.50% (2012) to 0.50% (2020), subject to a feasibility review. The limits applicable in special emission control areas (ECAs) for SOx and particulate matter were reduced to 1.00% (2010); being further reduced to 0.10% (2015).

In January 1980, the Province of New Brunswick and the Federal Government signed the Canada-New Brunswick Conservation and Renewable Energy Demonstration Agreement (CREDA). The Agreement (originally scheduled to terminate in March 1984) provided funds for the development, demonstration and commercialization of conservation and renewable energy technologies. The Federal Government contributed $9 million and the Province contributed $2.25 million for a total program funding of $11.25 million.

CREDA was originally developed in part to bridge the gap between research and implementation of promising technologies. Developing public awareness of the potential for conservation and renewables, creating employment in new and existing industries and fostering information transfer between demonstration projects and potential users of the technologies, are all key objectives of the Program.

In the early days of CREDA in New Brunswick, most demonstration projects which were approved resulted from unsolicited proposals. As word quickly spread around the province that funds were available for conservation and renewable demonstration projects, the quantity and sophistication of project proposals increased correspondingly.

In order to focus on demonstrations which were particularly attractive and relevant to New Brunswick, the Energy Secretariat in 1982, developed a CREDA Planning Document identifying three priority technology areas: 1) Wood and other biomass; 2) Waste heat recovery in all sectors; 3) Energy efficient retrofit in the residential, commercial and institutional sectors.

In addition to funding demonstration projects in these 3 priority areas, the Program continued, albeit more selectively, to fund a variety of promising technologies, geographically well distributed throughout the province.

The wood subprogram is extremely well developed. Beyond merely focusing on energy, the economic, employment and silvicultural benefits to the forest industry are integral components of the wood energy subprogram. The subprogram also focused on a select range of technologies (ie those related to the production, distribution and consumption of wood residue) which appear to have the greatest current potential for replication.

University of New Brunswick, Fredericton. Installation of a wood residue boiler to burn hogged bark supplemented by other sawmill and harvesting residues, procurred under long-term contracts with local sawmills.

A variety of Heat Recovery projects have been funded throughout New Brunswick. Some demonstrate well proven technology such as heat pumps, while others focus on the development and demonstration of novel concepts such as surface heated Greenhouses.

Mount Allison University, Sackville. Installation of heat recovery equipment, insulation and a central computer-based building energy management system. Modifications to ventilation, lighting and hot and cold water systems are also included in the retrofit.

Connors Brothers Ltd., Black's Harbour. Modification of existing burners and combustion testing of various mixtures of fish oil as a replacement for Bunker C oil. Total cost: $50,100 CREDA funding: $38,250 Annual saving: 50%

Most dry forms of biomass can be burnt very efficiently in well designed combustion equipment, making the replacement of oil in its industrial heating applications eminently feasible in technical terms. Given suitable land, biomass can also be grown at a cost well below the equivalent energy cost of oil fast growing tree plantations being generally the most attractive option. Limitations arise, however, due to the problems of transporting biomass from the areas where it can be grown to the industrial centres where the energy demand exists.

Because of the transportation component, the most economic and energy-efficient method of using biomass for industrial heating is to locate industries near to energy plantations so that they can burn wood directly. This provides a strong incentive for decentralisation of new industrial facilities. Relocation of presently existing facilities, on the other hand, would obviously be limited by the economic and social upheaval that would be required.

Where haulage distances are large, conversion of wood to charcoal has a number of advantages. Its higher energy content (approximately double that of wood, on a weight basis) makes it cheaper to transport as well as more convenient and efficient to burn. Charcoal also has several other desirable features for specific industrial uses, such as steel and cement making. The primary disadvantage of using charcoal is the significant energy losses that occur in the conversion process. These amount to as much as 50% of the original energy in the wood, even with efficient charcoal making equipment. Conversion to charcoal does greatly increase the range and extent to which wood energy can be used for industrial purposes, however, and as such can by justified given favourable local economics and provided that wood can be supplied in a renewable fashion.

The cost effectiveness of using wood and charcoal for industrial heat can be expected to improve as oil prices rise. The fact that these fuels are presently used in many countries is indicative that this is already a viable proposition in some cases, although the forestry and charcoal-making techniques currently used are often far from ideal. To maximise the potential of this approach, managed tree plantations will be required, as well as efficient charcoal conversion facilities and an appropriate transportation network. Such a supply system could either be integrated or separate from the systems that are necessary for the supply of wood and charcoal for domestic needs in urban areas.

In this chapter, the properties of products of combustion that are used for combustion equipment configuration selection, material of construction selection, heat system and air pollution control system selection, and design are discussed. The estimation of the concentrations of hydrogen fluoride, hydrogen chloride, hydrogen bromide, and hydrogen iodide as well as the concentrations of their corresponding fluorine, chlorine, bromine and iodine molecules, and the concentration distribution between sulfur trioxide and sulfur dioxide in the combustion product gases are described in this chapter. Models for the estimation of equilibrium formation of nitrogen oxides as well as the estimation of concentrations of nitrogen oxides in the combustion product gases are also presented in this chapter. The mechanisms for the formation of incomplete combustions and dioxins are discussed in this chapter. This information can be used for the reduction and control of products of incomplete combustion and dioxins. The acid gas dew points in the product of combustion can be estimated with models presented in this chapter. The fate of metals contained in the fuels and their effect on the combustor design are also included. And most importantly, an iterative algorithm to estimate the eutectic points of metallic compounds that may be presented in the combustion product gases is included. These estimation results will provide good information to prevent the formation of troublesome molten metallic compounds that may affect the system operation.

In the chemical industry, there is a special group of waste liquids that contain alkaline metals, such as sodium. The incineration of this group of waste liquids (i.e., waste liquids from caprolactam plants or acrylonitrile plants) presents a unique problem that requires special design considerations. This chapter discussed the incineration system design and heat recovery configurations of this waste group.

At the present time, there is not much information on estimation methods for products of incomplete combustion, dioxins, and fates of metals contained in the fuels. More studies are necessary to use experimental techniques, numerical calculations, and big data analysis techniques to derive methods to estimate the types of qualitative and quantitative concentrations of these compounds.

Lpez-Antn etal. [6] studied Hg behavior in the industrial combustion equipment of a 50MW CFB boiler. The first combustion sample is the blend of 3641wt% bituminous coal, 6 wt% limestone, and 5156wt% coal waste from the old disposal sites that contain coal; another combustion sample is the blend of 32.2wt% coal, 5.4wt% limestone, and 54.5wt% coal waste. Coal blends, limestone, bottom ashes, fly ashes, airborne particulates, and flue gases were sampled and analyzed (Fig.6.1).

The combustion equipment allows the burning of combustible blends with high ash content, which is about 63%65%. The validity of the Hg content in the samples can be confirmed by the percent relative standard deviation value. It was found that Hg in feed coal was distributed in combustion products. Hg concentration in the bed ash sampled from two strippers showed that the Hg content in bottom ash is not significant. In contrast, fly ash contained a high Hg concentration, which indicated that fly ashesplayed a very important role in capturing mercury. The fly ashes collected from the hoppers contained different Hg levels, among which the fly ash from the electrostatic precipitator (ESP) had the highest Hg concentration, especially for FA10, FA11, FA14, and FA15. Since the mercury was higher in the second campaign of combustible blend, the corresponding fly ash from this campaign contained higher mercury.

Fig.6.2 shows the relative enrichment (RE) factor values of fly ash samples obtained from two sampling campaigns a and b. It is found that the fly ashes from the last two hoppers of ESP have the highest REs, indicating that these two fly ashes are highly enriched with Hg. Moreover, the value of REs of the fly ashes collected from the air heater hopper are very low, whereas the value of REs of the fly ashes collected from ESP are higher than 1; in particular, for FA10, FA11, FA14, and FA15, the values of REs are higher than 3. This is consistent with the strongest captureability of mercury by the fly ashes from the last two hoppers of ESP, whichhave the characteristics of low particle size, high carbon content, and high surface area.

The mass balance of the input and output of the two sampling campaigns is shown in Table6.1. It can be observed that the Hg content in particulate matter (PM) of flue gas is relatively high. However, the mass of such PM is very low. Thus the output rate of particulate Hg in flue gas is relatively low. Most of the mercury in this fluidized-bed power plant is retained in fly ash. Mercury emissions from the gas phase are significantly low with less than 1% total mercury (Hgt) emissions from the gas phase.

Table6.2 shows the concentration of gas-phase Hg speciation in flue gas. The results showed that there were oxidized and elemental mercury (Hg0) in the flue gas, and Hg0 had the highest proportion. The emission concentration of Hg2+ was lower than 0.02g/m3, while Hg0 is around the order of 0.2g/m3.

Fluidized-bed furnace (FBF) and stoker-fired boiler (SFB) are widely used in small coal-fired power plants. Although the emission of Hg, As, and Se from industrial boilers is not growing rapidly, industrial boilers remain the largest Hg, As, and Se emission source related to coal utilization. The total amount of Hg, As, and Se from industrial boilers increased from 40.8, 382.67, and 364.81t in 1980 to 155.46, 1348.70, and 1322.78t in 2007, respectively [7]. The average release rates of Hg, As, and Se in FBF were 98.92%, 75.6%, and 98.05%, respectively, those in SFB were 85.00%, 77.18%, and 80.95%, respectively, and those in the coke furnace (CF) were 83.15%, 30.00%, and 40.00%, respectively.

The historical emission trend and composition of Cd, Cr, and Pb by different sectors are shown in Fig.6.3 [8]. The emission of the industrial sector was the leading source of the three elements. The emission amounts of Cd, Cr, and Pb from the industrial sector increased from 19.89, 788.58, and 965.47t in 1980 to 230.88, 7454.26, and 10271.45t in 2008, which accounted for 88.3%, 86.7%, and 81.8% of the total emission, respectively. The growth of the Cd, Cr, and Pb emissions by industrial sector increased most rapidly, with annual growth rates of 9.2%, 8.4%, and 8.8%, respectively. Table6.3 summarizes the release rates of Cd, Cr, and Pb during coal combustion in FBF, SBF, and CF [8]. The release rates of the three elements in FBF were 91.50%, 81.33%, and 77.33%, respectively, those in SFB were 42.53%, 26.74%, and 40.10%, respectively, and those in CF were 20.00%, 24.00%, and 31.50%, respectively. The release rates of Cd, Cr, and Pb in FBF were much higher than SFB and CF.

coal processing methods

More coal processing is done in foreign coal-producing countries because of their requirements for a smokeless fuel, their need to make a satisfactory metallurgical coke from inferior quality coals, and their general lack of indigenous oil or gas from which to produce chemicals or other carbon-based products.

The demand for coke in the United States has declined from a recent high in 1957 of 76.0 million tons to only 55.9 million tons in 1959 and 57.2 million tons in 1960. In addition to a decrease in coke demand in 1959 and 1960 because of a steel strike and general business recession, some technologic developments, such as supplemental fuel injection and better prepared burdens, tended to lower further the blast furnace coke rate, which reduced coke requirements for pig iron production. Nevertheless, because the cost of coke is important in pig iron manufacture, efforts to improve the methods and economics of carbonizing coal have not been reduced.

Blending of coals of different ranks and from different seams is used increasingly in the United States and in foreign countries to obtain an oven charge that will give coke of optimum quality and strength without damage to the carbonization equipment. All the 72 plants in operation in the United States use blends rather than single coals.

No major changes have been made in conventional oven equipment or processes used to produce coke in the United States for blast furnace use, but recent trends in automation of the plants to reduce labor costs have continued. Although the very large coke ovens used at several plants in Germany, Italy, and Russia have not been erected in this country, a construction firm has an agreement to build German-type ovens in the United States. Labor costs are claimed to be reduced significantly with these large ovens.

Because most European countries must use relatively poor coking coals to produce satisfactory coke, greater efforts to improve coke quality have been made there than in the United States. The charge of four large coke plants in France and about 90 percent of the coal carbonized in Poland are reported to be prestamped. This improves coke quality by increasing the bulk density of the charge while using less of the more expensive strongly coking coals in the blend. Another development, used in one plant in France, is dry charging, which gives a greater bulk density, greater coke production, and an improved coke strength for a given blend. In the United States a study showed that for each 1 percent of moisture reduction in the coal, oven throughputs increased 1.5 to 3.5 percent with no deterioration in coke properties.

Preheating the coal blend before charging into the ovens continues at the experimental level in several countries. The same improvement in coke strength for poorly coking coals results from preheating the charge as from drying the coals and results in further increased oven capacity. In the United States, the Bureau of Mines showed that preheating an Illinois No. 6 bed coal increased the coke strength and reduced the coking time. In other Bureau tests, increased strength of coke was obtained for all coals and blends tested; the greatest improvement occurred for those coals and blends making the poorest coke. In a study the Koppers Company obtained substantial improvement in coke quality by preheating the charge when high-oxygen coals were used.

After years of development in many different laboratories, small-scale test ovens, varying in size and used to predict the effect of changing variables on coke strength, have demonstrated their usefulness both in the United States and abroad. Four years of study in Marineau, France, showed that, except for material balances on new oven blends, complete comparability in tests is possible between full-scale ovens and a 400-kg. test oven. Similarly, the British Coke Research Association was able to relate test results of both a 10-ton and a 500-pound oven with commercial ovens.

With small-scale test ovens, the many variables that affect coke strength can be studied safely, and the economic importance of proposed changes in carbonization practice can be estimated. The effect on various blends of coals of such variables as particle size of the charge, surface-moisture, and oil additions on coke strength and expansion properties of the charge have been studied extensively in the United States, England, Germany, and France. Other variables, such as the effect of inerts, the use of blends of various coal tar pitches, the rates of heating the charge, and the effect of coking temperature, have been investigated and their interrelationship clarified. Based on this information, the addition of coke breeze or pulverized low-temperature char to increase coke strength has reached commercial application in France and Germany. In German experiments the effects of changes in operation of the oven and of different kinds of blends have been studied both with and without stamping of the charge. Other studies have shown that for coals that make a relatively weak coke, the Gieseler plastometer gives a good indication of how best to blend coal with higher ranking coals to make the lowest cost coke of required strength.

Improved small-scale tests have been developed to predict wall pressures that would be obtained in commercial practice. As a result, better information can now be obtained easily on the effect of bulk density and other variables on wall pressures.

In the last several years, success has been achieved in the United States and abroad in showing the comparability between the different laboratory tests used for measuring coke strength. The Micum and ASTM tumbler tests and a number of other standard tests can now be compared so that data collected by different test methods can now be used by all research workers.

Theoretical studies have continued, in all nations concerned with coal, on the mechanism and kinetics of the coking process. Much of this effort is centered about coal plasticity and the rate of weight loss as a function of temperature for different ranks of coal. This approach may lead to a better understanding of how coals and coal blends are transformed into coke. Other studies, such as the effect on hardness and other properties of coke caused by adding various amounts of pitch to coal and the effect of various petrographic constituents on coke strength, should lead to the development of improved coking methods and practices.

Ferrocoke is not used extensively in the United States, but interest continues in its manufacture, particularly when a small pig iron plant cannot afford sintering equipment for blast-furnace flue dust. It has been demonstrated that making ferrocoke requires a higher bulk density of the charge and a longer coking time. Larger pieces of coke are formed and the shatter index is higher, but the tumbler index is lower for both the 1-inch and -inch screen.

Research on ferrocoke continues overseas, and a study in India showed that 15 percent iron ore and 85 percent lignite gave a ferrocoke briquet of satisfactory strength. The addition of 10 percent low- or high-volatile bituminous coal to the mixture allowed the iron ore concentration to be increased to 30 percent without loss of briquet strength.

The rising demand for coke breeze has increased the average reported price from $3.80 in 1949 to $8.27 in 1960. Because of this price increase, alternate methods of producing small-size coke that can be used when strength is not critical have been developed, particularly in those areas where the breeze must be transported long distances; thereby, the delivered price is raised appreciably.

A rotary coke oven developed by the Wise Coal and Coke Company reportedly produces a small-size coke or char suitable for a chemical reducing agent in some processes, such as electric- furnace production of steel and in phosphorus manufacture. Coal, fed in a bed 6 to 12 inches deep onto a rotating circular grate, is heated by combustion of volatile matter evolved from the coal as it is carbonized. In effect, the rotary oven operates as if it were a continuous beehive oven. No byproducts are recovered, but it is believed that low capital and operating costs can be achieved when low-cost coals are used.

Two other continuous methods, similar to the process used commercially in Canada by Shawinigan Chemicals, Ltd., for producing small-sized coke have been reported in the United States. Both of these methods use moving grates. In one series of industrial tests a water-cooled Vibra grate stoker installed in a Kewanee boiler was used to produce a 1- x 1/8-inch coke with a 53 to 54 percent yield. The feed material was a 2- x 1--inch high-volatile A bituminous coal. In these tests about 38 percent of the heat value in the coal was recovered as steam, and about 50 percent remained in the coke. On the basis of these tests a commercial plant has been constructed at a cost of $600,000. The plant is reported to use a traveling grate but does not recover heat in the form of steam. No details have been released concerning the other continuous coker, which has been developed and which also reportedly uses a traveling grate.

Other developments using a traveling grate of different types to produce a chemical grade coke either commercially- or in pilot studies have been reported. The New Jersey Zinc Company is using a traveling grate to carbonize a zinc ore-coal briquet. A traveling grate stoker for producing coke was investigated by the Central Fuel Research Institute in India, a company in South Africa, and Bituminous Coal Research, Inc., in the United States.

In Western United States, reserves of good grades of coking coals that are comparable to those in Eastern United States are in short supply, and two new processes for making coke have been announced. The Food Machinery and Chemical Corporation and the United States Steel Corporation have developed a process, which is said to produce either a coke strong enough for use in blast furnaces or a product that can be used as a substitute for coke breeze in phosphorus reduction. The process is reported to be carried out in two steps a low-temperature treatment of the coal, followed by briquetting and further processing of the briquet.

In the other process developed by United States Fuel Company, fine coal is pelletized with an inert binder and water. The pellets are dried and charged to the top of an externally heated retort and flow countercurrent to a stream of natural gas fed at the bottom. Natural gas requirements of the operation are about 18,000 cubic feet per ton of coal, 10,000 cubic feet for drying and preheating, and 8,000 cubic feet per ton of coal for the thermal decomposition reaction. Tar in 40- to 50-gallon amounts per ton of coal and the combination of decomposition products from natural gas and coal yield 18,000 to 20,000 cubic feet of reactor gas containing 85 percent hydrogen. Volatile matter in the coke produced is about 1 percent.

The apparently attractive potentials of low-temperature carbonization of coals as a coal-processing method are so great that hundreds of patents have been issued in the last 50 years on different methods of carrying out this process. Millions of dollars have been spent on research to develop plants that would be commercially successful, but in the United States today only two low-temperature carbonization plants exist, each reported to be operating only part time. The Disco plant of Consolidation Coal Company processes a bituminous coal and produces a smokeless fuel, which meets air pollution regulations in the Pittsburgh area. The other plant at Dickinson, North Dakota, using lignite as a raw material produced a lignite char, which was subsequently briquetted and sold as a domestic solid fuel. In the last several years the Dickinson plant was reported to be making barbecue briquets.

Low-temperature carbonization processes, using any rank of coal, can be economically successful, if either the char or the tar can be sold at a premium price. Because the United States has ample supplies of some of the worlds best coking coals that are obtainable at low costs, no premium could be expected for the chars in metallurgical outlets in the United States, except in special places or under unusual conditions. Moreover, because the competing fuels, oil and gas, are available locally at reasonable prices in cities where air pollution is a problem, no large-scale premium outlet exists in the United States in the foreseeable future for the char as a domestic smokeless fuel. Also, the development of commercial outlets for the tar at prices that would make low-temperature carbonization attractive have not been successful. For these reasons, commercial exploitation of low-temperature carbonization has been limited.

Either coking or noncoking coals can be used to prepare chara, but usually a noncoking or weakly coking coal is employed because of its availability and price. In the United States, however, low-temperature carbonization has mostly been attempted with coking coals, which constitute over 90 percent of our production but which introduce serious operating problems. The largest plant constructed in recent years for testing the economics of low-temperature carbonization is the semi-commercial unit of the Aluminum Co. of America in Rockdale, Texas, which uses a Texas lignite that is carbonized in an externally heated fluid-bed reactor. Research on the Parry process, which is employed at the Aluminum Co. plant, is continuing at the Bureaus Denver Coal Research Laboratory with experiments aimed at determining the optimum ratio of internal to external heating and developing methods of using strongly coking coals.

The previously mentioned Food Machinery and Chemical Corporation development is reported to use a fluid-bed process for low-temperature carbonization as a first step in the process, although no description has been published.

During the 1950s experiments were conducted on low-temperature carbonization of coking coal by United Engineers and Constructors, Southern Research Institute, Consolidation Coal Company, and Montana State College. None of these processes, as originally, tested, have reached commercial application as yet, but these research activities plus a steady stream of patents on the subject indicate a continuing interest in the subject.

More commercial success in low-temperature carbonization has been realized in other nations, where high-quality coking coals are expensive and in short supply and where an extensive market for smokeless fuels exists. A premium price is offered for the chars produced in both of these markets. Two commercial processes (Phurnacite and Rexco) have been used for a number of years in England to make a smokeless fuel. Both processes carbonize a weakly coking coal in an externally heated vessel with no briquetting of the charge. Low-volatile fines, which have been briquetted with a pitch binder and then subjected to a low-temperature carbonization are also used in another process to make a domestic fuel. Similar processes are in commercial operation in other European countries.

Vigorous efforts are being made in England to produce chars that can be used to make a suitable smokeless fuel, and a systematic study is being made of a number of English coals in an 8-inch diameter fluid bed carbonizer to determine yields and properties of the products Larger diameter fluid carbonizers of 18 and 24 inches also have been tested, and a commercial plant with a 5-ton per hour capacity is being constructed on the basis of pilot plant results.

In England recent carbonization experiments using a disperse phase, in which coal particles are suspended in a hot gas stream, indicated that volatile matter can be reduced from 37 to 23 percent, in 1 or 2 seconds. If a process based on this principle could be devised, important savings in plant cost should be possible.

In the past, a considerable quantity of coal and coke derived from coal was used in producing manufactured gas. When long distance pipeline transmission of natural gas from Texas was introduced to the heavily populated sections of the country, the production of manufactured gas declined rapidly. In 1960, only 722,000 tons of solid fuels were used in producing manufactured gas by all utilities in the United States.

Some gas from coal is still produced for internal use at manufacturing plants, but no reliable figures are available on the quantity of coal used for this purpose. The introduction of readily available natural gas, however, has almost completely displaced coal in markets such as this.

Because the average delivered price of natural gas has risen from about 22 cents per 1,000 cubic feet in 1945 to over 50 cents in 1960 and the price of coal has remained relatively constant during that same time, an opportunity exists for coal to compete with natural gas by producing a cheap hot producer gas for use in such commercial applications as lime burning and glass making. At one commercial plant, a study was made of the economics and optimum operating conditions of gas producers using bituminous coal, but otherwise little or no systematic research has been conducted on production of manufactured gas declined rapidly. In 1960, only 722,000 tons of solid fuels were used in the production of manufactured gas by . all utilities in the United States.

Some gas from coal is still produced at manufacturing plants for internal use in the plant, but no reliable figures are available on the quantity of coal used for this purpose. However, it is known that the introduction of readily available natural gas has almost completely displaced coal in this market, too.

As the average delivered price of natural gas has gone up from about 22 cents per 1,000 cubic feet in 1945 to over 50 cents in 1960 and the price of coal has remained relatively constant during the period 1948 to 1960, an opportunity exists for coal to compete with natural gas by producing a cheap hot producer gas for use in such commercial applications as lime burning, glass making, etc. However, except for one commercial plant where a study has been made of the economics and optimum operating conditions of gas producers using bituminous coal, little or no systematic research has been conducted on this problem. Some gas producers using coke and anthracite, however, are being used in this country and information on operating experience and economics should be available when using these noncoking fuels.

In foreign countries, because of the absence of adequate supplies of indigenous natural gas, coke oven gas has been distributed for commercial and residential use. To release more coke oven gas for this purpose, research has been conducted on methods of

When gasification to make water gas was common in the United States, cyclic processes operating at atmospheric pressure and using coke or noncoking coals were used. These were high-cost operations, but test showed that water gas generators could be made continuous by using oxygen instead of air as the oxidizing medium; this procedure should reduce costs. These modifications in fixed- bed cyclic operations can be made to remove the ash in dry form or as slag. The kinds of coals that can be used, however, are still limited.

Pressure operation has significant economic advantages, and the Lurgi fixed-bed gasifier was developed to exploit these advantages. Commercial installations have been made in many countries using non-coking coals or weakly coking sized coals. The gasifying medium is a steam-oxygen mixture, and the process can be operated up to 30 atmospheres. The chief limitations of this process are the special properties required of the coals, the excess steam needed to prevent ash clinkering so that it can be removed in a dry state, and the relatively small throughput per unit of reactor volume. To overcome these difficulties, the Bureau of Mines, Grand Forks Lignite Research Laboratory, North Dakota, is conducting research to develop a method of removing the ash as slag. This method would permit greater throughput per unit volume of reactor and lower steam consumption. Two separate investigations are underway in England with the same objective, the first study by the Gas Research Council and the second study by the British Coal Utilization Research Association under the auspices of the Ministry of Fuel and Power.

The major limitation of fixed-bed gasifiers is the requirement that the coals be either noncoking or weakly coking. In the heavily populated areas of the United States, where much of the demand for synthesis gas or hydrogen would be concentrated, nearly all of the coals are strongly coking. Consequently, fixed-bed gasifiers cannot be operated unless the coal is pretreated. Pretreatment to destroy coking properties will probably be relatively expensive because methods of treatment at a reasonable cost still need to be developed.

As a result, research efforts in the United States have been aimed at developing gasification processes that can use any rank of coal and can be operated continuously. A Koppers-Totzek, atmospheric entrained gasifier using 1 ton of oxygen per hour was installed at the former Bureau of Mines Demonstration Plant, Louisiana, Missouri, and was successfully operated for several years. At the Morgantown Coal Research Center of the Bureau, several entrained atmospheric pressure gasifiers using both upward and downward flow of the reactants were tested. On the basis of these investigations, Babcock and Wilcox Company in cooperation with the Dupont Company constructed in West Virginia an atmospheric gasifier, which produced approximately 1 million cubic feet of carbon monoxide and hydrogen per hour. Because of economic considerations work was discontinued after successful operation of this unit.

The only full-scale entrained pressure gasifier operated in the United States was that erected by the Olin Mathieson Company in Morgantown, using the Texaco process. The gasifying medium at this plant, however, was air rather than oxygen. The Bureau of Mines and the Institute of Gas Technology have operated pilot-plant sized entrained gasifiers under pressure using oxygen. The Institute of Gas Technology gasifier operated at 105 pounds per square inch , while the Bureau of Mines gasifier operated at 450 pounds, per square inch. Refractory difficulties and erosion were problems in both reactors.

Fluid-bed gasifiers have been investigated in Europe and the United States. The major limitation on the fluid-bed gasifier is that it requires a noncoking or weakly to moderately caking coal. Commercial processes using this method of solid-gas contacting have been developed in Germany, and the Winkler, Winkler-Flesch, and Basf-Flesch-Demag processes have been commercially installed in several countries to make synthesis gas.

In France a pilot plant using the fluidized technique has been developed recently, which it is claimed can use any rank of solid fuel if the particle size and moisture content fall within specified ranges.

In the United States, Consolidation Coal Company is reported , to have operated a fluidized gasifier under pressure using a strongly coking bituminous coal. No reports have been published of this research. Hydrocarbon Research in the United States also operated a fluid-bed gasifier under pressure, but anthracite fines were used so that the coking problem was avoided. Up to 650,000 cubic feet per day of combustible gas were produced in this plant, and high reaction rates between carbon and steam were obtained.

Two new methods of gasifying coal have been proposed by Rummel in Germany. Both processes use a slag bath as a heat transfer medium. In the first, a single shaft gasifier, a mixture of coal, oxygen (or air), and steam is tangentially injected into a bath of molten slag. The coal remains in the slag at elevated temperatures long enough to complete its gasification. The slag is claimed also to act as a catalyst for the reaction. In the second process, in which a double shaft gasifier is used, a rotating slag bath is separated by a dividing wall to form two chambers. Air and coal are introduced into the slag in one chamber, and the coal is burned to raise the temperature of the slag. The slag circulates to a second chamber into which steam and coal are added and where the steam-carbon reaction takes place to produce synthesis gas. The double shaft process has been reported to have been operated satisfactorily, and on the basis of these investigations,.the North Thames Gas Board in England is planning to install a large pilot plant. The chief disadvantage of the double shaft process in producing synthesis gas or hydrogen is that it does not operate under pressure. The advantages, however, are that it requires no oxygen and should be able to handle any type of coal. On the other hand, the single shaft process, which has not been extensively investigated, should be adaptable to pressure operation, using either oxygen to produce synthesis gas or air to make producer gas.

One of two processes used by Germany during World War II to produce large quantities of liquid fuels from coal was the Bergius process in which a powdered coal is mixed with a recycle oil stream and reacted with hydrogen in the presence of a catalyst in a two-step process. In the first reactor, operated at 10,000 p.s.i. and 900 F., a liquid phase is maintained, and the product is a middle oil. The middle oil is reacted with hydrogen in a vapor phase in the second step of the process, using a catalyst and operating at pressure of 10,000 p.s.i. and temperature of 920 F.

The liquid products made by the Bergius process are expensive because the extreme temperatures and pressures used necessitate high capital plant costs and the complexity of the process makes for high operating and labor costs. Immediately after the war several countries tried to make the process more economic in competing with natural petroleum products but were not successful; coal hydrogenation plants have been converted to other uses. In some of these plants, coal tars in place of coal were hydrogenated to liquid products because milder operating conditions and less hydrogen are needed for tars, but no plants in the free world are operating now, even in this more favorable manner.

Nevertheless, research on coal hydrogenation in the United States and abroad has resulted in many process improvements and improved economics. Improved catalysts and methods of using them have been discovered, and in the United States, the Bureau of Mines has demonstrated that when molybdenum concentrations are as low as 0.01 percent, Wyoming coals can be converted at 8,000 p.s.i. and 480 C. with throughput four times as great as the Germans were able to obtain with iron catalysts. In another attempt to reduce plant costs and complexity and thus product costs, the Bureau studied a one step process. However, coke formation occurred at lower catalyst concentrations where temperature control was possible; at higher catalyst concentrations, temperature control was not possible.

Interest in the higher boiling products developed in the United States as the result of increased demand for jet and gas turbine fuels, and other Bureau experiments were made at 2,000 p.s.i. and 465 C. to produce these types of fuels rather than the normal range of petroleum products. The much lower pressure used would reduce capital costs appreciably. At these conditions, 95 percent conversion of coal was obtained with throughput comparable to the high-pressure Bergius process. Lower catalyst concentrations resulted in lower throughput, but product characteristics remained the same. Tests using iron as the catalyst at several concentrations showed that 2 percent iron was equal to 0.1 percent molybdenum in tests with 1 percent iron, the throughput was reduced 25 percent.

Autoclave experiments were conducted by the Bureau in an effort to elucidate the mechanism of coal hydrogenation and to develop new and improved catalysts that would permit high conversion and large throughput at lower temperatures and pressures. No major breakthrough was discovered that would make a major change in the economics of the process.

No other research at the engineering level is reported in the United States or abroad, although Consolidation Coal Company and Standard Oil Company of Ohio have announced a joint research program involving hydrogenation of coal. At the laboratory level, some research is still underway on catalyst development and on basic studies that may reveal ways of hydrogenating coal more economically. For example, it has been suggested that, if a method could be devised to use the hydrogen-rich portion of the coal to produce liquid products and leave a less reactive char for producing the hydrogen required, significant savings would result. Some of the laboratory studies now underway may demonstrate how this can be achieved.

The volume of liquid fuels produced by the Fischer-Tropsch process was never as great in Germany as production by the Bergius process. When an early decision was needed to freeze production plant design, the Bergius process was selected because at that time it had been investigated longer rather than because of any consideration of the relative economics. On the contrary, cost estimates made after World War II in the United States seem to indicate that the Fischer-Tropsch process would be more economic.

In the Fischer-Tropsch process, coal is gasified completely to make synthesis gas, and the gas is reacted over a catalyst to make a variety of organic products. The major engineering problem is the removal of heat because the reactions are highly exothermic. The first Fischer-Tropsch plants used cobalt catalysts operating at pressures from atmospheric to 100 p.s.i. in fixed-bed reactors. The catalyst was surrounded by water-cooled heat exchangers to maintain temperature control. Later German plants used higher pressures and iron catalysts.

Unlike the coal hydrogenation plants, some Fischer-Tropsch plants recently were still operating in Europe but produced mostly a variety of organic compounds and small quantities of liquid fuels. It is not known if any Fischer-Tropsch plants are operating at present. In the United States a Fischer-Tropsch plant constructed at Brownsville Texas, used natural gas as the raw material but stopped production of liquid fuels in 1957. In South Africa, the SASOL plant with a 5,000 bbl. per day liquid product capacity began operating in 1957 and has been successfully producing since then. A recent announcement stated that the plant would be expanded to almost double its present capacity. Because there are no indigenous liquid or gaseous fuels in South Africa, this plant is important for strategic reasons. Moreover, foreign currency considerations, the low-cost coal available, the desire to use a native resource, and the high transportation cost of liquid fuels imported to the densely populated Johannesburg area where the SASOL plant is located all affect the overall economic and political decisions to expand the plant.

Several important engineering modifications have been made in the Fischer-Tropsch process to remove the exothermic heat, and major improvements in catalysts have reduced costs. All modern processes use pressures of 25 to 30 atmospheres. The hourly space velocity of a new fixed-bed process, installed at SASOL is 500 cubic feet per cubic foot catalyst hour, contrasted with only 100 cubic feet per cubic foot catalyst hour for the early German plants. The second process used at SASOL is the Kellogg entrained process operated at 300 to 340 C. and with hourly space velocities of 400. The fixed-fluidized process operated in Brownsville, Texas, used a mill-scale iron catalyst at 300 to 340 C. and hourly space velocities of 440 V/V-hr.

In a fixed bed pilot plant, experiments have shown that the heat of reaction can be removed by circulating oil over the catalyst bed. At 280 C. and hourly space velocities of 600, either a fused iron or an iron lathe turning catalyst can be used. In the slurry process, the catalyst is suspended in the oil that is used to remove the heat. The process operates at temperatures of 280 C. and at hourly space velocities of 300, using precipitated, fused iron, or mill-scale catalysts.

The most recent engineering modification of the Fischer-Tropsch tested in a pilot plant is the hot gas recycle process, in which the heat of reaction is removed by recirculating 15 to 20 volumes of cooled make gas for each volume of fresh gas. This process can be accomplished at moderate pressure drops with a catalyst of iron turnings and hourly space velocities of 1,000 and temperatures of 300 to 340 C.

Major advances have been made in recent years in developing iron catalysts that can withstand the mechanical and other burdens imposed by each of the engineering modifications of Fischer-Tropsch process. Moreover, all the catalysts have good selectivity, activity, life and low initial costs.

Research is continuing in the United States and abroad on improved catalysts and engineering modifications of the Fischer-Tropsch process, mostly directed toward more basic studies rather than pilot plant experiments. However, a pilot plant has been constructed in India capable of producing 100 gallons of oil per day.

Important technologic breakthroughs will be necessary to make liquid fuels .produced by Fischer-Tropsch process economic in most countries, and the first plants will have to depend on income from the chemicals produced.

Development of a substitute for natural gas is of interest, but because gas of 800 B.t.u. content or more is not used commercially in many other countries, most of the research in producing gas of high heating value is being conducted in the United States. The Gas Research Council in England, however, has done considerable research on the direct hydrogenation of coal and investigations have been made in Australia using this process with brown coal.

Production of methane from coal by direct hydrogenation would require only the amount of synthesis gas that is needed for catalytic methanation. Because synthesis gas costs represent over 80 percent of the final gas cost, smaller gas requirements could have important economic implications. The Bureau of Mines and the Institute of Gas Technology are now experimenting to determine the optimum residence times and temperatures and pressures for this reaction. Pressures have been varied from 500 to 6,000 p.s.i. and temperatures from 1,000 to 1,800 F. Both entrained- and fluid-bed methods of gas-solid contacting have been tested. Long residence times and high carbon conversions are obtained using a fluid bed, but pretreatment of the coal is necessary to prevent coking. The product gas from fluid-bed reactors is high in methane and low in unreacted hydrogen, whereas the gas from an entrained reactor has a low methane content and would require a methane-hydrogen separation to obtain a high-B.t.u. gas. Entrained reactors, however, can use any kind of coal and require only short residence times.

Because the hydrogenation of coal to methane is exothermic, steam could be added to hydrogen to modulate the reaction and provide part of the hydrogen required. The endothermic steam-carbon reaction would use the heat released by the coal-hydrogen reaction. The potentials for using a steam-hydrogen mixture in a fluid-bed reactor are now being investigated by the Institute of Gas Technology.

In a balanced process, part of the carbon is used to produce the hydrogen required for the hydrogasification of the coal. Numerous methods have been proposed for using the more reactive portions of the coals high in hydrogen, to produce the methane. Low carbon conversions would be acceptable, because the unreacted char would be used to make hydrogen and in gasification an unreactive char would not be a serious drawback.

High-B.t.u. gas can also be produced by reacting synthesis gas over a catalyst. In the first experiments conducted in England, a nickel catalyst was used in a fixed-bed reactor. Nickel catalysts are sensitive to poisoning, and highly purified gas must be used. In later experiments at the Bureau of Mines, a Raney nickel catalyst was used in a fluid-bed reactor and produced satisfactory high-B.t.u. gas. Hydrogen was added at a number of inlets to insure good temperature control of the highly exothermic reaction. If it did not become sulfur poisoned, Raney nickel could be regenerated several times by a caustic soda treatment, thus giving good catalyst life.

The fluid-bed reactor provides a better means of modulating the heat of the reaction than a fixed-bed reactor, but internal water cooling will be required for each. In recent experiments by the Bureau of Mines, the hot gas recycle reactor developed for the production of liquid fuels has been shown to be an excellent method for producing methane. Moreover, iron lathe turnings which are less sensitive to sulfur poisoning and cheaper than nickel catalysts, can be used to produce a gas with heating value of 800 B.t.u. per cubic foot or more at pressures of 400 p.s.i., 340 F., and hourly space velocities of 800 to 1,000. If a gas of higher heating value were needed, the product from the iron catalyzed reaction could be passed over a Raney nickel catalyst to bring the heating value up to approximately 1,000 B.t.u. per cubic foot. This method of producing gas requires much less expensive nickel catalyst. The heat release problem in the nickel catalyst reactor would be much reduced because high concentrations of methane and low concentrations of synthesis gas are treated.

In the United States, tar and light oil recovered at high- temperature carbonization plants are the only chemicals produced in significant amounts from coal. The production of many of these same chemicals from petroleum is increasing each year, and the petrochemical industry has had an important impact on coal chemical prices. Future production of chemicals from coal by carbonization or some other method will depend largely on whether the competition from the petrochemical industry can be met.

The production of chemicals from coal by extraction, oxidation, and other methods, and by low-temperature carbonization is discussed elsewhere in this paper. Two other methods can be used to make chemicals from coal. Synthesis gas, made by the gasification of coal, can be reacted over catalysts at different process conditions to make a variety of organic chemicals. Presently in the United States, synthesis gas is used commercially to make ammonia and alcohols, but all new installations in the last 15 years have used natural gas as the raw material. Whether coal will be used again to supply this market will depend upon the future cost of natural gas, at any location, compared with the cost of producing synthesis gas from coal by gasification. Improved and more economic coal gasification processes are, therefore, extremely interesting not only for producing liquid fuels and high-B.t.u. gas but also for manufacturing ammonia and methanol.

The other method of producing chemicals will be as a byproduct from plants making liquid fuels by the Fischer-Tropsch or direct hydrogenation process, when such commercial plants become economic. In a typical Fischer-Tropsch plant, 15 percent of the product could be water soluble alcohols (methanol to pentanols and higher), aldehydes (acetal to butyral), ketones (acetal to methyl butyl), and acids (acetic to valeric and higher), but if there were demand for these chemicals, the operation could be adjusted or the catalyst.could be changed to produce an even greater percentage of the plant products. For example, using a nitrided catalyst results in producing 40 percent of the product as alcohols. Chemical credits, however, will prove to be difficult to obtain because one 10,000-bbl, per day Fischer-Tropsch plant, supplying about 0.1 percent of domestic petroleum demand, would produce 216 million pounds of chemicals per year. Some of the chemicals produced by this one small plant would exceed their current market demand.

A similar economic situation exists for chemicals produced from coal hydrogenation plants, although aromatic the chemicals are made rather than the aliphatics produced in/Fischer-Tropsch process. A 10,000-bbl. per day plant, using an Illinois No. 6 bed coal, would produce 572 million pounds of phenols (carbolic acid to xylenol) and aromatics (benzene to naphthalenes). This one plant would supply 5 percent of the phenol requirements of the United States and more than the present market requirement for some of the other chemicals.

In 1952 Union Carbide Co. announced the development of a one-step process for hydrogenating coals directly to aromatic chemicals, using short residence times. No commercial plants have been constructed, but it is reported that Union Carbide and other chemical companies are still doing basic research on developing cheaper methods of producing chemicals from coal.

Techniques to prepare a formed coke are not used as yet in the United States, but research and development in foreign countries have resulted in commercial use of this method of producing a metallurgical fuel. In Australia a brown coal is being dried to 15 percent moisture and briquetted under pressure without the use of binder. The resulting briquet is carbonized slowly in three stages of heating over a period of more than 20 hours, using a hot inert gas for carbonization. Despite a 52 percent shrinkage of the briquet, a strong metallurgical fuel is produced.

In Germany, preparing a strong hard briquet to produce a satisfactory metallurgical fuel has been emphasized rather than relying on special treatment during the carbonization step. Low-rank coals or chars are crushed and briquetted at optimum conditions to produce the hardest briquet possible and then carbonized at 900 to 1,000 C. Every effort is made to increase the density and strength of the briquet before carbonization is begun.

Also in Germany, coke breeze is converted into a metallurgical fuel by briquetting it with a mixture of 7 to 8 percent tar and 10 percent bituminous coal. The resulting briquet is then carbonized at 900 to 1,000 C.

In the United States the Bureau of Mines has conducted tests directed toward making a satisfactory metallurgical fuel from anthracite fines briquetted with bituminous coals and coal tar pitch and then calcined for 3 hours at 1,750 F. Good briquets can be made with many different proportions of bituminous coal and pitch. The effects of such variables, of coal-size consist, binder, briquetting pressures, and calcining temperatures have also been studied.

To successfully carbonize the strongly coking coals of the Eastern United States at low temperature, their coking properties must be altered. Many methods have been suggested for this purpose although all the operations are costly. At the present time, there is renewed interest in destroying these coking properties because a noncoking-sized coal is required for either dry-ash or slagging fixed-bed pressure gasification, and this method now seems to be the most economic process for the complete conversion of coal to synthesis gas and for direct hydrogenation to high-B.t.u. gas in fluid-bed reactors.

Coking properties of coals can be destroyed by oxidation at elevated temperatures, but if large lumps are pretreated in this way, only surface coking properties are affected. If the oxidized lump coal is recrushed and new unreacted surfaces are exposed, the coal again becomes coking. Moreover, the oxidation technique is relatively costly because long residence times are required. For example, a 1/8- by 3/8-inch Pittsburgh seam coal requires 50 hours of oxidation at 250 C. to destroy its coking properties. Even at 390 C., which approaches the softening temperature of the coal, 3 hours are required and at these higher temperatures considerable volatile matter is lost.

The degree of pretreatment required to prepare a suitable feed for a fixed-bed gasifier will probably be even more severe because exposure to hydrogen at high pressures tends to reverse the oxidation process and to restore the coking properties of coal. The Bureau of Mines is now testing to determine the degree of pretreatment that coal will require when exposed to a mixture of CO and H2 at the pressures used in fixed-bed gasification. In another series of tests the effect of oxygen concentration in the oxidizing gases on the rate of destruction of coke properties will be studied.

Demand in the United States for smokeless fuels that meet air pollution regulations is limited, but in other countries a smokeless solid fuel made from indigenous coals has a good market potential. A small market for the smokeless fuel produced from several commercial low-temperature carbonization processes (Phurnacite and Rexco) has existed for a number of years in England, A process using low-volatile coals and a pitch binder was described under the section, Low-Temperature Carbonization.

Two other processes to make a suitable smokeless fuel have been investigated extensively in the last several years in England. In both processes, a char is made first by low-temperature carbonization of a high-volatile coal. In one process hot char is briquetted without binder by the shape principle, a briquetting operation that uses a shear compression. In the other process, briquetting the hot char with a minimum amount of binder forms a briquet that is satisfactory yet smokeless; a pilot plant to produce 120 tons of fuel per day is now under construction in England.

Research is now being conducted in England to produce a briquet from anthracite fines suitable for use in small boilers employed for domestic hot water and central heating. In this process the anthracite is heated to 530 C., mixed with pitch and coking coal, and briquetted at 430 C. This treatment produces a fuel with satisfactory strength and combustion characteristics.

Other foreign countries also are interested in producing a smokeless fuel for use in open grates for heating or cooking. Experiments in several countries to prepare a smokeless product from low-rank or high-volatile coals have used approaches similar to those being tested in England.

Anthracite and coke breeze have been used for many years to sinter flue dust recovered at blast furnace operations. The use of magnetic taconites, which requires that the ore be ground to very fine sizes before it can be beneficiated, made necessary the development of a method to reconstitute the recovered iron and to make a suitable charge for the blast furnace. Finely ground ores are first pelletized with the addition of binders and then hardened in an oxidizing atmosphere. This hardening can be done in shaft furnaces, continuous chain grates, or chain grate-rotary kiln combinations. In the shaft furnace an external source of heat must be used and between 800,000 and 1- million B.t.u.s per ton of pellets must be supplied when hematite is charged. Less B.t.u.s per ton are required when magnetite is the raw material. In this method of hardening pellets, coal can be used as the source of heat.

A better charge to the blast furnace would be a pellet which, instead of being hardened in an oxidizing atmosphere, was hardened in a reducing atmosphere during which some prereduction of the pellet would take place. In pilot plants, several processes have been investigated to obtain such a prereduced pellet. The Dwight-Lloyd-McWane, Orcarb, and Freeman processes all produce either iron or sponge iron from pellets into which coal in some form has been incorporated. Other new processes for reducing iron ore also use coal but generally as the source of heat for a kiln or as the source of the reducing gas for producing the sponge iron or iron product.

The Bureau of Mines is currently investigating a process, in which lignite or lignite char would be added externally to the pellet and would produce a partly upgraded iron pellet of only 80 percent iron (contrasted with the 90-100 percent sought for other processes) and hard enough to withstand transport. The use of carbon from lignite for this purpose would be particularly attractive because the lignite deposits are nearer than other coal deposits to the iron ore deposits.

Many methods to process coal other than the foregoing have been suggested, and some have been tested in laboratory and pilot plant scales. Because coal is so cheap, less than cent per pound at the mine, it is a potentially attractive raw material for many uses. At present, however, there is still only very limited commercialization of any of these processing methods not only in the United States but also abroad where competing raw materials are relatively more expensive. Very attractive economic possibilities exist, however, because the finished products sell at many times the price of the coal used.

Coal has been subjected to many oxidizing agents, and uses for the humic acids produced have been investigated extensively. The caustic soda-oxygen oxidation appears to be the most attractive, and the acids produced have been reacted with polyamines and alkanolamines, which on further heating form a strong heat- and water-resistant resin. The humic acids produced by the oxidation also appear to.be satisfactory for the warp sizing of many synthetic fibers.

Nitric acid oxidation of bituminous coal in laboratory tests have shown that the potassium and ammonia salts of the humic acids produced may be a satisfactory fertilizer. A semi-plant-scale process is being tested in Japan.

Recently, use of humic acids produced by oxidation to prepare a very low-ash char, which could be used for electrode carbon, has been proposed. In this process the humic acids would be reacted with alkali and the soluble salts would be separated from the ash, reprecipitated, and then carbonized to produce a tar and low-ash char. As yet, this process has not been applied commercially.

Naturally oxidized lignite (leonardite) is used as an additive to stabilize drilling muds, and it has been shown that oxidation of lignite can produce a material with the same properties as leonardite. This process may prove to be a more economic source of drilling mud additive in oilfields that are remote from the leonardite deposits and near to sources of other lignitic coals that could be oxidized satisfactorily.

Research is under way at the Bureau of Mines to react coal with different chemical reagents, such as alkali metals and metal amines, to see if useful products can be produced. At the same time, studies are being started that may lead to using coal as the source of carbon for producing such chemicals as hydrogen cyanide, carbon disulfide, carbon black, and acetylene.

The reactions of lignite or of humic acids produced from any kind of coal with ammonia to form a fertilizer is being actively investigated in several laboratories in the United States and abroad. Ammoniated lignite or coal might be particularly Beneficial because it could serve not only as the source of nitrogen but as a soil conditioner.

The reaction of lignite and bituminous coals with sulfuric acid apparently produces a resin suitable for treating hard water, comparing favorably with other ion exchange materials. One manufacturer is reported to be producing this material commercially. A similar ion exchange material made from any kind of coal has been reported from India. This material is made by nitration and reduction and may find use in water softening or other special purposes, such as extraction and recovery of metals in analytical work.

A Wyoming subbituminous coal has been hydrolyzed, using caustic soda, and many potentially valuable chemicals have been identified, indicating that such a process may be used for converting this rank of coal to chemicals.

Work in England on reacting coal with gaseous trifluorides has resulting in forming liquid products similar to those of commercial fluorocarbons. No commercial production has been reported, but the products can be considered for use as hydraulic fluids, high-temperature lubricants, and other applications, when high-thermal stability is important.

Considerable research effort has been devoted to testing different solvents to upgrade coal. Commercial applications of some of these solvents have been made in some foreign countries,, and a few industrial developments have resulted from research in the United States. In Germany coal is extracted at elevated temperatures with coal tar and then filtered to produce a material that can be carbonized to form a low-ash carbon suitable for electrode production. A series of patents have been issued in Japan for producing electrode carbons by treating coals with an organic solvent at elevated temperatures.

Montan wax is produced commercially in the United States by extraction of a California lignite deposit using petroleum solvents and producing 280 pounds of crude wax per ton of lignite. The resins and waxes from a Utah coal have been extracted and are being used to produce satisfactory dielectric enamels. Five to seven percent of the coal is recovered in the extract. In England a research program to extract montan wax from lignite and peat was not successful, but the higher molecular weight compounds that were extracted appear to be a possible raw material for plastic production. Research toward developing such a process is now underway in Ireland.

To find another method of producing chemicals from coal, research at Pennsylvania State University has been directed toward showing that solution of the coal with aromatic oils may lead to a direct production of aromatic chemicals from coal.

At one plant in the United States activated carbon has been produced commercially from a Texas lignite for almost 40 years but no other commercial operations have been reported as using other lignites. Bituminous coal is reported to be used for manufacturing granular activated carbon in at least two plants.

Research aimed at reducing the sulfur in coke by adding a chemical to the raw coal during carbonization was conducted at Pennsylvania State University, but no success was reported for the different compounds tested.

Several organizations have attempted to dissolve coal in either coal tar road oils or in asphalt to produce a cheaper or more satisfactory road-paving material. No commercial applications have been reported.

Lump anthracite has been calcined under a variety of conditions to produce a metallurgical fuel for blast furnace use, and laboratory tests of its physical properties indicate that this product may prove to be a satisfactory metallurgical fuel.

Briquetting of coal fines in the United States and other countries to make effective use of coal or coke fines produced either in mining or during transportation is widely practiced. Coal or coke breeze is briquetted with a petroleum asphalt binder and sold for domestic use.

The conversion of coal refuse to useful products serves a twofold economic purpose it produces income and eliminates disposing of the waste product. Using the waste or upgrading the byproducts from coal preparation plants and from the carbonization and combustion of coal has been a goal of the coal industry and its consumers for many years. Fly ash is used widely as a pozzolanic material for concrete manufacture in the United States and abroad. Fly ash is also used in manufacturing lightweight aggregates, in producing cinder blocks, as a drilling mud additive, and in combination with lime as a soil stabilizer and road base material.

Sintering of the refuse from coal preparation plants to produce a lightweight aggregate is practiced commercially at several plants. The use of cinders from coal combustion furnaces in cinder block manufacturing and the use of slag from wet bottom furnaces for road construction and for other purposes is growing.

Coal refuse is reported to be used atone plant to prepare aluminum sulfate by reacting the refuse with sulfuric acid, filtering the iron and aluminum sulfate solution from the refuse, and separating the two sulfates by fractional crystallization.

Carbon dioxide produced during the combustion of coals is being used to produce dry ice. Recovering sulfur dioxide from flue gases of boiler plants has been proposed, although no commercial plants are in operation.

study on a multifunctional energy system producing coking heat, methanol and electricity - sciencedirect

A multifunctional energy system (MES) capable of consuming coke oven gas (COG) and coal, and simultaneously producing coking heat, methanol and electricity, was subject to an exergy analyses based on Energy Utilization Diagrams (EUDs). In this system a coal-fired coke oven is adopted to produce coke and COG, where non-coking coal is burned to supply thermal energy to the coking process. The COG and coal gas gasified from coal in a gasifier, were mixed to produce syngas for methanol synthesis. Since COG rich in hydrogen and coal gas rich in CO, the mixture of COG and coal gas can easily adjust the mole ratio of CO to H2 of syngas instead of the conversional reforming and shift processes. The active component of syngas is firstly converted into methanol and then the rest is introduced to a gas turbine for power generation. As a result, the overall efficiency of the MES system is about 62.3%, and its energy savings ratio is about 15% comparing with individual systems. The paper provides a new approach to use coal more efficiently and cleanly.

carriage of coal cargoes: self-heating and explosion risks - skuld

Members will be aware of the issues involving self-heating and methane emitting coal cargoes and the enclosed articles provide advice on how to avoid such situations occurring in the first place and how to deal with problems arising during the voyage.

Members will be aware of the issues involving self heating and methane emitting coal cargoes,which have recently been originating from Indonesia. The logistics of dealing with coal cargoesapply to all regardless of origin.

Coal has its origins as vegetable matter which has been subjected to heat and pressure overtime. It is primarily composed of carbon with variable quantities of other components and it ischanges in the proportions of carbon to the other components which describes the coal rank.As the rank increases, which is as a result of the effects of increasing pressure and temperatureover millions of years, so too does the calorific value. Peat is the precursor to coal and isusually considered the lowest rank as it clearly shows the remains of plants. Lignite or browncoal, is the next lowest rank followed by sub-bituminous coal which is usually dark brown toblack. Sub-bituminous coal is utilised for heating, steam-electric power generation and as animportant source of light aromatic hydrocarbons for the chemical industry. Bituminous coal is ablack coal and is one most people are familiar with as it is primarily used as a fuel in both openfires and in steam-electric power generation and manufacturing. It is also in coke production.The highest rank of coal is anthracite which is a hard glossy black coal primarily used forresidential and commercial heating.

Most coal deposits in Indonesia are relatively young as coals go and it is the length of timeavailable for coal formation which determines the coal rank with this process called'coalification'. Most Indonesian coals are brown coals, i.e., lignite to sub-bitumious coal, withthe rest being black coals, and many of the shipments we have seen are blended to achievethe requirements of the purchaser. Indonesian coal is known to have low dust and sulphurcontents and these are very desirable properties e.g., burning low sulphur steam coal producesless sulphur dioxide. However, lower rank coals have higher volatile contents and manyIndonesian low rank coals have high resin contents both of which are undesirable. Coalreserves in Indonesia are found in various areas of Sumatra, Kalimantan, Java, Sulawesi andWest Papua. The largest deposits are found in South Sumatra, East Kalimantan and SouthKalimantan.

During the coal forming process, gases like methane can become trapped in the coal (and canbe 'tapped off' as a resource separate from the coal). This feature represents a significantoperational and transport hazard. Coal and related cargoes are fuels which undergocombustion. If coal undergoes spontaneous oxidation and the energy released by this processis trapped and not dissipated to the environment, it is known as self-heating. As a result the temperature rises and this may progress to full combustion of the coal and as a consequencestockyard and coal seam fires are well documented. Self-heating of coal can result insecondary hazards, which include the production of carbon monoxide as well as other toxic andflammable gases. In addition, any form of combustion consumes oxygen, so extreme careshould be taken when dealing with coals and related cargoes as they are oxygen depletingmaterials. As a general rule, the higher coal rank products tend to be methane producing coals,whereas the lower rank ones are those prone to self-heating. However, in some ports, Shipperssometimes blend self-heating and methane producing coals.

The commercial names for some coals (often used on Bills of Lading), such as steam or thermalcoal (grades of sub- to bituminous coal), and metallurgical or coking coal (bituminous andanthracite coal) reflect their end use rather than their coal rank (manufacture of steel andburning in power stations, respectively).

Regardless of the trade name for the type of coal, there is only one COAL entry in the IMSBCCode (the Code), so we would expect all coal cargoes should be listed on the cargodeclaration as coal. The Code provides a reasonably comprehensive set of instructions for thesafe loading of coal cargoes and we would refer all parties to this entry in the Code.

Coal is usually shipped in the form of lumps, but some are very fine grained (called 'fines') andmay exhibit liquefaction characteristics, hence these require further loading controls in the formof a Transportable Moisture Limit Certificate (TML) and a Moisture Content (MC) Certificate.The IMO has put guidelines in place on how shippers can monitor their moisture controlmethods, and the Competent Authority of the Port of Loading is now required to supply anadditional certificate which details their approval of these methods.

Another coal-related cargo is listed as COAL SLURRY, and this also consists of fine coalparticles, often washed off larger lumps. Since this too can liquefy, it requires a TML Certificateand MC certificate prior to loading.

Shippers are required to provide a cargo declaration stating if the cargo has a history of selfheatingor methane emission. If it does not, ask shippers again as both these properties arecommon in Indonesian coals, with self-heating especially so.

All coal cargoes will require monitoring during the voyage. This will take the form oftemperatures and gas readings for each hold. As indicated above, all vessels intending to carrycoal are required to have appropriate gas monitoring equipment for the duration of the voyageand it is important that this equipment be in good working order with an up-to-date calibrationcertificate prior to the commencement of loading. Since gas monitoring is a requirement of theCode for coal and some related cargoes, it is very important to know how the ships gas meterworks BEFORE loading starts.

Gas meters come in many different types and makes, with some having an inbuilt pump to drawthe gas sample through a sampling tube inserted into the hold headspace though the gassampling port and over the gas sensors inside the instrument. Others do not have this facilityand require a rubber bulb type hand-pump positioned in-line between the end of the samplingtube and the gas meter to draw the headspace gases through the meter. Once a reading hasbeen taken, it is also important to ensure that the meter returns to reading normal gas levels infresh air before attempting to take the next measurement i.e. oxygen 20.9%, carbon monoxide0%, %LEL (lower explosive level) 0%. It is also important to prevent dust and moisture fromentering the gas meter as these can damage the sensors and consequently, an in-line filter isuseful in this respect.

Access to the headspaces via the gas sampling ports enables assessment of the gas levelswithout opening the hatch covers so that oxygen (O2), methane (CH4) and carbon monoxide(CO) levels can be reliably monitored. It is also extremely important to know which gases arebeing checked and why:

Carbon monoxide (CO) this gas is produced when self-heating or combustion occurs at lowoxygen levels. This gas has no smell and is a silent killer because it binds to haemoglobin inthe blood 200 times more strongly than oxygen thereby shutting down blood oxygen transportleading effectively to suffocation.

Methane (CH4) is a gas released by some coals, so an increasing level indicates the coal isemitting CH4 and needs to be closely monitored. If the concentration increases to reach 20% ofthe lower explosive limit (LEL), ventilation is required.

It should be noted that most of the commonly used multi gas meters encountered onboard shipswill not be reliable for hydrocarbons or other flammable gases at low oxygen levels - in fact theywill not work properly below about 12% O2 values. This is because most gas meters usecombustion sensors which require oxygen to function properly and to produce reliablehydrocarbon/flammable gas readings.

If shippers declare there is no history of self-heating, then prudent action would be to monitorthe cargo temperature carefully and not to load any coal with temperature above 55C. If thecoal temperature is already at 55C, then it has probably been mis-declared anyway.

The reason for having a maximum cargo temperature limit is the recognition that the selfheatingreactions are like any chemical reaction in that the rate of reaction approximatelydoubles for every ten degree rise in temperature. Thus once coal gets to about 55C, the rate ofthe self-heating reactions will be such that potentially the coal can heat relatively quickly to thepoint of self-ignition. Generally if the cargo temperature is below 55C then there will besufficient time to load the cargo, monitor it and to restrict oxygen such that the self-heatingreactions are stifled and the coal cannot attain the high temperature required for ignition.

If the coal is declared as having a past history of self-heating and/or emitting methane, thisshould be given in writing via the cargo declaration. These characteristics do not preclude thecarriage of the coal, but dictate its handling and monitoring during loading and the voyage.

If the coal on any barge is found to have temperature in excess of 55C then it is theresponsibility of the shipper to either cool such cargo down by rotating it using bulldozers or toensure such coal is not loaded onboard. This will require policing by the crew by way ofchecking temperatures regularly or local surveyors if they have been appointed. We add that itis possible to cool coal down by rotating it and/or turning it over and we in fact have hadexperience where this has been done effectively such that the cargo temperature wassubsequently found to be below the 55C limit and was therefore acceptable for loading.

The Code recommends that pre-loading checks on the temperature are conducted. If shippersdo not give any indication that the coal may self-heat, some may question why such monitoringwould be necessary. Unfortunately there is a long history of shippers not telling the truth, orsimply not realising that the information is required, or what the consequences might be for aship in the event that the cargo self-ignites. After all, if a stockpile onshore catches fire, it iseasier to deal with.

We recommend therefore that prior to loading the temperature of the nominated cargo shouldbe checked. This may be difficult in Indonesia where much of the coal is transferred frombarges, so monitoring temperatures of the cargo prior to it being transferred to the vessel willlikely require the coal on the barges having to be checked.

Ideally, a thermocouple probe and thermometer should be used, but it can be difficult to pushsuch a probe into coal. Therefore if it is difficult or none is available, then an Infra-Red (IR)thermal spot temperature device could be used. These are becoming relatively cheap so couldbe made available to each coal-carrying ship. However these instruments have a number oflimitations, such as they are not particularly accurate and they can only record surfacetemperatures, so rechecking the cargo below the surface is vital, i.e., once it is disturbed by thegrabs and by checking the temperature of the freshly exposed surfaces of the stow. Inaddition, the shippers might have temperature sensors on the loading conveyors, so these couldbe monitored if access is granted.

Because the monitoring of temperature may necessitate loading being stopped, it is importantthat the results of the cargo temperature monitoring operation are carefully recorded. Surfacetemperatures are a good place to start, and if these are already above 55C (given as themaximum temperature acceptable for loading in the Code), then the cargo would appear toalready be self-heating and does not meet the carriage requirements. To take furthertemperature readings, the stow on the barges (on stockpiles, if ashore), should be taken fromwithin the pile, i.e., it requires digging into the pile to access the inner parts of the stow.

Self-heating can be very localised in a pile of coal, therefore many pits will need to be dug toestablish the temperature throughout the whole of the stockpile/barge-load/stow. This way, aclear picture of the temperature profile of the cargo can be obtained. It may be possible to usean IR thermometer to check the freshly exposed surfaces after a grab-load is removed and ifnecessary stop it reaching the holds if the temperature proves to be above 55C in the innerparts of the stow.

Then the monitoring and management of the cargo during the voyage becomes important. Evenif the cargo was loaded with temperatures below 55C, this does not mean that problems willnot start during the voyage.

As temperature sounding pipes are located within a hold, but at the periphery, any temperaturereadings can only provide a general indication of the temperature of the cargo near the pipe andwill provide no information concerning what the cargo temperatures are elsewhere in the hold.Consequently, gas measurements are the preferred and most reliable method for cargomonitoring during a voyage.

Access to the headspaces via the gas sampling ports enables assessment of the gas levelswithout opening the hatch covers so that oxygen (O2), methane (CH4) and carbon monoxide(CO) levels can be reliably monitored. It is also extremely important to know which gases arebeing checked and why:

Carbon monoxide (CO) this gas is produced as a result of self-heating/combustion occurringat low oxygen levels. This gas has no smell and is a silent killer because it binds tohaemoglobin in the blood leading effectively to suffocation.

Methane (CH4) is a gas released by some coals, so an increasing level indicates the coal isemitting CH4 and needs to be closely monitored. If the concentration increases to reach 20% ofthe lower explosive limit (LEL), ventilation is required.

It should be noted that most of the commonly used multi gas meters encountered onboard shipswill not be reliable for hydrocarbons or other flammable gases at low oxygen levels - in fact theywill not work properly below about 12% O2 values. This is because most are actuallycombustion sensors and need oxygen to function to produce reliable hydrocarbon/flammablegas readings.

Changes in the gas concentrations will indicate whether self-heating/combustion, or methaneemission, is taking place. All vessels intending to carry coal are required to have appropriategas monitoring equipment for the duration of the voyage and it is important that this equipmentbe in good working order with an up-to-date calibration certificate prior to the commencement ofloading. Since gas monitoring is a requirement of the Code for coal and some related cargoes, itis very important to know how the ships gas meter works BEFORE being faced with anemergency situation. Please see first advisory for further details on gas meters.

Having loaded a Code-compliant coal, the shipment should be monitored for gas variationsduring the voyage. The Code indicates that if there is no declaration of any hazards such asself-heating or methane emission, then the holds should be ventilated for the first 24 hours.During this time, the gas in the headspace of the holds should be monitored and this will requirethe ventilation to be stopped for a suitable period (the Code recommends this is not less thanfour hours) prior to the gas readings being taken. Assuming no methane is detected or if it is, itremains at very low levels, then the holds should be sealed and gas monitoring continued.

Self-heating/combustion will be evident if high (and increasing) CO levels are detected incombination with decreasing oxygen levels. If the CO increases but the oxygen does notdecrease, then this indicates that the holds are not sealed effectively. If necessary, Ramnecktape and expanding foam should be used to assist with the sealing of the holds, but these canonly be used as a last resort because cargo holds are not designed to be gas tight.

The Code indicates that CO levels above 50 ppm are an indication that the cargo may be selfheating.Even when sealed and oxygen supply is restricted, the CO levels in the headspaceabove a self-heating coal could exceed 500 ppm (some gas meters cannot measure levelsabove this, so the actual value may be higher). The CO levels should 'level out' as the oxygen isused up and as long as no methane is detected (or if the methane levels remain below the limitsin the Code, see next section), then the holds should remain sealed until each hold is ready todischarge.

If gas levels indicate self-heating is taking place the only thing which can be done is to limit theamount of oxygen available in the holds. Since self-heating/combustion requires oxygen, if theholds are sealed then the oxygen level should fall to the point where further combustion isprevented from occurring.

Methane and other flammable gases are often emitted from coals. The reaction of coal withoxygen results in self-heating/combustion and can also release flammable gases from the coalpossibly generating an explosive atmosphere, although in our experience this is quite rare.

In the reaction between methane and oxygen, twice as much oxygen as methane is required forthe perfect match, and since the oxygen content of air is about 21% by volume, then theamount of methane required for the most violent reaction is around 10%. Mixtures of between 5to 15% methane in air are explosive mixtures. While sealing the hatches and stoppingventilation should control or restrict self-heating/combustion, if the coal starts emitting methaneor other inflammable gases, then these may require removal in order to prevent development ofa potentially explosive atmosphere. In this situation, the only option would be to open the ventsbut we would strongly recommend seeking expert advice in this situation.

To assist with safety assessments, it is important to know what the lowest explosive limit or LELis for a given gas mixture. For methane, the LEL is 5%, i.e., the lowest amount of methanemixed with air that can be explosive. However, for safety reasons, the IMSBC Code COAL entrystates that the amount of methane in a hold, which is considered as the trigger point for actionby the master, is 20% of the LEL - therefore this is actually equivalent to only 1% methane in air(volume by volume). The gas concentrations should be monitored and a record kept, since theirlevels will determine the advice given by an expert. If oxygen levels drop and stay low, even ifmethane levels are high, then there is unlikely to be an explosion. However, if methane is above20% of LEL, then ventilation may be advised.

Usually fires in coal are small and rarely become 'raging infernos'. However, they do tend toproduce lots of smoke and toxic gases. If the coal or related cargo appears to be on fire addinglots of water to a hold fire is not a practical option. The added weight of the water may damagethe ship by over stressing the hold plating (stresses and bending moments will need to beconsidered). Equally impractical is that to discharge a hold full of dirty, contaminated, andpotentially acidic water is going to be difficult and expensive due to environmental concerns.Unless all the cargo is fully submerged, it will not usually put the fire out.

However, water can be used to cool the grabs used for the discharge and help control thesmoke by dowsing the smouldering/burning areas so that once the majority of the cargo isremoved, flooding the remaining amount to extinguish the fire might be an option. Bulldozersand their drivers cannot be put into a hold to move the cargo to allow access for the grab if theair or the cargo is too hot, the air in the hold is lacking oxygen, and/or has unsafe carbonmonoxide levels. It is likely to be very impractical if not impossible to find stevedores who aretrained to operate and discharge cargo in full breathing apparatus.

If the ship is still at sea, the main logistical challenge will be to stop oxygen entering the holds.An alternative option may be to use inerting gas such as carbon dioxide or nitrogen but thesemay not be available or may not be available in sufficient quantity. Seek expert advice ifconsidering the use of inerting gases. Boundary cooling of the external parts of the hold will atleast cool the coamings and deck surface and so assist with access. If sealing the holds tostarve the fire of oxygen does not work, the only option will be to discharge the cargo.

The main problems associated with discharging a self-heating cargo of coal are associated withthe fact that even for a small localised area of smouldering, burning coal, a considerable amountof smoke will be generated. This smoke accumulates in the headspace of the hold and will bereleased en-masse when the hatch covers are opened thereby appearing to make the situationworse than it really is. In our experience this frequently causes undue concern with theReceivers and has resulted in some coal terminals refusing to discharge the cargo despite thefact that it was the hatches being opened which introduced fresh supplies of oxygen into thecargo holds to support continued self-heating/combustion. We recommend therefore that thehatch covers are only opened when there is agreement to discharge the cargo directly. Untilthat point, they should remain firmly sealed such that exposure to oxygen is restricted.

The best way to deal with such a situation is to have the area of smouldering or burning cargoremoved but obviously this requires the area to be accessible and for it to be safe, in terms ofcarbon monoxide levels, to enter the hold to remove it. Localised spraying of fresh water todampen down such areas is recognised as a temporary solution but excessive use of watershould be avoided since any significant increase in the moisture content of the cargo will reducethe calorific value of the coal somewhat. In addition, if the hot area isnt removed but remainsexposed to oxygen then it is likely to re-ignite within a matter of hours or days. Any water usedfor firefighting should be fresh water rather than seawater if at all possible since Receivers rarelytolerate chloride contamination as it can potentially cause corrosion to the power station boilerswhen the coal is ultimately burnt.

In terminals where the coal is discharged to conveyor lines, Receivers and Terminal Operatorsmay be reluctant to put hot coal onto their belts for fear of damaging them i.e., melting therubber, or worse, setting fire to them. Since coal fired power stations are dependent upon acontinuous supply of coal, damage which renders the conveyor system inoperable for any lengthof time will be of real concern to the Receivers, despite the likelihood of such damage occurringbeing remote. In addition, the use of water in firefighting can also affect the cargo handlingproperties of some coals and when wetted, they may become 'sticky' and difficult to dischargeonto conveyor lines.

Once discharge of a self-heating coal cargo commences it is important that the holds aredischarged completely and in a timely manner since part discharged holds have a largerreservoir of oxygen in them with which to feed the self-heating reactions in any remaining cargostow. This can cause ignition or re-ignition of 'hot spots' within the stow. Obviously whether ornot the Terminal suspends discharge for any reason is likely to be beyond the control of theMaster and crew but there have been a number of cases where part discharged cargo holdsignited whilst the vessel waited at the anchorage for completion of discharge. If such a situationarises, all that can be done is to attempt to restrict exposure of the cargo to oxygen as much aspossible by closing all the ventilators etc., and for the monitoring of the headspace gases tocontinue. Providing the vessel has done all that it can to prevent self-heating within the stows byrestricting exposure of the cargo to oxygen throughout the voyage, then ignition of the cargoduring discharge, if it does occur, is beyond the control of the vessel and simply due to theinherent nature of the coal. Unfortunately though, this will not always prevent claims against thevessel.

Finally, Receivers may also take issue with the smoke produced from burning coal, partly as thismay restrict stevedore access to the holds, and partly due to the environmental impact. Careshould be taken to ensure that once discharge starts (in a problem coal) that it is completed, andthat partly discharged holds are not left open.

When discharging hot, methane emitting coal and related products, additional care will berequired because the opening of the hatches will allow oxygen to enter the holds and whenmixed with the methane could potentially result in an explosion. Ensuring there are NO ignitionsources around the holds and the hatch cover wheels are greased should reduce the possibly ofsparks igniting the methane and oxygen mixture. Seeking expert advice will be critical prior tostarting the discharge process.

Initially, it may be suggested that the gases are vented off via the hatch cover vents however thisallow oxygen to enter the holds. Equally, it may be advised that an inerting gas is pumped intothe hatches just prior to opening. This will reduce the risk of an explosion occurring by flushingout the flammable gases via a second open vent. This should only be considered with expertadvice.

Having fire fighting personnel on standby may be required to both assist in the event of anincident as well as to spray the cargo with water once it is onshore. Spraying a small amount offresh water onto the area of concern may enable this patch to be removed by the grabs. However, once the discharge has reached the limits of the grabs, then the gas levels mayrestrict personnel e.g., the bull dozer driver, from entering the holds.

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