Gasification Introduction

Transcription

1 7.3 Gasification Introduction In the gasification process, any carbonaceous material is converted into a gas, called synthesis gas or syngas, consisting mainly of carbon monoxide (CO) and hydrogen (H 2 ). This gas may be used either as a fuel to generate electrical energy, or as the base for a large number of products in the petrochemical industry and in the refinery (e.g. methanol, oxo-alcohols, ammonia, synthetic fuels, etc.). Apart from using feedstock, such as coal and heavy residues, gasification enhances lowvalue materials, converting them into gaseous products with a usable heating value and/or into marketable products. Gasification technologies, some having developed as of the first decades of the Twentieth century, differ in many aspects, though they share certain general characteristics. The dominant technology is the partial oxidation, producing a syngas that consists of carbon monoxide and hydrogen in various ratios (the sum of which generally amounts to over 85% of the total volume) and minor quantities of carbon dioxide (CO 2 ) and methane (CH 4 ). Partial oxidation can be applied to solid, liquid or gaseous feeds, such as coal, refinery residues, gas, petroleum coke, biomasses and other materials otherwise regarded as waste. The feed in the gasifier reacts with oxygen typically between 95% and 99% pure in volume (or with air), and/or steam at a high temperature and variable pressure, and under-stoichiometric oxygen. The lack of oxygen justifies the term partial oxidation, which in modern technology distinguishes gasification, and for this reason either term may be used interchangeably. Under these definitions, in any case, only non-catalytic processes are included (whereas steam reforming and partial catalytic oxidation, for example, are catalytic processes). The gas produced through gasification is subsequently cleaned, so that the hetero-elements or other impurities present may be recycled, recovered or discharged. For feeds containing such high quantities of heteroatoms or impurities that they cannot be treated with different processes, the above makes gasification particularly interesting since this technology permits practically the total removal of pollutants from the syngas. Sulphur is mainly recovered in an elemental form, while the cleaned gas can be sent for chemical production purposes and/or be used to produce electricity (Fig. 1). Gasification, especially of coal, is a technology that has long been applied in the industry. It underwent a revival in the 1990s, with a 50% growth in world capacity during that same decade, mostly due to the use of heavy refining residues. At the end of the century, the greatest concentration of gasification capacity was found in the Republic of South Africa, thanks to the Sasol plants (Childress and Childress, 2004). At the turn of the century, Italy occupied third place (following the US and the Republic of South Africa) due to its plants for the production of electrical energy from residues (IGCC, Integrated Gasification Combined Cycle) installed in four refineries. Historically, gasification has been used on a large scale to obtain chemical products and energy vectors from coal via syngas. During the Second World War, Germany obtained high-octane fuels through isobutylic synthesis and diesel oil through the Fischer-Tropsch synthesis. In the post-war period, during the embargo, the Republic of South Africa fully satisfied its requirements of fuels and chemical products through coal-based gasification and Fischer-Tropsch synthesis. These continuously modernized plants are still in operation. However, at the end of the Twentieth century, gasification took on an important new role also in the VOLUME II / REFINING AND PETROCHEMICALS 325

2 DEEP CONVERSION OF RESIDUES Fig. 1. Gasification and its products: simplified scheme. soot removal gas cleanup fuels and chemicals high sulphur fuel oil, refinery tars, petroleum coke, coal, biomass, wastes, natural gas, etc. soot sulphur by-product air compressor shift reactor synthesis gas conversion generator air combustion turbine electric power gasifier oxygen steam air separation exhaust heat recovery steam generator recovered solids steam steam turbine generator electric power production of electricity from coal, since it was regarded as a technology capable of improving the efficiency of coal conversion and was accepted from an environmental standpoint Rudiments of the gasification process Due to the heterogeneous composition of hydrocarbon residues, gasification chemistry is rather complex (Higman and van der Burgt, 2003). Numerous reactions occur, including reforming, combustion, shift and the formation of carbonaceous residues: Reforming (strongly endothermic) [1] C n H m nh 2 O nco ( 1 m n)h 2 2 [2] C n H m nco 2 2nCO 1 m H 2 2 Combustion (strongly exothermic) [3] C n H m (n m 1 4 )O 2 nco 2 m 1 2 H 2 O [4] C n H m n 1 2 O 2 nco m 1 2 H 2 [5] C 1 2 O 2 CO [6] C H 2 O CO H 2 Shift (moderately exothermic) [7] CO H 2 O CO 2 H 2 ( 10 kcal/mol) Formation of carbonaceous residues (soot) [8] cracking (endothermic): C n H m nc 1 m H 2 2 [9] Boudouard (exothermic): 2CO CO 2 C ( 41 kcal/mol) where, for gases (methane), m 4 e n 1 (m/n 4); for oil, m 2 e n 1 (m/n 2); and for coal, m 1 e n 1 (m/n 1). The concentration of the single species as well as the working conditions determine what the main reactions will be. Reactions with oxygen [3], [4] and [5] are essentially complete, as is also the case, substantially, regarding carbon conversion [6] and [9]. In most cases, the gasification temperature (see below) varies from 850-1,500 C, according to the type of gasification and the feed. Lower temperatures minimize oxygen consumption, but slow down the kinetics. In practice, from the kinetic standpoint, in order for the gasification of coal and of petroleum residues to take place at a temperature inferior 900 C, a catalyst would be required; however, this solution is not a practicable one due to the presence of ash, sulphur and various impurities in the feedstock. At the temperatures considered above, hydrocarbon will not be present in appreciable quantities, apart from methane. Above 900-1,000 C, all reactions are very rapid and a thermodynamic equilibrium practically achieved for each. Consequently, the composition at the outlet from the partial oxidation chamber can be reasonably estimated on the basis of the input of C (with hydrocarbon), of H (with hydrocarbon and steam) and 326 ENCYCLOPAEDIA OF HYDROCARBONS

3 GASIFICATION H/C mol in feed oil steam S/C 1.5 carbon formation zone P (H 2/CO-%CO 2) oil O O/C mol in feed 1.5 O 2 /C of O (with steam and as molecular oxygen). The global C, H, O composition of the feed may be represented as shown in Fig. 2, which illustrates the possible input atomic compositions when, together with a hydrocarbon feed, a bitumen or a heavy residue (typically with an atomic ratio of H/C 1), there is an increasing input of oxygen (the line parallel to the abscissae) or of steam (the oblique line). Assuming perfect mixing, each of the possible inputs of bitumen (oil), steam and oxygen will be characterized by a point in the portion of the plane defined by these two halflines. For each given C, H, O input composition, Fig. 2 shows the corresponding equilibrium composition in terms of the percentage of CO 2 and the H 2 /CO ratio Fig. 2. Estimated equilibrium composition of syngas (from bitumen at 1,350 C and 68 bar). Each pair of numerical values in the grid refers to the nearest knot. 3.5 Thermodynamic analysis foresees the presence of numerous compounds. Given point P (indicated in Fig. 2 as the feed), Fig. 3 shows the evolution of the macrocomponents H 2, CO, CO 2, CH 4 and C in terms of temperature. One may note that in the zone of typical temperatures of the combustion chamber, a syngas is obtained with a ratio of H 2 /CO The formation of carbon is not foreseen. Repeating the thermodynamic analysis for various input compositions, Fig. 2 demonstrates that conditions of thermodynamic stability of carbon occur for low H/C and O/C ratios: the figure indicates the carbon formation zone, which would correspond to negative conditions for the operation of the gasifier. In practice, the ideal condition of a perfect and very rapid mix of all feeds does not occur; therefore, there are zones in the combustion chamber where the formation of carbon is possible: in fact, the syngas produced always contains a certain quantity of carbonaceous particulate, referred to as soot. Apart from the above-mentioned macrocomponents, traces of numerous other products can be formed, including formic acid (HCOOH), which makes process condensates corrosive. Most feeds contain other components apart from carbon, hydrogen and oxygen, which are mainly sulphur and nitrogen. Petroleum residues and petcoke (petroleum coke) contain significant quantities of metals (nickel and vanadium). Coal can contain considerable quantities of ash (up to 30-40% in weight), which is the inorganic residue of combustion; ash consists principally of silicon, aluminium, iron, titanium, etc., oxides. Fig. 3. Effect of temperature on syngas. 50 combustion chamber temperature H 2 O CO H 2 H 2 /CO 0.79 % mol C CH 4 CO ,000 1,100 1,200 1,300 1,400 1,500 temperature ( C) VOLUME II / REFINING AND PETROCHEMICALS 327

4 DEEP CONVERSION OF RESIDUES Table 1. Main characteristics of gasifiers Category Moving-bed Fluid-bed Entrained-flow Ash Dry ash Slagging Dry ash Agglomerate Slagging Typical processes Lurgi BGL Winkler, KRW, U-Gas Shell, Texaco, HTW, CFB E-Gas, Noell, KT Feedstock Dimensions 6-50 mm 6-50 mm 6-10 mm 6-10 mm 100 mm Fines acceptability limited more than good better unlimited dry ash bed Coal quality any high low any any Working conditions Outlet gas temperature low moderate high ( C) (900-1,050 C) (1,250-1,600 C) Oxygen requirement low low moderate moderate high Steam requirement high low moderate moderate low Other characteristics hydrocarbons lower conversion of coal pure gas, high conversion in gas of coal Sulphur is converted into hydrogen sulphide (H 2 S) and carbonyl sulphide (COS) in the molar ratio of H 2 S/COS Nitrogen, though present mostly as elementary nitrogen (65%), is also transformed into ammonia NH 3 (25%) and into hydrogen cyanide HCN (10%). In general, the quantities of sulphur and nitrogen are small enough not to influence the balance of the major components (CO and H 2 ); even so, it is necessary to consider the impact of their compounds both on the environment (atmospheric emissions) and with regard to the poisoning of the catalysts in downstream units. The metals present in the hydrocarbon feedstock generate solid wastes: nickel is transformed into sulphide (NiS), while vanadium is obtained in oxidized form (V 2 O 3 ). With soot, both of these compounds form the solid residue that is separated from the syngas. Ashes, on the other hand, are extracted in the melted state (and then cooled and vitrified) or in the solid state, according to the type of gasifier used. Operating parameters The composition of syngas depends not only on the characteristics of the feedstock (elemental composition, heat capacity, presence of ash and moisture, approximate composition). It is also dependant on certain operating parameters such as: the quantity of oxygen per unit of feedstock and/or the quantity of steam per feedstock unit (or, in other terms, the temperature, which depends on these quantities); and the working pressure. In the case of coal, the gasification temperature is generally chosen on the basis of the properties of the ash (melting/softening point): the higher the temperature, the greater the consumption of oxygen. Regarding pressure, one criterion is that of selecting pressure according to the process requirements or those of the apparatus downstream. For example, a synthesis of methanol or a turbogas is generally more economic to compress the feedstock and the oxygen, as opposed to syngas. Should the process downstream require very high pressures, as in ammonia synthesis ( bar), the above no longer applies, being that gasification pressures greater than bar are not practicable. It should be stressed that pressure does not exercise a strong influence on the quality of the syngas, since the temperature is equal; the H 2 CO content diminishes with pressure, but the residual methane increases (Higman and van der Burgt, 2003). Efficiency The two most common criteria for assessing the efficiency of a gasifier are: Cold Gas Efficiency (CGE) (%) (energy contained in gas produced/energy contained in feedstock) 100 (typical values are between 80 and 90%). 328 ENCYCLOPAEDIA OF HYDROCARBONS

5 GASIFICATION Carbon conversion (%) [1 (carbon in gasification residue/carbon in feedstock)] 100 (typical values are between 96 and 99%). In any case, the CGE criterion must be applied with particular regard to the final use of the produced gas: a process that produces gas with a high residual methane content also has a high CGE, and is suitable for use in IGCC. However, if the objective is to produce hydrogen or H 2 CO, the CGE is not significant, while it is necessary to choose the working conditions that maximize these components Gasification processes The heart of the gasification plant is the reactor (or gasifier); various types of gasifiers have been applied industrially in the course of past years and may be grouped together in three main categories: moving-bed gasifiers, fluid-bed gasifiers and entrained-flow gasifiers, according to the relative motion between the feedstock and the oxidant flow. Some typical characteristics of each category are listed in Table 1 (Higman and van der Burgt, 2003), which makes reference to coal as feedstock. For refinery IGCC processes, entrained-flow type gasifiers are used most. Refineries are able to feed gasifiers either with visbroken tar-type residues or bitumens, or with petroleum coke. Moving-bed gasifiers. These consist of a bed on which the coal moves slowly downwards due to gravity, while gasification proceeds. The coal comes into contact in counter-current with oxygen and steam, which are distributed through a rotating grate. With this configuration, there is a temperature profile along the bed with four consecutive reaction zones: drying, volatilization, gasification and combustion. The outlet temperature of the syngas is generally low (approximately 600 C), although in the heart of the bed the ash melting temperature can be reached (2,000 C). The working pressure is around bar. The feedstock of moving-bed gasifiers consists of coal (in pieces of up to 50 mm) with little dust, which, if the coal tends to clog, could block the upward passage of the gas. There are two versions of this gasifier, differing in the way that the ash is extracted; the most common version is the dry ash gasifier. The ash is discharged in solid form at about 1,100 C. The best-known gasifier of this type is based on the Lurgi technology (Fig. 4), largely applied in the Republic of South Africa, the United States, Europe and China. In another configuration, the ash is discharged in liquid form (slagging) and thus at a temperature higher than the melting point (1,200 C). Fluid-bed gasifiers. In the fluid-bed gasifier, ground coal (max size 10 mm) is kept in suspension by the oxygen (or air) stream and steam, which thus has the twofold function of oxidant and fluidifier. The fluid bed ensures an intimate mixing of feedstock and oxidant, thereby improving the phenomenon of mass and heat transfer. According to the velocity of the gas, the fluid bed passes from a stationary regime to a CFB (Circulating Fluid Bed) regime, and lastly to pneumatic transport, appropriately referred to as such (Higman and van der Burgt, 2003). The temperature is maintained below the ash softening point (950-1,100 C for coal and C for biomass), since otherwise the ash would become aggregated and drop to the bottom, with problems of removal. The moderate temperature tends to privilege the use of low-grade coal (lignite, peat) and biomass in fluid-bed gasifiers; these feedstocks are more reactive than high quality coal, which compensates for the kinetic disadvantage due to the lower temperature. steam oxygen coal coal lock coal distributor grate ash lock ash Fig. 4. Lurgi dry ash gasifier. tar recycle steam jacket water jacket wash cooler raw gas VOLUME II / REFINING AND PETROCHEMICALS 329

6 DEEP CONVERSION OF RESIDUES However, some fluid-bed gasifiers exist that permit greater coal conversion by concentrating a high temperature in particular areas. The first fixed fluid-bed reactor used in gasifying coal was the Winkler gasifier, developed in the 1920s, which operated at atmospheric pressure; in the 1970s, this gasifier was modified to operate at a higher pressure (up to 30 bar). In the HTW (High Temperature Winkler) gasifier, presented in Fig. 5, the material is fed under pressure using a pressurized screw feed system. The oxidant flow is conveyed both to the base of the gasifier to keep the bed fluidized, and above the bed to gasify the coal particles entrained. The ash is removed by means of a cyclone separator, while the responsive heat of the gas is recovered in a heat exchanger. Entrained-flow gasifiers. In this category of gasifiers, the feed and the oxidant are delivered in equi-current. In this case, the residence time is very brief (2-5 s), and thus high temperatures are necessary (1,200-1,500 C) in order to obtain good conversion results: this implies greater oxygen consumption than in the two gasifier typologies described above, an extremely small methane residue in the syngas, a high coal conversion rate (up to 99%) and, in the case of coal or petcoke feed, the fusion of the ash (slagging conditions). Practically any solid feed (provided that it is finely ground, 100 mm), pumpable liquid feed or gaseous feed can be used for this type of gasifier. First developed by Texaco in the late 1940s, it has become the most common type in the coal gasification field and amongst the majority of IGCC plants. Working pressures are typically in the range of bar. Within the context of the common characteristics described above, the plants that use entrained-flow reactors have specific features. These include the number of feedstock stages, the manner of supplying solid feed, the flow direction and the cooling system for the syngas produced, as illustrated in Table 2 (Higman and van der Burgt, 2003). Fig. 5. HTW gasifier. product gas coal gasifier secondary zone 1,2000 C cyclone hot dipleg primary zone C lock hopper steam, oxygen ash lock 330 ENCYCLOPAEDIA OF HYDROCARBONS

7 GASIFICATION Table 2. Characteristics of main entrained-flow processes Process Stages Feedstock Direction of flow Gas cooling Oxidant Kopper-Totzek 1 dry down-up heat exchange oxygen SCGP 1 dry down-up gas quench oxygen and heat exchange Prenflo 1 dry down-up gas quench oxygen and heat exchange Noell 1 dry up-down water quench oxygen and/or heat exchange Texaco 1 slurry up-down water quench oxygen and/or heat exchange E-Gas 2 slurry down-up two-stage oxygen gasification CCP 2 dry down-up two-stage air gasification Eagle 2 dry down-up two-stage oxygen gasification Regarding the Texaco process, which uses a slurry feed, down-flow entrained-flow gasifier, there are two basic configurations, according to whether the hot gas from the gasification chamber is quenched directly with water (Fig. 6) or cooled with a radiation type heat exchanger to produce high-pressure steam. The Fig. 6. Texaco quench-type gasifier. grinding and slurry preparation gasification and gas cooling gas scrubbing oxidant water solid feed gasifier particulate-free synthetic gas slurry tank slurry pump quenched syngas particulate scrubber quench chamber recycle (optional) coarse slag sale/disposal lock hopper char clarifier recycle (optional) purge water fine slag and char sale/disposal VOLUME II / REFINING AND PETROCHEMICALS 331

8 DEEP CONVERSION OF RESIDUES Fig. 7. Shell process for liquid feedstock (SGP). BFW, Boiler Feed Water. SARU, Soot/Ash Removal Unit. steam oxygen waste heat exchanger scrubber high-pressure steam raw gas free of soot reactor quench pipe steam BFW carbon separator quench water carbon slurry (SARU) return water vacuum visbreaker residue metals ash excess water quench type is generally more economical, but less efficient. It can be applied to a vast range of feedstock, causing no problems of fouling the exchange surfaces with ash or metals. In the case of coal, the ash is removed from the bottom of the quench chamber in the form of vitreous waste; when using the radiation exchanger, the melted ash solidifies in a water bath downstream of the exchanger, where the gas is cooled to C. In the case of solid feed, the ash is ground to about 100 mm and slurried with water before being pumped together with the oxygen into the gasifier through the feed injector (burner) positioned at the head of the reactor. For liquid feed, however, the feed is preheated to lessen its viscosity and mixed with steam before being pumped through the injector. In view of the low Fig. 8. Shell process for solid feedstock (SCGP). MP, medium pressure; HP, high pressure. MP steam quench gas blower HP steam membrane wall oxygen to gas treatment pulverized coal fly slag refractory slag BFW BFW 332 ENCYCLOPAEDIA OF HYDROCARBONS

9 GASIFICATION ash content, no ash is extracted in the form of vitrified waste; instead, the quench water is simply purged from the circuit to prevent its build-up. The gas leaving the quench chamber is saturated with steam at C, according to the pressure, and is therefore in the ideal condition for subsequent production of hydrogen or ammonia, since it may then be fed to a CO conversion reactor (shift) without any additional steam required. The Shell process has also found widespread application and has two basic configurations: the Shell Gasification Process (SGP) for liquid hydrocarbon feed (Fig. 7), and the Shell Coal Gasification Process (SCGP) for coal (Fig. 8). Both configurations carry out the recovery of the gas responsive heat through heat exchange as well as the production of high-pressure steam; the quench configuration, however, is not present. As indicated in the above-mentioned figures, the flows in the SGP process occur in a down-flow direction (Texaco type), while in the SCGP they are up-flow. In the SCGP process, the feedstock is not slurried with water, but fed directly, in a dry and pulverized state, into the gasifier through the burners, by a stream of inert gas under pressure. There are usually four burners in the SCGP process, positioned around the circumference of the lower part of the reactor. Compared with slurry feed (Texaco type), dry feed permits a saving of 20-25% of oxygen and, in many cases, bears greater overall energy yields. However, feeding a dry stream, as mentioned above, is more complex and costly than pumping a water-coal slurry as in the Texaco gasifier. To obtain hydrogen of higher than 99.9% mol purity, the purified (clean) gas will be conveyed to an adsorption system on molecular sieves of PSA (Pressure Swing Adsorption) type, producing a low pressure gas flow that can be used as fuel and pure hydrogen (obtainable at pressures of between 15 and 50 bar). Methanol The synthesis of methanol takes place by causing hydrogen and carbon oxides to react at pressures of between 50 and 100 bar on copper-based catalysts. The ideal composition for a gas for methanol synthesis is as follows: (H 2 CO 2 )/(CO CO 2 ) 2.03 in moles (methanol module). CO % in moles. H 2 S 1 ppm in volume. Inerts minimum content. The gasification process of residues allows a syngas to be obtained that is more similar to that defined above, though entailing a number of subsequent operations. The gas from the gasifier is first desulphurized by the Rectisol process (see below). There are two ways of adjusting the methanol module and the CO 2 content (Fig. 10 B): sending part of the desulphurized gas to the shift and separating the CO 2 from this stream; separating the CO 2, as well as the H 2 S, and extracting the excess CO in a cryogenic unit. nitrogen Applications of synthesis gas (syngas) Syngas can act as the origin of chemical products, synthetic fuels and electrical energy. Below, some simplified process schemes are addressed (gas preparation), targeted on various chemical or energy products (Higman and van der Burgt, 2003). The basic scheme for gasification (Fig. 9) is very similar in concept in the various use configurations, some of which are set out below, with a modest variant in the case of hydrogen production. air residue carbon slurry oxygen H 2 S sulphur Hydrogen When the product of interest is hydrogen, the effluent from the gasifier (POX, Partial OXidation) is sent directly for CO conversion (shift; Fig. 10 A). Downstream of the shift, the H 2 S must be removed from the gas (e.g. by means of a scrubbing process), while total, separate removal of the CO 2 is unnecessary. waste water vanadium concentrate Fig. 9. Basic scheme for gasification of residues targeted on chemical or energy products. VOLUME II / REFINING AND PETROCHEMICALS 333

10 DEEP CONVERSION OF RESIDUES Fig. 10. Gasification of residues targeted on production of (A) hydrogen, (B) methanol and (C) ammonia. A H 2 S hydrogen fuel gas methanol CO 2 fuel gas carbon monoxide B nitrogen CO 2 ammonia C Ammonia Ammonia synthesis occurs at pressures between 130 and 180 bar. A typical specification of gas for ammonia synthesis is as follows: N 2 :H 2 1:3 in moles. CO+CO 2 30 ppm in volume. Sulphur 1 ppm in volume. Inert gases (including methane) 2% in moles. If the plant for ammonia synthesis is coupled with a plant for urea synthesis, a stream of CO 2 having a purity of at least 98.5% in volume will also be required. In line with the above, a typical block diagram is illustrated in Fig. 10 C. In the case of gasification followed by quenching (i.e. the gas saturated with water vapour), since it is necessary to maximize the production of hydrogen, the most logical solution consists in immediately performing the shift catalytic conversion according to the reaction CO H 2 O CO 2 H 2, followed by the removal of the acid gases (H 2 S and CO 2 ). In this case, the shift catalyst must be of sulphur-resistant type. One of the acid gas removal systems employed in ammonia synthesis plants, the Rectisol process, uses pure methanol at a low temperature ( 30 C, 60 C) as the absorbent liquid. If, instead, gasification followed by a heat exchanger is adopted, only the H 2 S can first be removed, followed by the shift, after the gas has been saturated with water and then superheated; lastly, the CO 2 is removed. In both cases, the H 2 S-rich regenerated stream will enter a Claus type sulphur recovery system. The ratio N 2 :H 2 1:3 is obtained thanks to the nitrogen from the air fractionation plant, by way of a liquid nitrogen cryogenic washing process. In addition to forming stoichiometric nitrogen, this process, operating at temperatures close to 200 C, will eliminate practically all of the inert gases from the syngas, including argon and methane, feeding the ammonia synthesis with a gas of more or less ideal composition. IGCC IGCC is the result of a number of technologies aimed at the production of electrical energy in a 334 ENCYCLOPAEDIA OF HYDROCARBONS

11 GASIFICATION combined cycle (CCU, Combined Cycle Unit), fed by fuel gas of low heating value ( 2,000 kcal/nm 3 ) obtained in the refinery from the gasification of refining residues, coal, petcoke, etc. (Collodi, 1999). This process became widespread throughout the oil refining industry during the last two decades of the Twentieth century. Apart from the production of electricity, IGCC permits the coproduction of hydrogen and vapour, as well as that of elemental sulphur and a filter cake, in which the heavy metals present in the original crude are concentrated. IGCC also enables the production of electrical energy while adhering to increasingly strict European and US regulations regarding gaseous and liquid emissions. SO 2, NO x and CO are sent into the atmosphere as flue gas in concentrations between 10 and 30 mg/nm 3, with a sulphur removal efficiency of over 99% and a net efficiency of approximately 45% (i.e. equal to or greater than with other technologies; e.g. PC Pulverized Coal boiler; CFBC, Circulating Fluid Bed Combustion) for the same type of fuel, with consequently a smaller quantity of CO 2 emitted per kwh of electricity produced. The efficiency can vary according to the feed, whether or not there is cogeneration of hydrogen, etc. IGCC is required to be highly reliable and available, being that as a rule the energy produced is made available to the public network. IGCC based on refinery residues typically consists of a series of process units (Fig. 11): air fractionation, gasification, soot removal, removal of heavy metals, heat recovery, COS hydrolysis, sulphur removal, sulphur recovery, gas saturation/dilution, combined cycle and hydrogen recovery (optional). The oxygen required for partial oxidation is supplied by an Air Separation Unit (ASU). The residual oil coming from the refinery is first preheated to the condition necessary for gasification, after which the oil, the oxygen from the ASU and the high-pressure steam from the CCU are fed to the gasification unit, converting the residue into syngas under high-temperature conditions (1,300-1,500 C) and medium-to-high pressure (30-80 bar). The syngas, containing hydrogen, carbon oxides and minor quantities of methane, H 2 S, COS and traces of ammonia and HCN, is immediately cooled, either directly (by quenching with water) or indirectly (by a radiant exchanger), and then washed to remove any particulate matter. The water used for this washing is enriched with soot and consequently is sent to the soot-removal unit where the soot is absorbed in naphtha and then recycled to the gasifier. In this way, the carbon conversion is maximized. Alternatively, the water containing the soot can be filtered, in which case neither soot recovery nor recycling occurs. A portion of the water separated from the naphtha by decantation ( grey water) is recycled to the scrubber in the gasification plant. The remaining portion is sent to a water treatment unit, where the metals (mainly vanadium and nickel), the cyanides, the sulphates and the ammonia are removed from the water before air sulphur nitrogen oxygen hydrogen sulphide (steam to export) steam from CCU BFW from CCU feedstock filter cake water discharge desalted water (hydrogen) demineralized water (steam to export) Fig. 11. IGCC plant for refinery residues. VOLUME II / REFINING AND PETROCHEMICALS 335

12 DEEP CONVERSION OF RESIDUES the ensuing biological treatment. As stated, the metals are concentrated in the filter cake. The responsive heat contained in the saturated syngas issuing from the scrubber is recovered for steam production and to preheat the water. The syngas is then sent to the COS hydrolysis unit, the COS being hydrolysed into H 2 S and CO 2 in a fixed-bed catalytic reactor. Hydrolysis of the COS can be avoided if the downstream sulphur removal unit has sufficient capacity to also absorb the COS. The hydrolysed gas is further cooled and fed into the sulphur removal unit where the solvent, of chemical type (alkanolamines, etc.) or physical type (dimethyl ethers of polyethylenglycols, etc.) absorbs the sulphur compounds (H 2 S and COS), minimizing the coabsorption of carbon dioxide. From the head of the regenerating column, a stream containing mainly H 2 S and CO 2 is sent to the sulphur recovery unit. There the H 2 S is converted into elemental sulphur, while the clean stream (containing only a few tens of ppm of sulphur) can be fed to a hydrogen recovery and production unit (if hydrogen is a desired coproduct), or directly to the saturation unit, where the addition of steam reduces the NO x content in the CCU flue gas and improves the turbogas efficiency, increasing the mass flow-rate of the syngas. As an alternative to saturation, NO x can be reduced by diluting the syngas with nitrogen (coming from the ASU). The resulting saturated syngas, with a low heating value between 1,700 and 2,000 kcal/nm 3, is superheated and sent to the gas turbine of the CCU for the production of electrical energy. The CCU consists basically of a gas turbine that conveys its hot exhaust gas plus post-combustion gas to a series of heat recovery units (boilers and economizers) before dispersing them into the atmosphere. The high-pressure steam produced is fed in part to the steam turbine and in part to the gasification unit. Turbogas and the steam turbine are connected to electrical generators in single-shaft (or also multipleshaft) configuration. In integrated configurations, an air stream under pressure can be extracted from the comburent air compressor to be sent to the ASU for oxygen separation Integration of gasification in the refinery cycle The new environmental specifications have led to a profound change in the fuel oil market, with noteworthy consequences for the oil industry, creating an excess of heavy refinery residues that must in some way be converted and reused. Furthermore, in the European Union, the commercial specifications for petroleum products in terms of sulphur and heavy metals have become increasingly restrictive. These considerations have been the motive power causing many refineries to explore new ways to reduce the production of heavy residues and to seek new technologies enabling them to remain competitive on the market. Aside from environmental restrictions and the demand for heavy fuel oils, at the beginning of the 1990s, other energy factors of particular importance to some countries also came into play. Fig. 12 presents a typical integration of a refinery gasification plant, fed with heavy residues from vacuum residue to bitumen (SRI Consulting, 2001). In fact, due to the heavier grades of crude oil being supplied to the refineries, the world capacity of coking plants is increasing (by some 170% during the 1990s), tending towards a rapid saturation of the market for petcoke with a high sulphur content. Above all, the refineries located in inland areas of the United States are experiencing problems with petcoke disposal, with a considerable increase in costs (Marano, 2003). Contrary to the case of European refineries, the combined visbreaking and solvent deasphalting capacity in the US is equal to only about one-fifth of the coking capacity. As already seen, implementing gasification can improve a refinery s flexibility in terms of feedstock and products, and at the same time can supply highpressure hydrogen and steam. Electrical energy, generated in a combined cycle with greater efficiency than in conventional boilers, can be used internally or exported and sold. The total atmospheric emissions are reduced with the insertion of an IGCC (reductions of 8-15% for SO 2, 2-4% NO x and 10% particulate). Moreover, with respect to direct combustion, there are smaller quantities of solids requiring disposal. The systems of removing acid gases and sulphur recovery units can be shared between refinery and gasification plant. Gasification can also be fed with other refinery streams that would otherwise require disposal. Efficient use of part of the responsive heat contained in exhaust of gas turbines can reduce the number and the duty of the furnaces present in the atmospheric distillation, coking, deasphalting, etc., units Environmental aspects Gasification, coupled with modern combined cycles (IGCC), is one of the methods to produce electricity from solid or liquid fuels with the lowest environmental impact. 336 ENCYCLOPAEDIA OF HYDROCARBONS

13 GASIFICATION hydrocracker hydrotreater low sulphur products 90,000 bbl/d $ 23/bbl gasoline, diesel L, other distillates ultra heavy crude Mayan Venezuelan Kern River Mariner $ 14/bbl 100,000 bbl/d vacuum residue 60,000 bbl/d gas oil/distillates crude unit 40,000 bbl/d solvent 20,000 bbl/d deasphalted oil solvent separation 20,000 bbl/d bottoms gasification sour gas HP hydrogen raw syngas refinery gas/ natural gas 5,000 bbl/d $ 15/bbl equiv. clean syngas 5,000 bbl/d equiv. (1,000,000 lb/h) $ 15/bbl equiv. steam/heat export Fig. 12. Gasification/refinery integration (simplified scheme). sulphur power export 5,000 bbl/d equiv. (400 MW) $ 44/bbl equiv. ($ 25/MWh) Gaseous effluents The IGCC system is able to provide values of emissions, similar to those of the CCGTs (Combined-Cycle Gas Turbines) for the three main types of effluent (all with reference to 15% O 2, dry basis): Sulphur dioxide, SO 2 5mg/Nm 3. Nitrogen oxides, NO x 30 mg/nm 3. Particulate 1 mg/nm 3. IGCC permits a clean use of coal with lower emissions than PC boilers, provided with flue gas cleaning systems, regarding: SO 2 1/30 of the PC boiler. NO x 1/4 of the PC boiler. Particulate 1/20 of the PC boiler. Heavy metals 1/1,000 of the PC boiler. In the IGCC, over 99% of the sulphur is removed, in most cases, producing marketable elemental sulphur. In gasification, the nitrogen present in the feedstock is partially converted into ammonia and hydrocyanic acid, which are then removed when washed with water. The HCN is converted into ammonia in the COS catalytic hydrolyser. The NO x generated by turbogas is subsequently removed from the flue gas, if necessary, with SCR (Selective Catalytic Reduction) systems. Mercury is present in coal in various quantities and its emission into the atmosphere will be subject to restrictions in the near future, starting in the United States. It has been demonstrated that over 90% of the mercury present in the syngas can be removed with activated carbons. Removal using the IGCC scheme of carbon dioxide (one of the greenhouse effect gases) has the advantage of combustion taking place under pressure, whereas in the conventional combustion technologies, flue gas is at atmospheric pressure. Liquid effluents Depending on the plant layout in which it is inserted, gasification may have an excess or shortage of water. Generally, gasification processes are integrated by waste water treatment systems of chemical-physical type (i.e. ph regulation, flocculation and sedimentation) and of biological type (i.e. aerobic or anaerobic) to obtain a liquid effluent respecting current regulations. Solid effluents The quantity and nature of the solid effluents from a gasification plant depend essentially on the ash present in the feedstock, which may be less than 1% in weight (in petroleum residues) up to 40% in weight in certain types of coal. Compared with other technologies for producing electricity (PC boiler and CFBC), the gasification plant inserted in IGCC produces a considerably smaller quantity of solid effluents (e.g. the desulphurizing of flue gas does not require large quantities of limestone). IGCC produces pure elemental sulphur, which, as stated, is a marketable product. In the case of coal, eventually the heavy metals almost entirely take on the form of inert sandy material (in the case of gasifiers slagging). In the case of petroleum residues, the metals VOLUME II / REFINING AND PETROCHEMICALS 337

14 DEEP CONVERSION OF RESIDUES (i.e. vanadium, nickel and iron) eventually mainly take on the form of a filter cake, with a concentration of around 30% in weight. These cakes can, in turn, have a market for Ni and V recovery Commercial aspects In general, gasification is a process that requires high capital investments, but, on the other hand, can transform a great variety of low-value (or even negative) feeds, or even those difficult to process or hard to dispose of, into products with a market value. The economic impact of gasification depends on the context in which it is inserted (feed, final products, alternative processes, regulations, etc.) and, therefore, it is not possible to draw conclusions of a general character. To a large extent, IGCC plants are still one-of-akind, not yet enjoying the benefits of standardization. Moreover, its technology entails a high operational level and quality, as well as maintenance (O&M), thus requiring proper programming. The investment in an IGCC plant can be subdivided into air fractionation, gasification, gas purification and combined cycle. Generally speaking, the total cost of preparing synthesis gas is approximately equal to that of the combined cycle. The key factors in making the process economically interesting include reliability and capacity factors (i.e. the ratio between the actual annual production and the theoretical, or designed one). A number of analyses have shown that 1% of additional capacity of a plant corresponds to a reduction in investment of approximately 1.5%, and that this additional capacity is equivalent to an IGCC with about three points more efficiency (Higman and van der Burgt, 2003). Another way to increase the availability of gasification is foreseeing a stand-by gasifier, even if this may entail a considerable and not always justified cost, or splitting up total capacity over a number of lines (e.g. two lines of 50% or 60%, rather than one 100% line). However, it must be acknowledged that, at least in the case of refinery residues, gasification plants (and IGCCs) are chalking up capacity factors of around 90%, including scheduled maintenance and out-of-service periods, as demonstrated by the two largest Italian IGCCs in the world, without stand-by gasifiers (Collodi and Brkic, 2003). The future of gasification and the processes associated with it, in particular IGCC, thus depends on internal and external factors, which can constitute the motive power for their final development. Among the external factors, the most accredited include: a) the (high) price of natural gas and its variability as compared to coal; b) the search for a diversification of energy sources (gas + coal, etc.); c) the increasing environmental constraints (emissions of SO 2, NO x, CO 2, mercury, etc.) to which IGCC is best able to adjust; d) the so-called hydrogen economy and the possibility of polygeneration (more products from the same syngas). The internal factors seem at the moment less effective and in many plant areas the results are not yet promising and consolidated (e.g. hot clean-up of syngas, more economic air fractionation units, etc.), except for the progress made in gas turbines and in combined cycles, which can contribute towards achieving a better overall efficiency of IGCCs. The impact of gasification on the market also depends, however, on other factors that are either not reflected in usual economic analyses or difficult to assess, such as its affects on the territory and on local labour, as well as the fore-mentioned factors of reliability, future energy demand, etc. Therefore, while many evaluations are of a technical and financial character, there are others based on mere perceptions and judgements, which at times are not positive. References Childress J., Childress R. (2004) 2004 World gasification survey. A preliminary evaluation, in: Proceedings of the Gasification Technologies conference 2004, Washington (D.C.), 3-6 October. Collodi G. (1999) Impianti di gassificazione per produzione di energia, «ICP», 6, Collodi G., Brkic D. (2003) The experience of Snamprogetti s four gasification projects for over 3000 MWth, in: Proceedings of the Gasification Technologies conference 2003, Washington (D.C.), October. Higman C., Burgt M. van der (2003) Gasification, Amsterdam-Heidelberg, Gulf. Marano J.J. (2003) Refinery technology profiles. Gasification and supporting technologies, U.S. Department of Energy, National Energy Technology Laboratory, Energy Information Administration. SRI CONSULTING (2001) Refinery residue gasification, Process Economics Program Report 229. Guido Collodi, Domenico Sanfilippo Snamprogetti San Donato Milanese, Milano, Italy 338 ENCYCLOPAEDIA OF HYDROCARBONS