A PROCESS FOR RECOVERING ENERGY FROM A COMBUSTIBLE GAS

Abstract: A process for recovering energy from a combustible gas generated by partial oxidation of cellulose waste liquor in a gas generator (A) operating in a temperature range of 600-1300 DEG C and a pressure in the range of 1-100 bar, cooling and cleaning said combustible gas and using the gas as fuel in a recuperated gas turbine cycle (C, E), wherein water and/or steam is injected to humidify compressed air and/or combustible gas, increasing turbine motive fluid massflow and power output.

Description: Title: A process for recovering energy from a combustible gas. Field of the invention The present invention relates to an improved process for recovering energy from a combustible gas generated during gasification of cellulose waste liquors, the improvement comprising a cooling zone, wherein the combustible gas is cooled to a temperature below 150 C, simultaneously recovering sensible and latent heat in one or more heat exchangers, discharging the cooled combustible gas for use as fuel in a water and/or stea injected recuperative gas turbine cycle. Background of the invention The raft process is currently the dominant chemical pulping process. During pulping large quantities of recoverable energy in the form of black liquor is generated. Worldwide some 2.8 billion GJ (780 TWh) of black liquor was produced in 1990 at kraft pulp mills. The kraft recovery system has two principal functions: i) Recovery and recure of the inorganic pulping chemicals. ii) Recovery of the energy value of the organic mate¬ rial as process steam and electrical power. The chemical recovery process contributes significant to the capital intensity of the kraft process. About 35% of the capital cost of a modern pulp mill is attr butable to the recovery process. The predominant method today for recovery of chemical and energy from black liquor is the Tomlinson recover boiler, a technology which was introduced well over fifty years ago. Although an established technology, there are some wellknown disadvantages with conventio nal recovery technology. Most often the recovery boiler with its inherent in¬ flexibility constitutes the main production bottlenec in the pulp mill. Economics of scale dictate large capacity units. Other disadvantages include the low thermal efficienc and risk of smelt water explosions which in turn con¬ stitute a safety problem. These and other areas of concern have been the drivin force for development of new methods and principles f recovering chemicals and energy from black liquor. O of the more promising routes is gasification of the liquor in entrained or fluidized beds. In some cases these alternative processes can be installed as incre mental capacity boosters, providing an opportunity to eliminate the recovery boiler bottleneck. One of the major driving forces for development of ne recovery technology has been to improve thermal effic ency accompanied with higher power to steam output ratios. The present invention relates to a major improvement in this area, using technology based on gasification and energy recovery in a recuperated gas turbine cycle. Gasification of black liquor can be performed at vari¬ ous temperatures and pressures, resulting in different forms of the recovered inorganic constituents and different calorific values of the combustible process gas. The inorganics, mainly sodium compounds, are solubi- lized to form an aqueous alkaline liquid called green liquor, which liquor is used for cooking liquor prepa¬ ration. Kraft pulp mills are significant producers of biomass energy and today most mills are designed to use the biomass fuel available at the kraft mill to meet on site steam and electricity needs via back pressure steam turbine cogeneration system. Electricity demand is often higher than internally generated, in particu¬ lar for integrated mills and often electricity is imported from the grit. Process steam requirements for a modern kraft pulp mil is in the order of 10 GJ per ton of air dried pulp. The internal electricity demand is around 600 kWh/ton of air dried pulp. The biomass gasification gas turbine cogeneration system of the present invention will meet mill steam demand and has the potential to produce excess electri city for export. The present invention can be practised using various types of gas generators and gasification principles exemplified in prior art documents. In US 4,917,763 and US 4,692,209, gasification of spen cellulose liquor, such as black liquor, is described. The gasification temperature is in the range of 1000- 1300°C, resulting in the evolvement of molten inorga¬ nics and a combustible gas. The molten alkaline chemi cals are withdrawn from the gas stream in a cooling an quenching stage where an aqueous solution is sprayed into the gas steam. The product alkaline solution is cooled to below 200°C. The combustible gas is used for generating steam or as a synthesis gas. Another gasification method is described in US 4.808.264 where recovery and energy from black liquor is carried out in three distinct and separate steps, whereas in the first step concentrated black liquor is gasified in a pressurized gasification reactor by flash pyrolysis at 700 to 1300 C, in which the inorganic chemicals of the black liquor are contained in the form of molten suspended droplets. Energy is recovered from the resulting process gas for generation of steam and/or electric power in a gas turbine/steam turbine cycle. The steam turbine is of back pressure type preferably selected to fit the need of process steam for the mill. In WO 91/15665 is described a method and apparatus for generation of electricity and steam from a pressurized black liquor gasification process. Energy is recover in a gas turbine/back pressure steam turbine system. Excess steam generated in the mill is recirculated in the gas turbine or the combustor thereof for increasi the generation of electricity. This procedure is kno to the industry as a steam injected gas turbine here¬ inafter referred to as STIG. Common for US 4.808.264 and WO 91/15605 is that they both are based on energy recovery using a combined cycle including a back pressure steam turbine. These systems have a rather high thermal efficiency b suffer from the high capital cost of the steam turbin and waste heat steam generator. The electricity outp from a condensing steam turbine in a combined cycle i often less than a third of the total power output and considerably less for back pressure turbines. A bottoming steam cycle as in these inventions has an inherent high thermodynamic irreversiblity since the evaporation of water occurs at constant temperature, whereas the heat release occurs at varying temperatu¬ res, leading to lower thermal efficiencies. The objective of the present invention is to provide process for more efficient and less capital intensive production of electric power and process steam from gasification of black liquor using a recuperated gas turbine cycle following a gas quench cooler and heat exchange system where the hot process gas from the gasifier reaction zone is cooled to a temperature bel 150 C, simultaneously recovering sensible and latent heat transferred for generation of steam for mill internal use. A substantial quantity of sensible heat can also be extracted from hot liquids such as quench liquids, condensates and coolants, discharged from or within t quench zone and/or heat exchange zones. Recovery of latent and sensible heat can be performed in various types of equipment including heat exchange steam generators, boiler feed water heaters and heat pumps. In a specific embodiment, latent and/or sensible heat in the gas and/or liquid streams is recovered using a reversed absorption heat pump, where a heat absorbing medium such as for example sodium hydroxide solution used for heat transfer. The cooled combustible process gas is transferred to gas turbine system in which some or all of the excess air, which is used as thermal diluent and working fluid, is replaced with water vapor. Gas turbines are very sensitive to contaminants in th incoming gas stream, in particular sulfur oxides and alkali salts. To prevent harmful effects on turbo machinery, the gases have to be substantially free fr these and other contaminants, in particular if the ga is used as fuel in an internally fired gas turbine cycle. It is therefore important to have efficient g cleaning in the present invention in particular with respect to sodium, as sodium is a dominant inorganic compound in cellulose waste liquors. It is appreciated that substantially all vaporized sodium compounds and particulates are removed in the quench gas cooler and scrubbing system of the present invention. Saturation vapour pressure of the harmful components in question is very low at temperatures below 200°C. If necessary the process gas can be filtered or sodium compounds can be sorbed on an appropriate involatile inorganic sorbent, such as an alumino-silicate before the gas enters the gas turbine combustor. Zeolites may be used as filters or as sorbant surface for alkali removal. One way to get around this problem totally is to use the process gas as fuel in an externally fired gas turbine cycle, which is another optional embodiment of the present invention, described subsequently herein. Although gas turbine cycles have inherent thermodynami advantages, simple cycle gas turbine systems suffer from some wellknown disadvantages as well, such as the large parasitic load of cooling air on the system to decrease the turbine inlet temperature. Furthermore, the exhaust from the gas turbine contains a large quantity of sensible heat and if discharged to atmosphere large quantities of potentially useful energy are wasted. However, this exhaust heat can be exploited in various ways, for example to produce stea in a heat recovery steam generator (HRSG) , which can b used for process needs directly or in a cogeneration figuration, or to produce more power in a condensing steam turbine. In light of the strong scale economics of steam turbine cycles and other factors described herein, combined gas turbine and steam turbine cycles based on heavy duty industrial turbines are not the best candidates for applications in the relatively modest scales in conjunction with black liquor gasifi¬ cation. Another method to exploit the heat content of turbine exhaust is to raise superheated steam which is recircu lated and injected in the combustor of the combustion turbine, see e.g. US patent No 3,978,661. Steam injec tion in biomass gasifier gas turbine cogeneration systems for forest product industry applications is fo example described in PU/CEES Working Paper No 113 by D Eric Larson, Princeton, February 1990. Yet another method to exploit the turbine exhaust is preheat the air leaving the compressor against engine exhaust in a recuperative heat exchanger and simultan ously use interstage cooling during air compression. Injection of water in a recuperative cycle can furthe improve efficiency. The principle of water injected recuperative gas tur¬ bine cycles is previously described, for instance in patent 2,869,324 and US patent 4,537,023, and in lite rature; Gasparovic N. , "Gas turbines with heat ex¬ changer and water injection in the compressed air", Proc.Instn. Mech. Engrs., vol. 185, 1971. A major drawback of direct fired gas turbine cycles a exemplified in prior art documents above is the high sensitivity to fuel gas quality. Indirectly fired or externally fired gas turbine cycle are considerably less sensitive and can accept fuels o approximately the same quality as steam generators. Indirect cycles, currently under development for coal gasification applications, can accomodate a wide varie ty of conventional equipment. Advanced combustors and high temperature heat exchangers are commercially available or under development. Stack gas recirculation to use all the cycle air for combustion can be attractive in indirect cycles, mini¬ mizing NO emissions and lowering capital cost. As will be subsequently explained herein, use of an indirectly fired gas turbine cycle in combination with compressed air humidification by water injection is an attractive alternative embodiment of the present inven tion. The practise of the present invention will be describe by reference to the appended description, examples and figures as applied to the recovery from black liquor. It should, however, be recognized that the invention i applicable to the recovery of other cellulose waste liquors, such as for example spent sulfite or soda pulping liquors. Brief description of the drawings The invention will be explained by referring to the appended figures, in which; Fig. 1 discloses a preferred embodiment of an arrangement according to the invention, and Fig. 2 discloses an arrangement for cogeneration of 12 steam according to the invention. General description of the invention In the subject process a cellulose waste liquor con¬ taining hydrocarbonaceous material and inorganic sodiu compounds is reacted with an oxygen containing gas in free flow gas generator A to produce a combustible gas The gas generator operates at a reaction zone temperature of between 700-1500 C and at a pressure of 1-100 bar. The hot effluent gas stream from the gas generator is rapidly cooled through direct contact with an aqueous liquid in a quench cooler 1, see figure 1. The main part of the cooling is a result of evaporation of part or all of the aqueous quench liquid. The temperature of the effluent gas 2 and quench liquid 3 is governed by the selected operating pressure of the gas generato and corresponds to the temperature of saturated steam at this pressure. A large portion of the sensible heat in the hot efflu¬ ent gas is thus absorbed and transferred to water vapor. The saturated gas leaves the quench system at temperature in the range of 60-220 C and a pressure ranging from 1 to 100 bar, preferably at the same pressure as in the gas generator less pressure drop in the quench. The combustible gas is then further cooled in one or more heat exchangers 4, simultaneously generating process steam 5 and/or hot water. A large portion, if not all, of the mills' steam deman is thus covered by the cooling system heat exchange steam generators. A downstream gas turbine system B can hence be optimized for power generation. The condensate 6 resulting from the cooling which may contain sodium compounds is withdrawn from the process gas and mixed with other aqueous liquids to form green liquor 7 for use in cooking liquor preparation. The process gas leaving the heat exchangers is further cooled by scrubbing B with an aqueous liquid 8, which further enhances the removal of any carryover sodium fumes. The resulting clean combustible gas 9 has a temperatur of between 20 and 150°C and a pressure substantially a the same pressure as in the gas generator. The gas is saturated, and water vapor partial pressure correspond to the temperature and total pressure. Further gas purification and sodium removal can optio¬ nally be performed by downstream filtering or electro¬ static precipitation. The heating value of the process gas is dependent on the type and amount of oxidant used in the gas genera¬ tor. The use of air as oxidant results in that about half the product gas consists of nitrogen, thus result ing in a gas with a rather low calorific value. According to overall energy balance and capital cost considerations there is little or nothing to be gained by using industrial oxygen as oxidant for gasification of black liquor in the present invention despite the higher product gas quality. The clean product gas from air blown black liquor gasification has a heating value, in the range of 3.5- MJ/Nm 3 . After final cooling and scrubbing, the temperature of the process gas is raised by heat exchange with hot circulating green liquor and/or circulating compressor intercooling coolant 10 and/or gas turbine exhaust 11. The preheated clean combustible gas is thereafter used as fuel in a gas turbine plant comprising a compressor C, combustor D and gas turbine E. To attain the power generation objective of the presen invention the mass flow through the turbine is increas ed by injecting water or steam into the gaseous stream entering the combustor or before expansion in the gas turbine and by preheating said gaseous streams by heat exchange with gas turbine exhaust. A distinguishing feature of the present invention is the use of recuperators F which recycle a large portio of the turbine or combustor exhaust energy to preheat compressor discharge air and/or fuel gas prior to the combustor. Furthermore, the use of compressor intercooling signi¬ ficantly improve the performance of recuperated cycles, since the compressor work is reduced and thermal energ lost by intercooling is counterbalanced by extraction of more heat from the exhaust gases in the recuperator. In a preferred embodiment the compressed air stream is cooled after compression by adding water 12 to the air stream in a humidification tower G, in which all or part of the injected water evaporates. The dewpoint decides maximum water addition. In a following recuperator, the humid compressed air is heated by hea exchange with gas turbine exhaust. Maximum heat is recovered from the exhaust gas when th temperature of the air at the inlet of the recuperator is equal to the dewpoint temperature. The evaporative regeneration is performed in one or more steps with humidification towers before the recuperators. An alternative embodiment is to arrange an evaporative aftercooler after the compressor discharge, followed b a water injected evaporative recuperator. By injection of water in the compressed air stream in this way, at least two objectives are reached. The resulting increased massflow through the gas turbine increases power output and reduces the parasitic load of air compression. Further, by injecting water into the compressed air, the lower temperature and higher heat capacity of the fluid give more favourable heat exchange conditions with respect to the turbine or combustor exhaust. Yet another objective of the invention is reached by providing pressurized oxidant air for the operation o the gas generator. The reduced need for diluent cool ing air in the gas turbine in the present invention enables provision for supply of all the air needed fo gasification. Another specific advantage of the process of the pre¬ sent invention is that it can utilize low level heat from the discharged flue gases 20, the compressor intercooler 13 or from the gasification process or utilize low level heat from elsewhere in the mill to preheat water used for evaporative cooling of the compressed air and/or fuel gas, and hence improve overall efficiency. A major advantage of the present invention is its simplicity. The entire bottoming cycle of a combined cycle is eliminated, resulting in lower capital costs for a given electricity output. Recuperators and humidifiers does not present serious design or opera¬ tional difficulties. A disadvantage with water or steam injected cycles is that water added to the humidifier is lost if no meth to recapture the vapor from the exhaust gas is used. For gas turbine systems with evaporative regeneration the water consumption for humidification is in the order of 0.1-0.8 kg water per kWh power and about twi as much for power efficient STIG systems. In both cases the water has to be processed to boiler feed water quality. The gas turbine cycle in the present invention can be integrated with a facility for production of deminera lized water to be used for injection. Such a deminer lization plant could be based on various principles known from the sea water desalination industry. Demineralization plants based on distillation process are most preferred for use in the present invention since they can use heat from the exhaust stream direc ly or use surplus steam or low level heat from else¬ where in the mill. In another preferred embodiment of the present invention heat pumps are used for recovery of sensibl and latent heat from the combustible gas stream and/o alkaline liquors discharged from the quench zone and/ heat exchange zone. The use of heat pumps is particularly attractive when gasification pressure is lower than say 10-15 bar, as useful steam in a pressu range of 2-10 bar can be generated despite lower saturation temperature in the gas streams and lower temperature in the liquid streams discharged from the quench zone. When practising the present invention at lower gasifi cation pressures, say lower than 10-15 bar, the use o a downstream indirect fired gas turbine cycle becomes more attractive relative to direct fired systems. Th efficiency of indirect fired systems are substantiall independent on fuel gas pressure. In the indirectly fired cycle the fuel gas is fired i a combustor in the presence of gas turbine exhaust, a combustor exhaust heat is extracted for preheat of humidified compressed air, which air is used as motiv fluid in the gas turbine. Use of high cast ceramics such as fused aluminia/silica compounds as heatexchang surface permits pre-heat of air in range of about 1000 °C and above. One obvious advantage of the indirect cycle is the lower sensitivity to fuel gas quality. Water injection into the compressed air or the fuel ga as practised in several embodiments of the present invention lowers the adiabatic flame temperature in t combustor, however, as long as combustion is stable, this effect has negligible impact. Higher solids loading in the black liquor feed counteract this effe by increasing fuel gas heating value and adiabatic flame temperature. Average water vapor partial pressure in the turbine exhaust gas stream in the present invention is in the order of 5-25 % of the total pressure. It will also be appreciated that environmental benefi will result from the present invention as injection o water or steam in a gas turbine system gives a lower peak flame temperature in the combustor at given tur¬ bine inlet temperatures. NO emissions tend to fall exponentially with increased heat capacity of the hum combustion air and/or fuel gas. Water vapor in small quantities also exert catalytic effects on the decomp sition of hydrocarbons and minimizes carbon monoxide emissions. Examples E x a m p l e I (Figure I) A kraft market pulp mill produces 1070 ton/day bleache pulp, generating a black liquor flow of 1662 ton/day a dry solids. The mill's internal steam requirements amount to 112 ton 5 bar steam and 36 ton 13 bar steam per hour. Electricity consumption in the mill is 600 kWh/ton pulp or 642 MWh/day (26.75 MW) . Black liquor is fed to a suspension bed gasifier integrated with an evaporative recuperated gas turbine system for energy recovery. The black liquor has the following data at the gasifie entrance: Dry solids 78% Temperature 170°C Higher heating value 14.8 MJ/kg DS Flow rate 19.24 kg DS/s The gasifier is operated at a pressure of 25 bar and a reaction zone temperature of 950 C. Air is bled off from the gas turbine compressor (14) and used as oxidant in the gas generator. The tempera ture and pressure of the air leaving the gas turbine compressor are increased by a booster compressor. The process gas leaving the gasifier is cooled by heat exchange in two indirect heat exchangers, generating 112 ton 5 bar steam per hour and 7 ton 2 bar steam per hour for export to the mill. The gas is further coole by scrubbing in a countercurrent spray scrubber. The clean process gas leaving the scrubber has a tempe¬ rraattuurree ooff 4400°CC aanndd aa pprreessssiure of 23 bar. The gas has the following composition: The calori .fi.c value of the gas i.s 4.2 MJ/Nm3 (LHV) . The process gas is discharged from the gasifier/scrub¬ ber and used as fuel in a recuperative gas turbine plant. After scrubbing, the process gas temperature is in¬ creased to 130°C by heat exchange with hot water (1( from the compressor intercooler (13) and the gas is further preheated by gas turbine exhaust in a rreeccuuppeerraattiivvee hheeaatt eexxcchhaannggeer to 450 C before entering the gas turbine combustor. Boiler feed water (10) is preheated in the compressor intercooler from 30 C to 145 C, and used for combustib le gas preheat and partly as injection water in the humidifier and as boiler feed water. Excess water (15) is used as bark boiler feed water. A stream of boiler feed water (18) from the gas preheater (16) is preheated by indirect heat exchange (21) with green liquor from the gasifier/scrubber circulation loop fro 125°C to 160°C. Another stream of boiler feed water is pumped (19) to the humidifier in line (12) . Make up water is added in line (17) . The gas turbine exhaust stream is finally discharged from the gas turbine plant and recuperators through line (20) . The gas turbine cycle has the following main design criteria: Compressor adiabatic efficiency = 0.89 Turbine adiabatic efficiency = 0.91 Generator efficiency = 0.99 Ambient_air_conditions_at_comEres^ (22) Temperature 15 C Pressure 1.033 atm Relative humidity 60% Fuel (23) Clean process gas from gasification of black liquor. Temperature 450 C Calorific value 4.2 MJ/Nm 3 (LHV Air_bleed_from_comgressor_to_gasifier (14) Temperature 290°C (after booster compressor) Flow 26.6 Nm 3 /s Gas turbine inlet conditions A minimum temperature difference of 20°C between heat¬ ing and heated fluids in the recuperators is assumed. Combustion and mechanical efficiencies are assumed to be 1.0. Auxiliary power is assumed to be negligible. No provision is made for additional gas turbine cool¬ ing. Power consumption in air booster compressor is 3.3 MW (efficiency 0.8). Result Net power output 85.9 MW Net power yield 32% Thermal efficiency 65% Temperature in flue gas after the recuperator 200°C 3 Exhaust gas flow 163 Nm /s Water vapor content in flue gas 10.8 % Oxygen content in turbine exhaust 10.9 % E x a m p l e II (Figure II) Process gas generated in a black liquor gasifier is cooled by heat exchange and further cooled in a scrubber to a temperature of 40°C, recovering 86 ton 5 bar steam and 27 ton 2 bar steam per hour for use in the mill. Other relevant data as in example I. The clean cooled process gas is preheated to 300 C in heat exchanger (24) , whereafter the process gas is humidified in a countercurrent multistage saturator, decreasing the gas temperature to 131 C. The saturate process gas is thereafter preheated in a heat exchange by extracting heat from the gas turbine exhaust. The temperature of the process gas entering the gas turbin combustor is 450°C. Gas turbine exhaust heat is used for heat exchange wit incoming fuel gas in two recuperative heat exchangers and for generation of 34 ton 12 bar steam per hour in waste heat boiler. (25) Compressor intercooling is not used in this cycle and the heat in compressor exhaust is transferred directly to the combustor. A part of the hot air from the compressor is bled off and recirculated for use as gasifier oxidant. (26) Result Net power output 76.6 MW Net power yield 28% Thermal efficiency 69% Temperature in discharged flue gas 210°C Water vapor in flue gas 9.2% Oxygen content in turbine exhaust 11.8% Additional embodiments The turbine exhaust flue gas leaving the recuperators still contain a considerable amount of heat, although at a low temperature. This heat can for instance be used for low pressure steam generation. Due to the comparatively high water content in the flue gas, also condensing heat recovery can be profitable. In a condensing heat recovery system, the temperature of the flue gas is lowered to below the water vapor dewpoint, with condensation as a result. The heat recovered is both sensible and latent, the latter giving the greater contribution. The same or higher energy quantity can be recovered by flue gas condensin heat recovery in steam injected gas turbine cycles. Another potential advantage of condensing flue gas hea recovery is that relatively pure water can be recovere for recirculation and use as injection water or steam. The modern kraft mill often has hog and/or bark fired boilers or gasifiers integrated. Yet other mills have natural gas available for various purposes, such as lime kiln fuel. The present invention can be practised in combination with combustion of other gaseous or liquid hydrocarbon fuels available at the mill. As an example, additiona natural gas or biogas can be fired in a preburner in the compressed air stream or at the gas turbine combus tor increasing gas turbine inlet temperature and power output. The same objective can be reached by blending the combustible gas from the gasifier with another hydro¬ carbonaceous fuel. Yet another method to increase power output in the present invention is to inject steam in various locations in the combustor or gas turbine. The quench cooler following the gas generator could be replaced by liquid cyclones or by liquid injection cooling. In the appended claims such devices are grouped under the expression "contacting zone". Obviously, various modifications of the invention as herein set forth may become apparent to those skilled in the art without departing from the spirit and scope thereof. Thus, for example a plurality of intercooler may be used and reheaters may be employed with the gas turbine. Humidification may be employed in one or mor steps with subsequent preheat, and water or steam may be injected at different locations in the cycle to increase motive fluid mass flow. Therefore, only such limitations should be made as are indicated in the appended claims.

Claims: What is claimed is: C l a i m s 1 A process for recovering energy from a combustible gas, generated by the partial oxidation of cellulos waste liquor in a gas generator operating in a temperature range of 600-1500 C and a pressure in the range of about 1-100 bar, cooling and cleaning said combustible gas by direct contact with an aqueous liquid in a quench zone or contacting zone, thereby dissolving inorganic sodium components, forming an alkaline liquor, which liquor is withdrawn from the system for preparation of cookin liquor, discharging said combustible gas from the quench zone or contacting zone, the improvement comprising the steps of: (1) cooling the combustible gas stream leaving the quench zone or contacting zone by passing said gas stream to one or more heat exchange zones, where the gas is cooled by heat exchange with one or more coolants to a temperature in the range of 30-180°C; (2) passing said combustible gas to fuel a direct or indirect fired gas turbine plant; (3) compressing air to a predetermined pressure; (4) bleeding compressed air from the compressed ai stream for use as oxidant in the gas generator (5) contacting all or a part of said compressed ai and/or the combustible gas with water or steam (6) burning said combustible gas in the presence o an oxygen containing gas, preferably the said compressed air or exhaust gas from said gas turbine; (7) extracting heat from gas turbine exhaust by indirect heat transfer to compressed air and/o combustible gas or use of gas turbine exhaust as combustion air in a combustor, followed by extraction of combustor exhaust heat by indirect heat transfer to compressed air and/o combustible gas. The process of claim 1, wherein the gas stream leaving the quench zone or contacting zone, is cooled in one or more indirect heat exchangers transferring heat for generation of steam at a pressure of 1-15 bar. The process of claims 1 and 2, wherein the gas stream after cooling by heat exchange is scrubbed and cooled with an aqueous liquid to a temperature below 150°C. The process of claims 1- 3, wherein condensates, alkaline liquids and/or scrubbing liquids are with¬ drawn from the gas stream, which condensates and liquids after mixing and recirculation to the quenc and/or scrubber are withdrawn for preparation of cooking liquor. 5 The process of claim 1, wherein heat is recovered b heat exchange with alkaline liquor leaving the quench and/or heat exchange zones. 6 The process of claims 1 - 5, wherein heat in the ga stream leaving the quench zone and/or heat in the liquids leaving the quench and/or heat exchange zones, is recovered by heat transfer using a heat pump system, preferably using a reversed absorption heat pump system. 7 The process of claim 1, wherein air is compressed i one or more stages to a pressure exceeding 2 bar preferably in the range of 5-50 bar, more preferred 10-30 bar. 8 The process of claims 1 and 7, wherein air is com¬ pressed in two or more stages with intermediate intercooling. 9 The process of claims 1, 7 and 8, wherein intercool ing is obtained by injection of water in the com¬ pressed air. 10 The process of claims 1, 7 and 8, wherein inter¬ cooling is obtained by indirect heat exchange with cooling liquid. 11 The process of claim 1, wherein 5-30 % by volume of the compressed air, leaving the compressor or com¬ pressors, is bled off for use as oxidant in the gas generator. 12 The process of claim 1, wherein the remaining com¬ pressed air, leaving the compressor or compressors after bleed off, is humidified by injection of wate or steam. 13 The process of claims l and 12, wherein the humidi¬ fication is performed in one or more countercurrent multistage contactors. 14 The process of claims 1 and 12, wherein the water o steam injected in the compressed air has a temperature above 100°C. 15 The process of claims 1, 12 and 14, wherein water injected in the compressed air is warmed to a temperature above 100 C by heat exchange with com¬ pressed air in a compressor intercooler. 16 The process of claims 1, 12 and 14, wherein water injected in the compressed air is warmed to a temperature above 100 C by indirect heat exchange with hot condensate, green liquor, quench liquid and/or scrubbing liquid. 17 The process of claims 1, 12 and 14, wherein water injected in the compressed air is heated to a temperature above 100 C by indirect heat exchange with turbine exhaust heat. 18 The process of claims 1, 12 and 14, wherein water injected in the compressed air is warmed to a temperature above 100°C by indirect heat exchange with waste heat generated in the gasification syste or in the mill. 19 The process of any of the preceeding claims, where the humidified compressed air is heated by indirec heat exchange with turbine exhaust to a temperatur above 150°C. 20 The process of claim 1 and any of the claims 2-19, wherein the humidified compressed air is heated by heat exchange with gas turbine exhaust in two or more separated but interconnected heat exchangers with intermediate injection of additional water or steam into the compressed air stream. 21 The process of any of the preceeding claims, wherei the humidified compressed air is heated by heat exchange with gas turbine exhaust in a countercurrent recuperative heat exchanger, in whi heat exchanger water is injected, at one or severa locations into the air stream. 22 The process of claim 1, wherein saturated combus¬ tible gas leaving the heat exchange zone, is con¬ tacted with aqueous liquid in one or more contacti zones, thereby cooling the saturated gas to a temp rature in the range of 70°C - 145°C, whereafter sa combustible gas is preheated by heat exchange with gas turbine exhaust heat and combusted in the pre¬ sence of compressed air. 23 The process of claim 1, wherein combustible gas leaving the heat exchange zone, is contacted with aqueous liquids in one or more contacting zones, thereby cooling the gas to a temperature below 100 C, preheating said gas to a temperature above 100°C, humidifying the gas by injection of water into the gas stream, preheating the humid combust¬ ible gas to a temperature above 150°C by heat exchange with gas turbine exhaust and combusting said humid gas in the presence of compressed air. 24 The process of any of the preceeding claims, wherei humidified or saturated combustible gas is preheate in countercurrent heat exchange with gas turbine ex haust to a temperature above 300 C. 25 The process of claim 1 and any of the claims 2-18, wherein gas turbine exhaust is used as oxidant in a combustor and wherein heat is transferred from the combustor exhaust by heat exchange with compressed air, said compressed air used as motive fluid in a gas turbine expander. 26 The process of claim 1 and any of the claims 2-25, wherein low level heat is recovered from gas turbin and/or combustor exhaust streams by condensing heat recovery. 27 The process of claim 1 and any of the claims 2-26, wherein condensates from condensing heat recovery i recirculated and used as injection water. 28 The process of any of the claims 2-27, wherein stea is injected in the gaseous stream or streams enter¬ ing the gas turbine combustor and/or gas turbine expander.

Inventors: STIGSSON LARS, STIGSSON, LARS
Applicants: CHEMREC AB, STIGSSON LARS, CHEMREC AKTIEBOLAG
Application year: 1992
Main classification: D21C11
IPC codes: D21C11, F01K21, F01K23, F02C1, F02C3