Abstract:
A power generation system ( 100 ) and a method of generating power. In one embodiment of the system shown in FIG.  1 , a gasification subsystem ( 1 ) is configured to convert a carbonaceous fuel to fuel suitable for combustion in a gas turbine ( 48 ). A first power generation cycle ( 2 ) includes the gas turbine ( 48 ) coupled to receive fuel from a gasifier ( 24 ). A first Rankine cycle ( 3 ) is coupled to receive thermal energy from at least the first power generation cycle ( 2 ) and generate power with a first vapor turbine ( 58 ). A second Rankine cycle ( 4 ) is coupled to receive thermal energy from the gasification subsystem ( 1 ) or the first power generation cycle ( 2 ) and generate power with a second vapor turbine ( 82 ). In an associated method, syngas ( 26 ) is generated and processed to remove components therein. Power is generated in a first turbine ( 48 ) with the processed syngas ( 33 ). Power is generated in a second turbine ( 58 ) with heat recovered from exhaust produced by the first turbine ( 48 ). Power is generated in a third turbine ( 82 ) with heat recovered from the syngas ( 33 ).

Description:
FIELD OF THE INVENTION 
     The present invention relates generally to power systems, and more particularly, to combined cycle power generation systems. 
     BACKGROUND OF THE INVENTION 
     Continual increases in the price of natural gas and fuel oil, and demands for generating electricity with reduced environmental impact, are stimulating advancements in technologies for deploying Integrated Gasification Combined Cycle (IGCC) power systems. Design of new power plants and retrofitting of older facilities, e.g., conversion of natural gas combined cycle (NGCC) plants to IGCC plants, present opportunities to develop systems and methods which increase overall power plant efficiencies. 
     In IGCC systems, a carbonaceous fuel such as coal is converted to a synthetic gas fuel, termed syngas. This is a mixture typically formed in a gasifier by partial oxidation of hydrocarbons at elevated temperatures. Oxygen-blown gasifiers typically source oxygen in order to minimize generation of by-products such as NO x  compounds. An oxygen source can be developed in a high temperature air separation process which uses an Ion Transport Membrane (ITM) Air Separation Unit. When syngas is generated by gasification of coal with oxygen, typical constituents of the syngas include H 2 , CO, CO 2 , and CH 4 . Often the syngas will include impurities such as sulfides, nitrous components, and dust particles. The latter are normally removed from the mixture prior to combustion in order to provide an environmentally clean exhaust gas from the combustion turbine. 
     Syngas produced in an IGCC system is typically directed to a gas combustor for oxidation and generation of high pressure, high temperature exhaust which is sent to a gas turbine to provide a first source of mechanical power. Sensible heat, present in various fluids within the gasification subsystem of the IGCC system, or within the associated gas turbine subsystem, is commonly recovered by generating steam. Normally, most of the steam is routed through a turbine. 
     The efficiency of large scale commercial gasification systems are typically below 80 percent. Means of improving the efficiency of these and other power generating systems are desired, as even small improvements in plant efficiency have large impacts on the cost and viability of electrical power production from carbonaceous solid fuel sources. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Features of the invention will be best understood when the following detailed description is read in conjunction with the accompanying drawings, wherein: 
         FIG. 1  is a schematic representation of an IGCC system constructed according to one embodiment of the invention; 
         FIG. 2  is a schematic representation of a syngas clean-up unit in the system of  FIG. 1 ; 
         FIG. 3  illustrates a Rankine cycle in the system of  FIG. 1 ; 
         FIG. 4  is a schematic representation of an IGCC system according to an alternate embodiment of the invention; and 
         FIG. 5  illustrates a Rankine cycle in the system of  FIG. 4 . 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     The Rankine cycle of an IGCC power generation system is normally powered by sensible heat recovered from hot, expanded gas exhausted by the gas turbine. After exiting the gas turbine, this hot gas is typically routed through a Heat Recovery Steam Generator (HRSG) to create a supply of high temperature, high pressure steam for the turbine section. 
     The gasification process is exothermic, creating syngas at such a high temperature that it must be cooled before undergoing conventional cleaning processes to remove undesirable impurities. Syngas coolers often generate steam which may also be directed to the turbine section although a portion of the steam may heat a saturator loop which adds moisture to the syngas. Heat from the hot syngas may also be transferred to amine condensate used for sulfur removal in the syngas cleaning process. However, due to practical limitations, a portion of the heat generated in the gasification and gas turbine subsystems is not recovered. 
     In accord with the invention, an exemplary IGCC system includes at least first and second Rankine cycles with the first Rankine cycle receiving sensible heat from high temperature heat sources including the hot, expanded gas exhausted by the gas turbine via the HRSG. This superheated steam expands in a steam turbine to generate mechanical power. An exemplary second Rankine cycle enables extraction of sensible heat from other heat sources in the IGCC system, including sources which might otherwise not be utilized for heat recovery, to generate additional mechanical power and increase overall system efficiency. Both Rankine cycles may use water as the working fluid, but in some embodiments of the invention an organic fluid may be preferred. 
     The invention concepts may be practiced with existing and retrofitted power systems, as well as new power generation systems. In a first exemplary embodiment of the invention, an IGCC system  100  shown in  FIG. 1  includes a gasification subsystem  1 , a gas turbine subsystem  2 , a first Rankine cycle  3 , and a second Rankine cycle  4 . 
     The gasification subsystem  1  includes a gasifier unit  24 , an ITM air separation unit  17 , an air pre-heater  16 , an air compressor  13 , a syngas cooler  30 , and a syngas clean-up unit  32 . These and other components are merely exemplary, and could readily be substituted with other well known components capable of performing similar functions. For example, the ITM air separation unit could be replaced with a cryogenic air separation unit. It also includes an oxygen cooler  23 , an oxygen-depleted air cooler  21 , an oxygen-depleted air quench column  22 , a slag cooler  27 , an auxiliary boiler  67 , and an auxiliary boiler heat exchanger  76 . Components of the syngas clean-up unit  32 , including heat exchangers forming part of the Rankine cycle  4 , are illustrated in  FIG. 2 . 
     In the gasification subsystem  1  the gasifier  24  receives a hydrocarbon fuel  11 , such as coal slurry, and oxygen  18 . The compressor  13 , driven by a motor  14 , inducts ambient air  12  and delivers high pressure air  15  to the pre-heater  16  which elevates the air temperature prior to entry into the ITM Air Separation Unit (ASU)  17 . The ITM ASU  17  produces a supply comprising a high concentration of oxygen  18  and a supply of oxygen-depleted air  19 , primarily nitrogen, while operating in a temperature range of about 1500-1700° F. (816-927 C). The hot oxygen, generally in the temperature range of about 1500-1700° F. (816-927 C), is sent through the cooler  23  for temperature reduction prior to entry into the gasifier  24 . The hot oxygen-depleted air, also in the temperature range of about 1500-1700° F. (816-927 C), is processed through the cooler  21  and the air quench column  22 , each placed in an oxygen-depleted air supply line  20  which provides the oxygen depleted air  19  to a high pressure air supply line  41  in the gas turbine subsystem  2 . In the gasifier  24  the hydrocarbon fuel  11  undergoes partial oxidation to generate primarily carbon monoxide and hydrogen in an exothermic reaction. This hot syngas  26  exits the gasifier  24 , generally in the temperature range of about 1800-2500° F. (982-1371 C). 
     The gasifier  24  also produces molten slag  25  which is composed of inorganic material present in the fuel  11 . The slag  25  is continually removed from the gasifier  24  and cooled in the heat exchanging slag cooler  27  for disposal as a solid material  28 . To meet air quality requirements impurities present in the syngas  26 , such as sulfur, nitrous oxide, and dust particles, are removed in the gas clean-up unit  32 . Prior to entering the clean-up unit  32 , the syngas cooler  30  reduces the temperature of the syngas  26 . The gas clean-up unit  32  comprises one or more cyclones, water scrubbers, and sulfur removal processing equipment. Typical components of the syngas clean-up unit  32  are shown in  FIG. 2 . 
     The auxiliary boiler  67  in the gasification subsystem  1  receives a portion  68  of the feed-water  64  from the feed-water pump  63  in the first Rankine cycle  3  and converts this into a supply of steam  70 . The steam  70  enters the steam chest  71 . Hot exhaust from the boiler  67 , typically 2000-2500° F. (1093-1371 C), is directed to the boiler exhaust cooler  76  for recovery of heat, shown in this example as effected by heating the steam  86  associated with the second Rankine cycle  4 . 
     The gas turbine subsystem  2  includes an air-compressor  38 , a combustor  44 , a rotor cooling air heat exchanger  49 , a gas turbine  48 , and an electrical generator  36 . The compressor  38  inducts ambient air  37  and produces pressurized air  40  which is directed to the combustor  44 . Nitrogen or oxygen-depleted air  19  is added to the compressed air  40 , forming a supply of diluted compressed air  42 . The dilution reduces flame temperature and NO x  formation in the gas combustor  44 . 
     The cleaned syngas  33  flows into the gas combustor  44  through a fuel supply line  34 . Steam  72  is routed from the steam chest  71  through a steam supply line  73  and is added to the syngas  33  to regulate the combustion process temperature, the internal combustor temperature profile, and the combustor exit temperature by varying the steam flow rate. The mixture  37  of steam  72  and syngas  33  enters into the combustor  44  of the gas turbine subsystem  2 . The fuel mixture  37  reacts with the diluted air  42  in the combustor  44  to produce a hot, pressurized gas  46  which is directed into the gas turbine  48  where the hot gas  46  expands, thereby producing power in a rotor shaft  50  to drive both the compressor  38  and the electrical generator  36 . As a result of having been expanded in the turbine  48 , the temperature of the expanded gas  46  exhausted from the turbine  48  is considerably lower than the temperature of the hot gas  46  entering the turbine  48 . The expanded gas  46 , typically in the range of 850°-1100° F. (454-593 C), is directed to the Heat Recovery Steam Generator (HRSG)  66  in the first Rankine cycle for recovery of heat. As illustrated, a portion  47  of the pressurized air  40  exiting the compressor  38  may be routed through the gas turbine  48  to cool the rotor assembly in the turbine  48 . The heated air  47  exiting the turbine  48  is cooled in the rotor cooling air heat exchanger  49  and is then mixed with the incoming air  37 . 
     The first Rankine cycle  3  comprises a heat recovery steam generator  66 , the steam chest  71 , a steam turbine  58 , an electrical generator  54 , a condenser  61 , and a feed-water pump  63 . The steam turbine  58  receives a supply of high pressure, high temperature steam  74  from the steam chest  71 . This working steam, generally at 1300-2000 psia (8961-13786 kPa), and 900-1100° F. (482-593 C), passes through the turbine  58 , producing power in the rotor shaft  56  to drive the electrical generator  54 . In other designs, the steam turbine  58  may be coupled to the shaft  50  and generator  36  of the gas turbine subsystem  2 . Upon exiting the turbine  58  the cooled, expanded steam  74  enters the condenser  61  for recycling as feed-water  64 . Fresh water  60  is supplied to the condenser  61  to compensate for the loss of water in the system  100 . The feed-water  64  with assistance of the pump  63  flows into the HRSG  66  where it is converted to superheated steam  69  as it receives heat from the hot effluent gas  46  exhausted from the gas turbine  48 . After flowing through the HRSG  66 , the cooled, expanded gas  46  is then discharged to atmosphere via a stack  79  while the superheated steam  69  is sent to the steam chest  71 . 
     The second Rankine cycle  4  includes a steam turbine  82 , an electrical generator  80 , a condenser  84 , and a feed-fluid pump  87 . The steam turbine  82  receives a supply of low pressure, low temperature steam  86 , relative to the steam  74  generated in the HRSG  66 , from an auxiliary boiler exhaust heat exchanger  76 . The steam  86  powers the turbine  82  with an entry temperature in the range of 700°-800° F. (371-427 C) and pressure in the range of 15-25 psia (103-172 kPa), and turns the rotor shaft  81  to drive the electrical generator  80 . In other designs, the steam turbine  82  may be coupled to the shaft  50  and generator  36  of the gas turbine subsystem  2  or to the shaft  56  and generator  54  of the first Rankine cycle  3 . 
     Upon exiting the turbine  82  the cooled, expanded steam  86  enters the condenser  84  for recycling as feed-water  85 . The pump  87  moves the feed-water  85  through a network of heat exchangers in the system  100  which generate the steam  86  and elevate it to a superheated state. With reference to both  FIG. 1  and  FIG. 2 , initially the feed-water  85  is circulated under relatively low pressure, generally in the range of 25-35 psia (172-241 kPa), through a line  90  to the syngas cleaning unit  32  where it extracts heat from an MDEA cooler  180 . The water  85  then flows out of the syngas cleaning unit  32  through line  91  to the slag cooler  27  where it to receives heat from the hot slag  25 . The water  85  next returns through line  92  to the syngas clean-up unit  32  where it flows through a water scrubber heat exchanger  107  which transfers heat from a first water scrubber  104 . The water  85  then flows through line  193  to enter a sour gas heat exchanger  138  for further heating, followed by flow through line  194  into a sour water heat exchanger  130  to receive heat from syngas exiting a second water scrubber  126 . 
     Next the water  85  flows through line  195  to a saturator heat exchanger  188  where it receives heat from exhaust gas  187 , being output by a saturator heater  186 . The water  85  then flows through line  196  to the syngas heat exchanger  118  to receive heat from hot syngas which flows between a cross heat exchanger  110  and a COS hydrolysis unit  122 . The heated water  85  then flows through line  93  and out of the syngas clean-up unit  32  to the oxygen cooler  23  where it receives heat from the hot oxygen  18  exiting the ITM ASU  17 . The water  85  then flows through line  94  to the oxygen-depleted air cooler  21  to receive heat from the hot oxygen-depleted air  19 . The hot water  85  then flows through line  95  to the rotor cooling air heat exchanger  49  where it is converted to steam with heat received from rotor cooling air  47  that exits the gas turbine  48 . 
     The steam  86  is then superheated, first flowing through line  96  to the syngas cooler  30  where it receives further heating from the hot syngas  26  exiting the gasifier  24 ; and then traveling to through the boiler exhaust cooler  76  which transfers heat from the exhaust  75  exiting the auxiliary boiler  67 . The steam  86  may also be heated at various stages with supplemental sources including tail gas exhaust from the sulfur recovery unit (not shown), Claus reactors and a SCOT reactor in the sulfur recovery unit (not shown). 
     Syngas from a coal gasifier contains impurities such as entrained soot, ash, H 2 S, NH 3 , COS, and HCN, which are removed in the syngas purification process. First, ashes and inorganic particles are removed in cyclones and water scrubbers. Then the syngas is further cooled to a temperature suitable for a hydrolysis reaction, generating sour gas, i.e., a form of syngas containing H 2 S, CO 2 , and ammonia. After the ammonia is removed in a water scrubber and the H 2 S and CO 2  are removed in an MDEA contactor connected to an MDEA regenerator, the cleaned syngas is saturated with steam and send through a final filter before entering the gas combustor  44 . The MDEA solution, rich in H 2 S and CO 2 , is heated in the MDEA regenerator to generate fresh MDEA and release a stream of acidic gas, primarily comprising H 2 S, CO 2 , and water vapor. In a sulfur recovery unit the H 2 S is converted to elemental sulfur for disposal. Heat exchangers may be included to recover sensible heat from numerous heat sources present in the syngas purification process. 
     The syngas clean-up unit  32  includes a cyclone  101 , the first water scrubber  104 , the syngas cross heat exchanger  110 , a COS hydrolysis unit  122 , the second water scrubber  126 , a sour water accumulator  134 , an MEDA contactor  142 , a syngas saturator  184 , the saturator heater  186 , and a final filter  192  for generating clean syngas  33 . It also includes a rich MDEA surge drum  148 , an MDEA cross heat exchanger  152 , an MDEA regenerator  158 , an MDEA reboiler  160 , an MDEA circulation pump  164 , a condensate accumulator  170 , and a sulfur recovery unit  174  for recovery of sulfur  177 . In addition, the syngas clean-up unit  32  includes a network of heat exchangers: the MDEA cooler  180 , the water scrubber heat exchanger  107 , the sour gas heat exchanger  138 , the sour water heat exchanger  130 , the saturator heat exchanger  188 , and the syngas heat exchanger  118 . 
     In the syngas clean-up unit  32 , syngas  31  flowing from the syngas cooler  30  first enters the cyclone  101 , which centrifugally removes the ash and mineral particles  103 . The syngas  102  exiting the cyclone  101  travels to the first water scrubber  104  where char in the syngas  102  is removed. The syngas  105  leaving the first water scrubber  104  is in the temperature range of 250-350° F. (121-177 C). Water containing the char  106  is directed to the water scrubber heat exchanger  107  for recovery of heat. The syngas  105  is then further cooled by several hundred degrees, e.g., to the range of 500-700° F. (260-371 C), when passing through the syngas cross heat exchanger  110  where the relatively hot syngas  105  heats cleaned syngas  189  exiting the syngas saturator  184 . The cooled syngas  105  is routed through line  111  to the syngas heat exchanger  118  while the warmed clean syngas  189  travels through line  191  to the final filter  192 . The syngas heat exchanger  118  transfers heat from the syngas  105  exiting the cross heat exchanger  110  before the gas  105  travels through the line  120  to the COS hydrolysis unit  122 . 
     The COS hydrolysis unit  122 , operating in the temperature range of 250°-350° F. (121-177 C), hydrolyzes the syngas constituents COS and HCN to form CO 2 , H 2 S, NH 3  and CO. The sour gas  123 , i.e., syngas containing H 2 S, exiting the COS hydrolysis unit  122  is directed to the second water scrubber  126  through a line  124  to remove water-soluble gases such as NH 3 . The warm sour gas  127  flowing out of the water scrubber  126  through line  128 , generally at 270°-330° F. (132-166 C), is cooled to 220°-250° F. (104-121 C) in the sour water heat exchanger  130 . The cooled sour gas  127  enters the sour water accumulator  134  through line  132  where moisture in the sour gas  127  is removed. The dry sour gas  135  is directed through line  136  to the sour gas heat exchanger  138  and cooled further to 90°-110° F. (32-43 C). Traveling through line  140 , the sour gas  135  enters the bottom of the MDEA contactor  142  for H 2 S separation. A supply of fresh MDEA  181  enters the top of the contactor  142  through a line  182  from the MDEA cooler  180 . An acid-gas-rich-amine solution  145  leaves the bottom of the contactor  142  through a line  146  at an elevated temperature. Through line  144  the cleaned syngas  143  exiting the MDEA contactor  142  travels to the saturator  184  in which the syngas  143  is saturated with moisture  185  circulating from the saturator heater  186 . The heat exchanger  188  recovers heat from exhaust of the saturator heater  186 . The moisture-saturated syngas  189  exiting the saturator  184  is directed to the syngas cross heat exchanger  110  to receive heat from the hot syngas  105  before entering the final filter  192 . After passing the final filter  192 , the cleaned syngas  33  is routed to the combustor  44  in the gas turbine subsystem  2  through a fuel supply line  34 . 
     The MDEA solution  145  containing H 2 S and CO 2  travels to the rich MDEA surge drum  148  from the MDEA contactor  142 . The surge drum  148  allows separation of hydrocarbon liquid  151  from the solution  149 . The MDEA solution  149  exiting the surge drum  148  is routed to the MDEA cross heat exchanger  152  through line  150  and then on to the MDEA regenerator  158 . In the MDEA cross heat exchanger  152 , the MDEA solution  149  containing H 2 S and CO 2  is heated by a fresh MDEA solution  161  from the MDEA regenerator  158  delivered to the heat exchange  152  through line  166 . H 2 S and CO 2  in the MDEA solution  149  are then removed in the MDEA regenerator  158  by heating the solution  149  to the range of 100°-200° F. (38-93 C) MDEA solution  149  entering the regenerator  158  is continuously heated with circulating steam  159  from the MDEA boiler  160  and fresh MDEA solution  161  travels with assistance of the MDEA pump  164  from the regenerator  158 , through lines  162  and  166  to the MDEA cross heat exchanger  152 . The cooled MDEA  161  exiting the cross heat exchanger  152  travels to the MDEA cooler  180  for further temperature reduction. 
     Acid gas  167 , exiting the MDEA regenerator  158 , is routed to the condensate accumulator  170 . Condensate  173  in the accumulator is mostly water which is drained. The remaining acid gas  171  enters the sulfur recovery unit  174  where H 2 S is converted to sulfur  177  for disposal while the tail gas  175  is routed to the gasifier  24 . 
       FIG. 3  illustrates an exemplary order in which a series of exchangers transfer heat to the working fluid in the second Rankine cycle  4 . 
     The second Rankine cycle  4  is based on recovery of heat from multiple sources ranging from a low temperature, e.g., below 800° F., to upwards of 2100° F. (1149 C). In the embodiment of the system  100 , water is a suitable working fluid when some of the heat sources have relatively high temperatures, e.g., 1600-2100° F. (871-1149 C). An organic fluid, such as R-245fa, can be more effective as the working fluid than water if the maximum temperature of the heat sources is below 800° F. (427 C). At higher temperatures organic fluids can create non-condensable substances that degrades the performance of heat recovery. However, for low temperature heat sources, organic fluids generally having a lower boiling point, a lower specific volume, and a lower specific volume than water, the higher mass flow rate of these organic fluids can result in extraction of more heat per unit volume, thereby improving the efficiency of the Rankine cycle. 
       FIG. 4  illustrates an IGCC system  200  according to another embodiment of the invention wherein a first Rankine cycle  3  receives high temperature, high pressure steam from a steam chest  271  and a second Rankine cycle  6  operates with a working fluid receiving heat recovered from multiple low temperature heat sources, e.g., below 800° F. (427 C). The operation of the system  200  differs from the system  100  shown in  FIG. 1  in that heat recovered from high temperature sources such as the syngas cooler and the auxiliary boiler is part of the first Rankine cycle  3  which uses water as the working fluid. The system  200  includes the gas turbine subsystem  2  and the first Rankine cycle  3 , as described with respect to  FIG. 1 , a gasification subsystem  5  and the second Rankine cycle  6 . 
     The gasification subsystem  5  includes a gasifier unit  24 , an ITM air separation unit  17 , an air pre-heater  16 , an air compressor  13 , a syngas clean-up unit  32 , and a syngas cooler  230 . It also includes an oxygen cooler  23 , an oxygen-depleted air cooler  21 , an oxygen-depleted air quench column  22 , a slag cooler  27 , and an auxiliary boiler  67 . 
     In the gasification subsystem  5 , the gasifier unit  24  receives a hydrocarbon fuel  11 , e.g., a coal slurry, and oxygen  18  from the ITM ASU  17 . The compressor  13 , driven by motor  14 , inducts the ambient air  12  and delivers the high pressure air  15  to the pre-heater  16 . The hot oxygen  18  exiting the ITM ASU  17  is cooled in the oxygen cooler  23  before entering the gasifier  24 . The oxygen-depleted air cooler  21  and the oxygen-depleted air quench column  22 , each placed in the oxygen-depleted air supply line  20 , cool the oxygen depleted air  19  before it enters the high pressure air supply line  41  in the gas turbine subsystem  2 . 
     In the gasifier unit  24  the hydrocarbon fuel  11  undergoes partial oxidation to generate hot syngas  26 . The gasifier  24  also produces molten slag  25  which is continually removed from the gasifier  24  and cooled down in the heat exchanging slag cooler  27  for disposal. Impurities present in the syngas  26 , such as sulfur, nitrous oxide, and dust particles, are removed in the gas clean-up unit  32 . Prior to entering the clean-up unit, the syngas cooler  230  reduces the temperature of the syngas  26 . A portion  65  of the feed-water  64  in the first Rankine cycle  3  circulates through the syngas cooler  230  to recover syngas heat and be converted into steam  229  which is then sent to the steam chest  71 . The gas clean-up unit  32  comprises one or more cyclones, water scrubbers, and sulfur removal processing equipment such as shown in  FIG. 2 . The auxiliary boiler  67  in the gasification subsystem  5  receives a portion  68  of the feed-water  64  from the feed-water pump  63  in the first Rankine cycle  3  for conversion into steam  70  which is also sent to the steam chest  71 . 
     The second Rankine cycle  6  includes a vapor turbine  282 , an electrical generator  280 , a condenser  284 , and a feed-fluid pump  287 . In the second Rankine cycle  6 , the pump  287  develops a high pressure to send a working fluid  285  through a network of heat exchangers. The working fluid  285  flows through a line  90  to the syngas cleaning unit  32  where it absorbs heat from an MDEA cooler (such as the cooler  180  shown in  FIG. 2 ), and the fluid  285  next flows through a line  91  to the cooler  27  where it receives heat from hot slag  25 . The fluid  285  then returns to the syngas clean-up unit  32  through line  92  where, as shown in  FIG. 2 , it is further heated in a water scrubber heat exchanger  107 , receiving heat from hot water  106  that exits a first water scrubber  104 . The fluid  285  then flows through line  193  to receive heat from hot sour gas  135  in the heat exchanger  138 . The fluid  285  also flows through line  194  to a sour water heat exchanger  130  where it receives heat from syngas exiting a second water scrubber  126 , and then flows through line  195  to the saturator heat exchanger  188  to receive heat from an exhaust gas  187  from the saturator heater  186 . 
     After exiting the exchanger  188 , the fluid  285  flows through a line  196  to a syngas heat exchanger  118  to cool hot syngas  105  leaving a cross heat exchanger  110  ( 110 ,  118 ,  105 , and  196  are shown in  FIG. 5 ). The heated fluid  285  then exits the syngas clean-up unit  32  and flows through line  93  to the oxygen cooler  23  where it receives heat from hot oxygen  18  and next flows through a line  94  to the oxygen-depleted air cooler  21  to receive heat from the hot oxygen-depleted air  19 . 
     The hot fluid  285  flows through line  95  to receive heat from the rotor cooling air  47  in heat exchanger  49 . The heated fluid  285  is next directed into the vapor turbine  282  where the working fluid  285  expands, thereby producing power in a rotor shaft  281  to drive the electrical generator  280 . After passing through the turbine  282  the cooled, expanded vapor  286  enters the condenser  284  for recycling as feed-fluid  285 . Other heat sources such as tail gas exhaust from the sulfur recovery unit (not shown), Claus reactors and a SCOT reactor in the sulfur recovery unit (not shown) may be integrated with the second Rankine cycle  6  for recovery of more heat. 
       FIG. 5  illustrates an exemplary order in which heat exchangers heat the working fluid for the second Rankine cycle  6  from heat sources which can be ordered to thermodynamically optimize the heat recovery system. 
     With the second Rankine  6  cycle recovering heat from a range of sources, the second cycle can be incorporated into existing IGCC systems and NGCC systems retrofitted to operate as IGCC systems without requiring redesign and replacement of key components such as the HRSG. In designs with the second Rankine cycle  6  recovering heat from the syngas cooler, the operation of the HRSG, which is normally running at high pressure, is not adversely affected. 
     Chemicals used as an organic working fluid for the second Rankine cycle  6  may include halocarbon refrigerants, such as R-245fa, hydrocarbon gases, ammonia, and carbon dioxide, or a mixture thereof. An exemplary hydrocarbon gas is isopentane. The heat exchangers for the working fluid in the system  200  may be optimally designed for a selected working fluid. 
     Use of organic working fluids in the lower temperature Rankine cycle  6  in the system  200  brings advantages of a low boiling point, a low specific volume and a low critical pressure. These characteristics enable the organic fluid to perform in under supercritical conditions while at a relatively low temperature, and with a relatively small turbine, thereby reducing the capital cost of installing the cycle. When in the vapor state the organic working fluid may have a minimum temperature of 250° F. (121 C) but the minimum temperature may range between 200° F. (93 C) and 280° F. (138 C). The maximum temperature of the organic vapor may be about 300° F. (149 C), but may range from 280° F. (138 C) to at least 325° F. (163 C). 
     Operating a second low temperature, low pressure Rankine cycle with an organic fluid in a supercritical mode, at pressures above the critical pressure, increases the heat transfer efficiency as the heat transfer to the fluid is more efficient than when performing an analogous process using water as the working fluid. This is because, in the low temperature, low pressure cycle, the temperature differences between the working fluid and the various heat sources are relatively small while the organic fluid is able to reach a supercritical superheated state. 
     When using an organic fluid, such as Genetron 245fa, there is no need for superheating the fluid before expanding it in the turbine because it has a positive slope in its saturation vapor line in the two-phase dome. This decreases the size of the heat exchangers needed and reduces the possibility of having moisture at the outlet of the turbine. Use of an organic working fluid in the second Rankine cycle may be best suited for new IGCC power generation plants where the HRSG and steam turbine can be optimally designed to recover heat from the greatest number of heat sources, e.g., all sources above 800° F. (426 C). Recovery of heat from these relatively low temperature heat sources is more effective when the working fluid is above the critical pressure and a relatively small temperature difference between the working fluid and the heat source provides a higher heat transfer efficiency. For example, an organic fluid critical pressure of about 530 psia (3653 kPa) is far less than the 3200 psia (22058 kPa) critical pressure of water. 
     While the preferred embodiments of the invention have been illustrated and described, the invention is not so limited. Numerous modifications, changes, variations, substitutions and equivalents will occur to those skilled in the art without departing from the spirit and scope of the invention which is only limited by the claims which follow.