Abstract:
A method of generating electricity in synthesis gas in which a fuel is combusted in a gas turbine to generate the electricity that at least about 60 percent by volume is derived from a source independent of the synthesis gas. The synthesis gas is produced by reacting a hydrocarbon stream, by for example, partial oxidation, autothermal reforming or steam methane reforming. After the synthesis gas stream is cooled, heat is transferred from the heated synthesis gas stream to the fuel prior to combustion in the gas turbine. All or at least a portion of the heat is transferred at a temperature no greater than about 500° F. and at a flow ratio of the fuel to the gas turbine to the synthesis gas stream from at least about 1.5. The heating of the fuel to the gas turbine lowers fuel consumption and thereby the total expenses involved in generating electricity and syngas.

Description:
FIELD OF THE INVENTION 
     The present invention provides a method of generating electricity and synthesis gas in which heat is transferred from a synthesis gas stream to a fuel fed to combustors of a gas turbine used in generating the electricity. More particularly, the present invention relates to such a method in which the heat is transferred at a low temperature of no greater than about 500° F. and the fuel fed to the gas turbine has a composition that is at least 60 percent volume derived from a source that is independent of the synthesis gas stream. 
     BACKGROUND OF THE INVENTION 
     Synthesis gases, that is, gases that contain hydrogen and carbon monoxide are produced by steam methane reforming, autothermal reforming, partial oxidation, either catalytic or non-catalytic. The resultant synthesis gas stream can be further processed in a water gas shift reactor to increase its hydrogen content and the hydrogen can be separated from the synthesis gas to produce a hydrogen product stream though pressure swing adsorption. 
     Gas turbines are very commonly located at synthesis gas production sites. In this regard, commonly, the fuel for both the gas turbine and the hydrocarbon containing reactant fed for the synthesis gas production is natural gas. Where such installations exist, the gas turbines are not normally thermally linked to the synthesis gas production. In integrated gasification combined cycles, however, the gas turbine and the synthesis gas production are both thermally and operationally linked in that the fuel to the gas turbine is the synthesis gas and the synthesis gas is reheated through heat transfer with the synthesis gas stream being produced. 
     For example, in EP 0 575 406 B1, fuel and oxygen are reacted in a partial oxidation reactor to produce a synthesis gas stream. After the synthesis gas stream is quenched and water is removed in a knock-out drum at high temperature, the synthesis gas stream is subjected to a water gas shift reaction at a temperature of between 260° C. and 472° C. The heat created by the exothermic shift reaction is used in downstream heat exchangers to reheat the fuel stream to the gas turbine to a temperature of about 390° C. The fuel for the gas turbine is derived entirely from the synthesis stream. In this regard, in cooling stages occurring subsequent to the water gas shift, water is removed from the synthesis gas stream. After sulfur removal, the synthesis gas is reheated and, as stated previously, used as fuel to the gas turbine. As can be appreciated, all of the cooling steps and water removal act to remove heat from the synthesis gas stream at low temperature levels. Much of this heat is simply dissipated without being recovered. 
     As will be discussed, the present invention, unlike the prior art related to the utilization of synthesis gas in integrated gasification combined cycles, relates to a method of generating electricity and synthesis gas in which a gas turbine is not coupled to the synthesis gas production by the use of the synthesis gas as the dominant fuel source. This allows the heat within the synthesis gas to be recovered at low temperature and transferred to the gas turbine fuel. This provides an increase in gas turbine efficiency and therefore a net cost savings. 
     SUMMARY OF THE INVENTION 
     The present invention provides a method for integrating electrical power generation with synthesis gas production. In accordance with the method, a synthesis gas is produced by reacting a hydrocarbon stream with a reactant to form a synthesis gas stream. The synthesis gas stream is subsequently cooled and water is removed. Additionally, a fuel is combusted in a gas turbine to generate the electrical power. At least about 60 percent by volume of the fuel is derived from a source that is independent of the synthesis gas. For example, the fuel to the gas turbine could be natural gas mixed with up to about 40 percent synthesis gas. Heat is transferred from the synthesis gas stream to the fuel prior to combustion in the gas turbine. At least a portion of the heat is transferred at a temperature of no greater than 500° F. and at a flow ratio of the fuel to the synthesis gas stream of at least 1.5. In this regard, heat transfer of low temperature streams is defined for purpose of the invention at a temperature of less than about 500° F. 
     By utilizing a fuel that in major part is not derived from the synthesis gas stream and ratios of flow rates of the fuel and the synthesis gas stream of 1.5 and greater, the low temperature heat, which in the prior art is simply dissipated, can be used to preheat fuel to the gas turbine. Such preheating decreases the fuel requirements of the gas turbine and therefore, the cost in producing electricity. Such a reduced cost can be applied to the entire integration of electricity and synthesis gas production, and therefore hydrogen production, to provide economic efficiencies in an integration of the present invention that are not obtained in the prior art. 
     The hydrocarbon stream can be reacted in a partial oxidation reactor or an autothermal reforming reactor or a steam methane reformer. Further, the hydrogen content of the synthesis gas stream can be increased by a water gas shift reaction. 
     Steam may also be generated. Hydrogen can be separated from the synthesis gas stream to also produce a calorific tail gas stream. The combustion of the fuel in the gas turbine produces a heated exhaust and the calorific tail gas stream is combusted in a burner by combustion supported at least in part with the heated exhaust from the gas turbine to generate further heat. The further heat can be transferred to feed water to raise steam. 
     Water can be removed from the synthesis gas stream after the water gas shift reaction and within first and second cooling stages in which the second of the cooling stages operating at a lower temperature than the first of the cooling stages. Each of the first and second cooling stages has a heat exchanger to cool the synthesis gas stream followed by a knock-out drum to collect the water. The heat transfer from the synthesis gas stream to the fuel takes place within the second of the cooling stages and then the first of the cooling stages and in the heat exchanger associated with each of the first and second cooling stages. Alternatively, water can be removed from the synthesis gas stream by cooling the synthesis gas stream after the water gas shift reaction within first second and third heat exchangers and then introducing the synthesis gas stream into a knock-out drum to collect the water. At least part of the fuel to the gas turbine is heated in the third heat exchanger. The third heat exchanger is positioned between the first and second heat exchangers. 
     The fuel gas stream can be heated within a heat exchanger having passages for the fuel, the synthesis gas stream and cooling water. The cooling water can be used to trim the operation or to provide a heat transfer fluid when the gas turbine is removed from service. Another alternative is to transfer heat from the synthesis gas stream to the fuel by transferring the heat from the synthesis gas stream to a circulating heat transfer fluid and then transferring the heat from the circulating cooling fluid to the fuel. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       While the specification concludes with claims distinctly pointing out the subject matter that Applicants regard as their invention, it is believed that the invention would be better understood when taken in connection with the accompanying drawings in which: 
         FIG. 1  is a schematic process flow diagram for carrying out a method in accordance with the present invention; 
         FIG. 2  is a process flow diagram of an alternative embodiment of the method in accordance with the present invention; 
         FIG. 3  is an alternative heat exchange configuration of the present invention that is exemplified with respect to the method of  FIG. 2 ; 
         FIG. 4  is an alternative heat exchange configuration of the present invention that is exemplified with respect to the method of  FIG. 2 ; and 
         FIG. 5  is an alternative heat exchange configuration of the present invention that is exemplified with respect to the method of  FIG. 2 . 
     
    
    
     DETAILED DESCRIPTION 
     With reference to  FIG. 1 , an apparatus  1  for carrying out a method in accordance with the present invention is illustrated. A natural gas stream  10  is introduced into a catalytic partial oxidation reactor  12  along with an oxygen stream  14  and a steam stream  16 . Catalytic partial oxidation reactor  12  contains a partial oxidation catalyst to promote partial oxidation of hydrocarbons contained within natural gas stream  10  to produce a synthesis gas stream  18  containing hydrogen, carbon monoxide, water and carbon dioxide. The synthesis gas stream  18  is introduced into a water gas shift unit  20  that includes a water gas shift reactor containing a shift catalyst as well as known heat exchangers for steam generation and preheating of feeds to catalytic partial oxidation reactor  12 . For exemplary purposes synthesis gas stream  18  is produced at a temperature of 1750° F. and a pressure of about 315 psia. The natural gas stream  10 , available at 77° F. and 330 psia, is introduced into the catalytic partial oxidation reactor  12  after being preheated within unit 20 to 475° F. 
     Water gas shift unit  20 , by water gas shift conversion, increases the hydrogen content of the synthesis gas stream  18  to produce a synthesis gas stream  22  having a hydrogen content that is greater than that of synthesis gas stream  18 . Synthesis gas stream  22  can have a temperature of about 700° F., a pressure of about 300 psia, and a flow rate of about 21.2 MMSCFD. Further, synthesis gas stream  22  can have a composition as follows: a hydrogen content of about 58.3 mol percent, a water content of about 17.3 mol percent, a carbon monoxide content of about 3.5 mol percent, a carbon dioxide content of about 18 mol percent and a methane content of about 2.9 percent. All of these percentiles are on a volume basis. The process heat contained within synthesis gas stream  22  is extracted by heat exchangers  24  and  26 . 
     A gas turbine fuel stream  27 , which can be natural gas having a flow rate of about 43.6 MMSCFD, is passed through heat exchange passes located within heat exchangers  24  and  26  and is then fed to a gas turbine  28 . Gas turbine fuel stream  27  emerges from heat exchanger  26  at a temperature of about 245° F. and thereafter, from heat exchanger  24  at a temperature of about 370° F. before being introduced into gas turbine  28 . As can be appreciated, gas turbine  28  is located as close as possible to catalytic partial oxidation unit  12  and water gas shift unit  20 , heat exchangers  24  and  26  and etc. to minimize fuel pressure and heat losses. 
     Synthesis gas stream  22  is cooled in heat exchanger  24  to a temperature of about 375° F. and is then introduced into a heat exchanger  30  to preheat boiler feed water to near saturation for subsequent process steam generation within water gas shift unit  20 , for instance to produce steam stream  16 . The synthesis gas stream  22  exits heat exchanger  30  at about 260° F. and is further cooled to 110° F. in heat exchanger  26 . A trim cooler  32  is provided for back-up cooling. The placement and use of heat exchanger  30  and trim cooler  32  will, however, be dictated by the steam requirements and the exact synthesis gas plant being utilized. Knock-out drums  34  and  36  are located down stream of heat exchanger  30  and heat exchanger  26  for condensate removal via streams  38  and  40 , respectively. Knock-out drum  36  removes most of the condensate, typically over about  70  percent. The resultant cooled dry synthesis gas stream  42  is then separated in a pressure swing adsorption unit  44  (“PSA”) that, as would be known in the art contains, for example beds of alumina, carbon and molecular sieve adsorbent. The beds operate out of phase in a known manner to produce a hydrogen product stream  46 , here with 80 percent recovery and a flow rate of 9.9 MMSCFD and a PSA tail gas stream  48 . 
     Since the catalytic partial oxidation reactor  12  does not require external firing, all of PSA tail gas stream  48  is routed to a heat recovery steam generator  50  containing a duct burner  51 . Also introduced into heat recovery steam generator  50  is a heated exhaust stream  54  produced by gas turbine  28  through the combustion of fuel stream  27 . Such combustion within gas turbine  28  is supported by an air stream  52  that is compressed within gas turbine  28 . 
     Steam is generated within heat recovery steam generator  50  to produce a warm flue gas  56 . Some steam through a steam stream  58  may be introduced into a steam turbine  60  for power generation. 
     Pre-heating fuel stream  27  to 370° F. reduces gas turbine fuel requirements for gas turbine  28  by approximately 0.87 percent. Furthermore, routing the PSA tail gas stream  48  to the heat recovery steam generator  50  boosts the power of steam turbine  60  by roughly 10 percent. This reduces the production costs of hydrogen product stream  46  through the generation of power by approximately 20 percent over production costs that would be required without such integration. In fact, hydrogen production costs of an integration such as illustrated in  FIG. 1  and operated as described above yield production costs that become competitive with much larger facilities based on steam methane reforming. As indicated above, some of the heat in synthesis gas stream  22  is recovered at a temperature below 500° F. or more precisely, as low as about 110° F. This heat would if not recovered in accordance with the present invention would be dissipated or lost to the environment without the efficiency of the present invention being realized. The flow rate ratio of the fuel stream  27  and its makeup of entirely natural gas to the flow rate of the synthesis gas stream of about 2.0 allows such heat transfer and heat recovery in accordance with the present invention to take place. In practice, as indicated below for the embodiment of  FIG. 2 , such ratio is even higher but should in any case be greater than about 1.5. 
     With reference to  FIG. 2 , an apparatus  1 ′ is illustrated for carrying out a method in accordance with the present invention that involves steam methane reforming. In apparatus  1 ′, a hydrocarbon containing feed stream  62  and a steam stream  64  are introduced into a steam methane reformer  66  to produce a synthesis gas stream  68  that contains hydrogen, carbon monoxide, water and carbon dioxide. Synthesis gas stream  68  is in turn introduced into a water gas shift unit  70  that consists of heat exchangers for steam generation and preheating of feeds to reformer  66  and a water gas shift reactor, as discussed above, to produce a synthesis gas stream  72  having increased hydrogen content over that of synthesis gas stream  68 . Synthesis gas stream  72  is cooled within heat exchanger  74  and trim cooler  76  before being introduced into a knock-out drum  78  for removal of water  80 . Synthesis gas stream  72  after having passed through heat exchanger  74  is introduced into a heat exchanger  80  to heat fuel to a gas turbine  82 . 
     In heat exchanger  80 , low value heat is recovered from the incoming synthesis gas stream  72  after having been cooled within heat exchanger  74  to a temperature that is between about 200° F. and about 700° F. Upon exiting the heat exchanger  80 , the synthesis gas will be cooled typically to a temperature of about 150° F. or less for processing within PSA unit  86 . A synthesis gas product stream  88  can be recovered along with a hydrogen product stream  90  and a psa tail gas stream  92  that can be used to fire burners within steam methane reformer  66 . 
     A fuel stream  84  and a subsidiary fuel stream  94  as a combined stream  96  is in part introduced into heat exchanger  80  as a subsidiary stream  98 . A remaining part of the combined stream  96 , namely, subsidiary stream  100 , is recombined with subsidiary stream  98  after having been heated within heat exchanger  80 . The resultant heated combined stream  102  can be combined with a further subsidiary fuel stream  104  to produce fuel stream  106  to be introduced into gas turbine  82  along with air  108  to produce a heated exhaust stream  110 . Subsidiary fuel stream  94  and fuel stream  84  could be partly composed of synthesis product gas stream  88  provided that at least about 60 percent of subsidiary fuel stream  98  is derived from a source independent of the synthesis gas stream  88 . Subsidiary fuel stream  94  and subsidiary fuel stream  104  are optional and could be formed from the synthesis gas product stream  88 . 
     It is to be further pointed out that the heat transfer arrangement illustrated herein could be employed with a catalytic partial oxidation unit, such as unit  12  or optionally, the heat transfer arrangement of  FIG. 1  could be employed with a steam methane reformer, such as designated by reference number  66 . The advantage of the heat exchange arrangement of fuel flows used in connection with heat exchanger  80  is that the temperature of the fuel fed to the gas turbine can be controlled by mixing the heated fuel stream from heat exchanger  80  with an incoming ambient part of the stream  100 . However, as indicated in examples below, all of the fuel could be routed through heat exchanger  80 . 
     Fuel stream  106  is at a temperature of no greater than 400° F. which is the maximum allowable temperature contained in many manufacture-recommendations for gas turbines. The heated gas turbine exhaust  110  is introduced into a burner  112  within a heat recovery steam generator  114  to generate steam and a cooled flue gas stream  116 . Again, a steam stream  118  can be routed to a steam turbine  120  for power recovery. 
     With reference to  FIG. 3 , although heat exchanger  80  is illustrated as a single unit in  FIG. 2 , multiple heat exchangers such as  80   a  and  80   b  could be provided with process heat exchanger  122  situated between heat exchangers  80   a  and  80   b . The fuel gas  98  in such case can be divided into first and second subsidiary streams  124  and  126 . The first subsidiary fuel stream  124  after having been heated in heat exchanger  80   b  is divided into third and fourth subsidiary fuel streams  128  and  130 . Third subsidiary fuel stream  128  is combined with second subsidiary fuel stream  126  and introduced into heat exchanger  80   a  to produce a heated combined fuel stream  132  that is further combined with second subsidiary fuel stream  130  to produce a fuel stream  134  that would be introduced into a gas turbine such as gas turbine  82  as illustrated with respect to  FIG. 2 . 
     With reference to  FIG. 4 , heat exchanger  80  or heat exchangers  24  or  26  may be replaced by heat exchanger  80   c  in which a third cooling stream  135  such as water would only provide trim cooling and for cooling during periods in which gas turbine  82  is brought off line. 
     With reference to  FIG. 5 , heat exchanger  80 , or either of the heat exchangers  24  or  26  for that matter, might be replaced with heat exchangers  80   d  and  80   e  that employ a heat transfer fluid, for instance, water circulating through a heat transfer circuit. A water stream  136  is introduced into the heat transfer circuit and then pumped to high pressure by pump  138 . Excessive temperatures are moderated by a circuit cooler  140 . 
     The following are calculated examples illustrating a variety of possible operational schemes for the embodiment of Applicant&#39; invention as carried out in  FIG. 2 . Unless otherwise specified, in all examples, gas turbine  82  is a Model 7FA gas turbine manufactured by General Electric Energy (4200 Wildwood Parkway, Atlanta, Ga. 30339) being fed with a fuel stream  106  made up of natural gas fuel having the following composition: 92.1 mol % CH 4 , 3.4% C 2 H 6 , 3.2% N 2 , 0.7% CO 2 , 0.6% C 3 H 8 , a pressure of about 325 psia, a temperature of about 60° F. and a nominal flow rate of about 4675 lb-mol/hr. The manufacturer&#39;s recommended maximum allowable fuel temperature is set at about 400° F. The synthesis gas stream  72  is cooled to a target temperature in a range of between about 70° F. and about 120° F. prior to water removal in knock-out drum  78  and further processing within PSA unit  86 . Additionally, it is assumed that heat exchanger  80  is designed with 3 psi pressure drop on both the synthesis gas and fuel sides and with a 30° F. pinch. A further assumption is that the additional gas turbine fuel pressure drop can be managed by the pipeline or fuel compressor used in connection with the source of natural gas. 
     EXAMPLE 1  
     For purposes of this example, synthesis gas stream  72  has a flow rate of about 860 lb-mol/hr and has the following composition: 48 mol percent hydrogen, 35.7 mol percent water, 1.9 mol percent carbon monoxide, 10.8 mol percent carbon dioxide, 0.6 mol percent nitrogen and 3.0 mol percent methane. After passage through heat exchanger  74 , synthesis gas stream  72  has a pressure of about 238 psia and a temperature of about 372° F. Assuming a hydrogen recovery of about 83 percent, approximately 3.12 MMSCFD hydrogen would be produced for hydrogen product stream  90 . In heat exchanger  80 , the synthesis gas stream  72  is further cooled to 100° F. against subsidiary stream  98  that constitutes about 62 percent of combined stream  96 . Subsidiary stream  98  emerges from heat exchanger  80  at a temperature of about 322° F., which upon mixing with subsidiary stream  100 , produces fuel stream  106  at a temperature of about 227° F. In this example no additional fuel is used and hence, subsidiary fuel streams  94  and  104  are not present. The 30° F. pinch point is assume to occur near the warm end of heat exchanger  80 . The resulting preheated fuel stream  106  is calculated to decrease fuel consumption of gas turbine  82  by about 0.49 percent. 
     EXAMPLE 2  
     This example is a modification of Example 1 in which synthesis gas stream  72  has a flow rate of about 1385 lb-mol/hr and the same composition and temperature and pressure after having been cooled in heat exchanger  74 . Again, assuming a recovery of hydrogen of about 83 percent, about 5.02 MMSCFD hydrogen would be produced for hydrogen product stream  90 . Furthermore, in this example it is assumed that all of fuel stream  84  passes through heat exchanger  80  to cool synthesis gas stream  72  to about 100° F. The resultant fuel stream  106  has a temperature of about 322° F., which decreases fuel consumption by about 0.76 percent. 
     EXAMPLE 3  
     This example is similar to that of Example 2, but with synthesis gas stream  72  having a different composition than that previously considered due to additional process heat recovery within water gas shift unit  70 . In this regard, for purposes of this example, synthesis gas stream  72  is assumed to have the following composition: 63.9 mol percent hydrogen, 13.2 mol percent water, 2.8 mol percent carbon monoxide, 14.1 mol percent carbon dioxide, 0.7 mol percent nitrogen and 5.3 mol percent methane. As a result of the additional process heat recovery, synthesis gas stream  72  has a lower stream temperature after heat exchanger  74 , namely 277° F. as opposed to 372° F. in the previous examples and consequently a lower moisture content due to condensation removed in an upstream knock-out drum that as would be known in the art could be associated with water gas shift unit  70 . Further, in this example, synthesis gas stream  72  must only be cooled from about 277° F. to about 110° F. As such, about 2300 lb-mol/hr of synthesis gas stream  72  is cooled against all of the fuel stream  84  to produce 11.12 MMSCFD hydrogen for hydrogen product stream  90 . Under such conditions, fuel stream  106  has a calculated temperature of about 247° F., which decreases fuel consumption by 0.54 percent. 
     EXAMPLE 4  
     While previous examples have all considered a 7FA-based power plant, any power plant based on one or more gas turbines is suitable. For instance, a 6FA-based plant would nominally use 2150 lb-mol/hr of the previously specified natural gas as fuel stream  106 , while a 207FA combined cycle plant would nominally use 9350 lb-mol/hr of natural gas. For such plants, proportionally less or more of the synthesis gas could be cooled. For instance, Example 4 shows that, when all 7FA gas turbine fuel is routed through heat exchanger  20 , 2300 lb-mol/hr of synthesis gas stream  72  could be cooled from about 277° F. to about 110° F. For a 6FA plant, about 1058 lb-mol/hr of synthesis gas stream  72  could be cooled, while for a 207FA plant, about 4600 lb-mol/hr of synthesis gas stream  72  could be cooled. Synthesis gas stream  72  for such purposes is assumed to have the composition set forth in Example 4. This translates to about 5.11 and about 22.24 MMSCFD H 2  production, respectively. For all three foregoing cases, fuel stream  106  emerges preheated to 247° F., which decreases fuel consumption by about 0.5 percent. Obviously, annual fuel savings would be proportionally greater/smaller for larger/smaller gas turbines. 
     Although the present invention has been described in connection with steam methane reforming and catalytic partial oxidation, the present invention could be employed in connection with an autothermal reformer. 
     While the present invention has been described with reference to a preferred embodiment, as will occur to those skilled in the art, numerous changes, additions and omissions can be made without departing from the spirit and the scope of the present invention.