Abstract:
A method and system for generating power in a vaporization of liquid natural gas process, the method comprising pressurizing a working fluid; heating and vaporizing the working fluid; expanding the working fluid in one or more expanders for the generation of power, the working fluid comprises: 2-11 mol % nitrogen, methane, a third component whose boiling point is greater than or equal to that of propane, and a fourth component comprising ethane or ethylene; cooling the working fluid such that the working fluid is at least substantially condensed; and recycling the working fluid, wherein the cooling of the working fluid occurs through indirect heat exchange with a pressurized liquefied natural gas stream in a heat exchanger, and wherein the flow rate of the working fluid at an inlet of the heat exchanger is equal to the flow rate of the working fluid at an outlet of the heat exchanger.

Description:
BACKGROUND 
     Safe and efficient transfer of natural gas (NG) requires that the natural gas be liquefied prior to shipment. Once the liquefied natural gas (LNG) arrives at the target location, the natural gas must be regasified before it can be used as a fuel source. The regasification or vaporization of the liquefied natural gas, which requires input of work or heat, provides an opportunity for secondary power generation that uses the initially cold temperatures of the liquefied natural gas and the work or heat input for vaporization. 
     Previous known processes for generating power in association with vaporization of liquefied natural gas, however, were less than optimal for several reasons. For example, processes where the working fluid was only partially condensed were known to cause complexities, including the need for phase separators, which in turn increased costs and perhaps more importantly, rendered the processes more difficult to control and more sensitive to upsets that might unduly stress heat exchange equipment. Moreover, some processes suffered from thermodynamic inefficiencies due to mixing losses when the streams with different compositions were combined. Finally, the known processes did not disclose use of natural gas as a component of the working fluid. 
     BRIEF SUMMARY 
     Embodiments of the present invention satisfy a need in the art by providing a system and process for generating power in association with a vaporizing of liquefied natural gas process without the historical drawbacks. 
     According to one embodiment, a method is disclosed for generating power in a vaporization of liquid natural gas process, the method comprising the steps of: (a) pressurizing a working fluid; (b) heating and vaporizing the pressurized working fluid; (c) expanding the heated and vaporized working fluid in one or more expanders for the generation of power, the working fluid exiting the one or more expanders comprises: 2-11 mol % nitrogen, methane, a third component whose boiling point is greater than or equal to that of propane, and a fourth component comprising ethane or ethylene; (d) cooling the expanded working fluid such that the cooled working fluid is at least substantially condensed; and (e) recycling the cooled working fluid into step (a), wherein the cooling of the expanded working fluid occurs through indirect heat exchange with a pressurized liquefied natural gas stream in a heat exchanger, and wherein the flow rate of the expanded working fluid at an inlet of the heat exchanger is equal to the flow rate of the expanded working fluid at an outlet of the heat exchanger. 
     According to another embodiment, a method is disclosed for generating power in a vaporization of liquid natural gas process, the method comprising the steps of: (a) pressurizing a working fluid; (b) heating and vaporizing the pressurized working fluid; (c) expanding the heated and vaporized working fluid in one or more expanders for the generation of power, wherein the working fluid comprises: 2-11 mol % nitrogen, natural gas, a third component whose boiling point is greater than or equal to that of propane, and a fourth component comprising ethane or ethylene; (d) cooling the expanded working fluid such that the cooled working fluid is at least partially condensed; and (e) recycling the at least partially condensed working fluid into step (a), wherein the cooling of the expanded working fluid occurs through indirect heat exchange with a pressurized liquefied natural gas stream in a heat exchanger, and wherein the flow rate of the expanded working fluid at an inlet of the heat exchanger is equal to the flow rate of the expanded working fluid at an outlet of the heat exchanger. 
     According to yet another embodiment, a method is disclosed for generating power in a vaporization of liquid natural gas process, the method comprising the steps of pressurizing a working fluid; heating and vaporizing the pressurized working fluid; expanding the heated and vaporized working fluid in one or more expanders for the generation of power; cooling the expanded working fluid; and recycling the cooled working fluid wherein the cooling of the expanded working fluid occurs through indirect heat exchange with a pressurized liquefied natural gas stream in a heat exchanger, where the improvement comprises a working fluid comprising 2-11 mol % nitrogen and wherein the cooled working fluid is at least substantially condensed. 
     According to yet another embodiment, an apparatus is disclosed for power generation for use in a vaporization of liquefied natural gas system, the apparatus comprising: at least one expansion device; at least one heating device; at least one condenser; and a working liquid having multiple components, wherein the working liquid comprises: 2-11 mol % nitrogen, a second component comprising methane or natural gas, a third component whose boiling point is greater than or equal to that of propane, and a fourth component comprising ethane or ethylene 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The foregoing brief summary, as well as the following detailed description of exemplary embodiments, is better understood when read in conjunction with the appended drawings. For the purpose of illustrating embodiments of the invention, there is shown in the drawings exemplary embodiments of the invention; however, the invention is not limited to the specific methods and instrumentalities disclosed. In the drawings: 
         FIG. 1   a  is a flow diagram illustrating an exemplary power generation system in accordance with an embodiment of the present invention; 
         FIG. 1   b  is a flow diagram illustrating an exemplary power generation system in accordance with an embodiment of the present invention; 
         FIG. 2  is a flow diagram illustrating an exemplary use of liquid natural gas as a component of the working fluid in a power generation system in accordance with an embodiment of the present invention; 
         FIG. 3  is a flow diagram illustrating an exemplary power generation system incorporating a split stream in accordance with an embodiment of the present invention; 
         FIG. 4  is graphical illustration comparing the nitrogen content of the working fluid with the net recovered power in accordance with an embodiment of the present invention; 
         FIG. 5  is graphical illustration comparing the nitrogen content of the working fluid with the net recovered power in accordance with an embodiment of the present invention; 
         FIG. 6  is a graphical illustration of an exemplary cooling curve of the main heat exchanger when the nitrogen content of the working fluid was approximately 7.81 mol % in accordance with an embodiment of the present invention; and 
         FIG. 7  is a graphical illustration of an exemplary cooling curve of the main heat exchanger when the nitrogen content of the working fluid was approximately 0.40 mol % in accordance with an embodiment of the present invention. 
     
    
    
     DETAILED DESCRIPTION OF EXEMPLARY EMBODIMENTS 
       FIG. 1   a  is a diagram illustrating an exemplary power generation system including aspects of the present invention. A pressurized liquefied natural gas (LNG) stream may be fed through line  102  through the cold end  104  of the main heat exchanger  106  to generate pressurized natural gas (NG) in line  108  of the liquid natural gas vaporization loop  100 . The delivery pressure of the natural gas may be 76 bar absolute, for example. 
     With respect to the power generation loop  200 , working fluid in line  202  may be pressurized by the pump  204  and the pressurized working fluid in line  206  may then be sent through the cold end  104  of the main heat exchanger  106 . After the pressurized working fluid is heated in the main heat exchanger  106 , the pressurized working fluid in line  208  may be further heated and completely vaporized by a heater  210 . The pressurized working fluid may be completely vaporized working fluid in line  212 . The completely vaporized working fluid in line  212  may then be expanded in the expander  214 . The work generated by expander  214  may be converted into, for example, electrical energy through the use of a generator  216 . The exhaust working fluid from expander  214  in line  218  may be optionally further heated in a reheater  220 . One or more reheaters may be used in between the one or more expanders, for example. The resultant working fluid stream in line  222  may be optionally further expanded in expander  224 . Similar to expander  214 , the work generated from expander  224  may be converted into, for example, electrical energy through the use of a generator  226 . The exhaust working fluid from expander  224  in line  228  may then be fed into the warm end  107  of the main heat exchanger  106  for cooling and condensing of the working fluid. The cooled and condensed working fluid, that is now liquid working fluid, may then be recycled back into line  202  for repressurization. The process of the foregoing description is often referred to as a Rankine cycle. 
     The main heat exchanger  106  may be, for example, one or more physical heat exchangers. The one or more heat exchangers may be of the plate-fin heat exchanger type and measure 1.2 meters×1.3 meters×8 meters, for example. 
     While expander  214  in  FIG. 1  may be interpreted as being a single expander, it should be noted that expander  214  may also be interpreted to represent one or more expanders for expansion, for example. The optional expander  224  may also be one or multiple physical devices. 
     The liquid natural gas flow to heat exchanger  106  may be about 10,068 kmol/hr, for example. In such a scenario, Expander  214  may produce 4000 kW-8000 kW of power, for example. Optional expander  224  may produce 7,000 kW-15,000 kW of power, for example. The typical pressure for the low pressure working fluid in line  202  may be 10 bar to 25 bar, for example. The typical pressure for the high pressure working fluid in line  206  may be 60 bar to 80 bar, for example. The power needed to drive pump  204  may be in the range of 2,000 kW to 4000 kW, for example. Typical temperatures exiting heater  210  and the optional reheater  220  may be in the range of 40° C. to 250° C., for example. 
     The working fluid exiting the one or more expanders of the power generation cycle may include the components of, for example, nitrogen, methane, and a third component whose boiling point is greater than or equal to propane. The third component may be, for example, any normal alkane, their respective isomers, (e.g., propane, isobutane, butane, pentane, isopentane, hexane) or any combination thereof. Moreover, the number of components of the working fluid may include more than three components. For example, a fourth component may be, for example, ethylene, ethane, propylene, or dimethyl ether (DME). 
     The nitrogen content of the working fluid may be greater than 2 mol %. For example, the nitrogen content of the working fluid may be between 2-11 mol %, and more preferably, between 6-10.6 mol %. 
     In another embodiment, the working fluid exiting the expanders of the power generation cycle may include the components of, for example, natural gas, nitrogen, and a third component whose boiling point is greater than or equal to the boiling point of propane. The third component, for example, may be any normal alkane, their respective isomers, (e.g., propane, isobutene, butane, pentane, isopentane, hexane), or any combination thereof. Because the naturally occurring amounts of nitrogen in the natural gas may be low, nitrogen may be added to this mixture of natural gas and the third component. Moreover, the number of components of the working fluid in this embodiment may include more than three components. For example, a fourth component may be, for example, ethylene, ethane, propylene, or dimethyl ether (DME) Liquefied natural gas, which typically already contains methane, ethane, and sometimes nitrogen, may be used as the base for forming the working fluid. For example, adding nitrogen, ethane, and pentane into the liquefied natural gas results in such a mixture. 
     Use of natural gas as a component for the working fluid significantly saves money and resources because the use of natural gas as a component reduces the need to import and/or store at least some of the components already present in natural gas. The natural gas is already present on site for use in the vaporization portion of the process. For example, as illustrated in  FIG. 2 , three small tanks  250 ,  255 , and  260  may be used to store the working fluid components. The liquid natural gas supply  270  is already present at the site for vaporization  280 . The liquid natural gas supply  270  may be used, therefore, not only for vaporization  280 , but also for use as a component of the working fluid in the power generation cycle  290 . 
     The use of the natural gas as the base for forming the working fluid also allows for use of smaller storage tanks for the respective additional components of the working fluid. Moreover, use of the natural gas may eliminate the need to store methane—typically one of the largest components of working fluid. 
     In one embodiment, the exhaust working fluid from the last expander in the power generation cycle may be partially condensed after being cooled in the main heat exchanger  106  (as in  FIG. 1   b , for example). In another embodiment, the exhaust working fluid from the last expander in the power generation cycle may be fully condensed after being cooled in the main heat exchanger  106  (as in  FIG. 1   a , for example). In yet another embodiment, the exhaust working fluid from the last expander in the power generation cycle may be substantially condensed (i.e., condensed such that less than 10% of the working fluid is a vapor) after being cooled in the main heat exchanger  106  (also as in  FIG. 1   b , for example). Fully condensing the exhaust working fluid in heat exchanger  106  may be advantageous because a phase separator is not required when the exhaust working fluid is fully condensed leading to cost savings. Because remixing is not required when the exhaust working fluid is fully condensed, there is less potential for thermodynamic mixing losses. 
     When the working fluid is not completely condensed through cooling in the heat exchanger  106 , a phase separator  203 , as illustrated in  FIG. 1   b , may be used to separate the liquid and vapor from stream  202 . The liquid fraction of the working fluid may be pressurized by the pump  204 , for example. The vapor fraction of the working fluid may be compressed by the compressor  205 , for example. The resultant streams from pump  204  and compressor  205  may then be combined in line  206  to be sent through the cold end  104  of the main heat exchanger  106 . 
     In  FIG. 3 , elements and fluid streams that correspond to elements and fluid streams in the embodiment illustrated in  FIGS. 1   a  and  1   b  have been identified by the same number. Referring to the embodiment illustrated in  FIG. 3 , a split stream  300  may be taken from the exhaust working fluid of each expander, except for the lowest pressure expander. In the exemplary embodiment illustrated in  FIG. 3 , a split stream  300  may be first cooled and condensed by passing the split stream  300  through a section of the main heat exchanger  106 . The cooled and condensed split stream in line  302  may then be pressurized by a pump  304 . The pressurized split stream in line  306  may be reintroduced into the main heat exchanger  106  for heating. The heated split stream may then be reintroduced into the original line  206  for further heating in the main heat exchanger  106 . Use of split streams  300  may allow, for example, for more efficient matching of heat supply and heat demand. 
     As an alternative, split stream  306  may be reheated in heat exchanger  106  separately from stream  206 . In such an event, both warmed streams would be combined at the warm-end of the heat exchanger to form stream  208 . 
     Use of one of the exemplary embodiments, where the working fluid is heated to a temperature of 110° C. prior to expansion, may reach a thermal efficiency close to 29%, for example. The thermal efficiency is calculated by subtracting the work required for operation of the pump from the work produced by the expander(s) and dividing the resultant net work by the heat supplied to the process in heaters  210  and  220 , for example. 
     EXAMPLES 
     A comparison was performed between a Nitrogen Brayton cycle and an exemplary power generation system of the present invention. A Nitrogen Brayton cycle, as used here, operates as follows. Cold nitrogen gas is compressed from a low pressure to a high pressure (in a cold compressor and at a temperature near that of the incoming liquid natural gas) then warmed in a heat exchanger (or exchangers), then expanded from a high pressure to low pressure, then returned and cooled back to the initial state. The cold from the liquid natural gas is used to provide a fraction of the cooling of the low pressure nitrogen. The net work produced is the work output of the warm or hot expander less the work input of the cold compressor 
     For this example, a liquid natural gas having a composition of 0.4 mol % nitrogen, 96.3 mol % methane, and 3.3 mol % ethane was introduced at pressure of 76 bar absolute. As illustrated in Table 1 below, the power generated by the exemplary system of the present invention was greater than that of the Nitrogen Brayton cycle, even though the temperature level into the expander was hotter for the Nitrogen Brayton cycle. 
     The process of the exemplary system used a pump that consumes less power than the cold compressor used by the Nitrogen Brayton cycle. The exemplary system also used two expanders while the Nitrogen Brayton cycle used only a single expander. The expander of the Nitrogen Brayton cycle, however, had a much higher power rating (larger size). The results of comparison are as follows: 
                         TABLE I               Nitrogen (N 2 ) Brayton           System   Exemplary System of the Present Invention                   Capacity: 3800 metric   Capacity: 4000 metric tons per day       tons per day (mTPD)   (mTPD)       Nitrogen Heated To:   Working Fluid Heated To: 110° C.       260° C.       Expander Capacity:   Expander Capacity: 11,235 kW and 6,641 kW       20,000 W       Cold Compressor   Pump Capacity: 3,375 kW       Capacity: 12,300 kW       Net Power Produced:   Net Power Produced: 14,501 kW       7,700 kW                    
The composition of the working fluid for the exemplary system was as follows:
 
     
       
         
               
               
               
             
           
               
                   
                 TABLE II 
               
               
                   
                   
               
               
                   
                 Composition 
                 Mole Fraction 
               
               
                   
                   
               
             
             
               
                   
                 Nitrogen 
                 0.0781 
               
               
                   
                 Methane 
                 0.3409 
               
               
                   
                 Ethane 
                 0.4137 
               
               
                   
                 Pentane 
                 0.1673 
               
               
                   
                   
               
             
          
         
       
     
     Table III illustrates how varying the nitrogen content of the working fluid affects the performance of the energy recovery process when the working fluid consists of nitrogen, methane, ethane, and pentane. 
     Table IV illustrates the similar effects of nitrogen when the working fluid consists of nitrogen, methane, ethylene, and n-butane. The results in Tables III and IV were obtained by varying the nitrogen flow rate in the working fluid and then optimizing the flow rates of the other components (i.e., the methane, ethane, and pentane from Table III and the methane, ethylene, and n-butane in Table IV). That is to say, for a given level of nitrogen, the composition of the other components was adjusted to achieve the highest net power output. The liquid natural gas flow rate was 4000 mTPD. Also, the UA of the main heat exchanger (the product of the heat transfer coefficient of the heat exchanger (U) and the heat exchanger area (A)) and the efficiencies of the expanders and pump were fixed. 
     
       
         
               
             
               
               
               
               
               
               
               
               
               
               
               
               
             
           
               
                 TABLE III 
               
               
                   
               
               
                 Component 
               
               
                   
               
             
             
               
                   
               
             
          
           
               
                 Nitrogen 
                 0 
                 0.40 
                 0.87 
                 2.15 
                 3.01 
                 4.26 
                 6.35 
                 7.81 
                 8.53 
                 9.83 
                 10.66 
               
               
                 (mol %) 
               
               
                 Methane (mol %) 
                 45.8 
                 43.6 
                 43.5 
                 42.2 
                 41.1 
                 39.2 
                 36.3 
                 34.1 
                 33.1 
                 32.6 
                 33.5 
               
               
                 Ethane (mol %) 
                 33.6 
                 36.0 
                 35.8 
                 35.9 
                 36.8 
                 37.8 
                 39.8 
                 41.4 
                 42.3 
                 44.3 
                 44.7 
               
               
                 Pentane (mol %) 
                 20.7 
                 20.0 
                 19.9 
                 19.7 
                 19.1 
                 18.8 
                 17.5 
                 16.7 
                 16.1 
                 13.3 
                 11.1 
               
               
                 Net 
                 12,710 
                 13,315 
                 13,421 
                 13,761 
                 13,915 
                 14,118 
                 14,400 
                 14,501 
                 14,481 
                 14,203 
                 13,477 
               
               
                 Recovered 
               
               
                 Power (kW) 
               
               
                   
               
             
          
         
       
     
       FIG. 4  is a graphical illustration  400  comparing the nitrogen content of the working fluid with the net recovered power (kW) in Table III. 
     
       
         
               
             
               
               
               
               
               
               
               
               
               
               
               
               
             
           
               
                 TABLE IV 
               
               
                   
               
               
                 Component 
               
               
                   
               
             
             
               
                   
               
             
          
           
               
                 Nitrogen 
                 0.37 
                 2.3 
                 4.35 
                 5.75 
                 6.17 
                 7.88 
                 9.2 
                 9.8 
                 10.6 
                 11.2 
                 12.2 
               
               
                 (mol %) 
               
               
                 Methane (mol %) 
                 42.4 
                 41.6 
                 42.2 
                 36.6 
                 36.2 
                 32.2 
                 31.0 
                 29.0 
                 28.1 
                 29.1 
                 30.3 
               
               
                 Ethylene (mol %) 
                 34.8 
                 34.2 
                 35.9 
                 36.0 
                 35.9 
                 39.5 
                 39.5 
                 41.7 
                 41.9 
                 41.9 
                 43.7 
               
               
                 n-butane (mol %) 
                 22.0 
                 22.0 
                 22.7 
                 21.7 
                 21.7 
                 20.4 
                 20.3 
                 19.6 
                 19.4 
                 17.8 
                 13.8 
               
               
                 Net 
                 13,571 
                 13,858 
                 14,117 
                 14,373 
                 14,430 
                 14,640 
                 14,786 
                 14,788 
                 14,636 
                 14,330 
                 13,667 
               
               
                 Recovered 
               
               
                 Power (kW) 
               
               
                   
               
             
          
         
       
     
       FIG. 5  is a graphical illustration  500  comparing the nitrogen content of the working fluid with the net recovered power (kW) in Table IV. 
     Table V illustrates how removal of the nitrogen content of the working fluid in an exemplary case while keeping the other three components in the same relative ratios affects the performance of the energy recovery process when the working fluid consists of nitrogen, methane, ethane, and pentane. 
     
       
         
               
               
             
               
               
               
               
             
           
               
                   
                 TABLE V 
               
               
                   
                   
               
               
                   
                 Component 
               
               
                   
                   
               
             
             
               
                   
               
             
          
           
               
                   
                 Nitrogen (mol %) 
                 7.81 
                 0 
               
               
                   
                 Methane (mol %) 
                 34.1 
                 37.0 
               
               
                   
                 Ethane (mol %) 
                 41.4 
                 44.9 
               
               
                   
                 Pentane (mol %) 
                 16.7 
                 18.1 
               
               
                   
                 Net Recovered Power 
                 14,501 
                 12,351 
               
               
                   
                 (kW) 
               
               
                   
                   
               
             
          
         
       
     
     The examples above indicate an optimal content of the nitrogen in the working fluid may be, for example, greater than 2 mol %, and may preferably be greater than 6 mol %, even when the working fluid is fully condensed in the power generation process cycle. 
     Because nitrogen gas has a very low boiling point of approximately −195.8° C., which is far below the temperature range of liquid natural gas vaporization, working fluids that contained significant amounts of nitrogen were traditionally not used in a vaporizing of liquid natural gas process in conjunction with a Rankine cycle for power generation. Furthermore, and traditionally, when nitrogen was used as a component of the working fluid, the working fluid was first partially condensed, removed from the exchanger, sent to a vapor-liquid separator, and the resultant vapor returned to the exchanger and totally condensed—the use of the phase separator, in effect, creates several working fluids of different composition in the same process. The aversion to the use of nitrogen in the working fluid was most likely driven by the presumption that it would be difficult (or inefficient) to condense a component that was more volatile than methane (the major component of liquid natural gas). 
     In fact, we have found that: 1) the incorporation of significant levels nitrogen into the working fluid can be accomplished when the fluid is totally condensed, and 2) it is beneficial to do so. The explanation for why this is follows. 
       FIG. 6  is a graphical illustration  600  of the cooling curve of the main heat exchanger when the nitrogen content of the working fluid was approximately 7.81 mol %.  FIG. 7  is a graphical illustration  700  of the cooling curve of the main heat exchanger when the nitrogen content of the working fluid was approximately 0.40 mol %. The working fluid in the study for obtaining  FIGS. 6-7  comprised nitrogen, methane, ethane, and pentane in accordance with the examples shown in Table III (and  FIG. 4 ).  FIGS. 6-7  can be studied to understand the beneficial result of adding a judicious amount of nitrogen. Essentially, the addition of nitrogen results in a more uniform heat transfer temperature difference between the cooling stream and warming stream—particularly at the cold-end. The tightening of the temperature difference between streams in  FIG. 6  (a smaller average temperature difference between the heat exchanging streams) is indicative of a more efficient process. Furthermore, thermodynamic fundamentals teach that the temperature difference between streams should be minimized at the colder temperatures (the lost work is proportional to 1/T, where T is absolute temperature). 
     As illustrated in  FIG. 6 , when the nitrogen content in the working fluid was 7.81 mol %, the largest temperature difference between the cooling stream (indicated by T-Hot) and the warming stream (indicated by T-Cold) in the main heat exchanger was no greater than 15° C. In contrast, and as illustrated in  FIG. 7 , the largest temperature difference between the cooling stream and the warming stream in the main heat exchanger was more than 50° C. near the cold end of the main heat exchanger when the nitrogen content in the working fluid was reduced to 0.40 mol %. Thus, in this range, as the nitrogen content of the working fluid was decreased, the temperature difference between the T-Hot curve and the T-Cold curve increased, and more available work was lost in the heat transfer process leading to less efficient power generation. 
     As illustrated in  FIG. 1   b , one embodiment of the present invention anticipates that the working fluid need not be totally condensed to utilize the beneficial effect of adding nitrogen to the mix. However, total condensation has additional benefits. For example, in  FIG. 1   b , cold compressor  205  operates by introducing work at the coldest temperature. Cold pump  204  also introduces work, but that work, on a per mole basis, is significantly less that of the cold compressor. Work at the cold-end robs refrigeration from the LNG, thus reducing the power production. So, one can see that pumping a liquid is desirable to compressing a vapor. Additionally, it is understood that the cost of a pump is considerably less than the cost of a compressor. 
     With respect to the traditional processes, where the working fluid was partially condensed, phase separated, then fully condensed, the present invention has been simplified. Systems with multiple phase separation stages are clearly more complex due to additional equipment pieces such as phase separators, pumps, and pipelines, as well as penetrations in heat exchanger(s). Additionally, when these separated streams recombine, there are thermodynamic mixing losses that result from mixing streams of different composition—these mixing losses manifest themselves as reduce power recovery. Our results show, in contrast to the common belief that any significant amount of nitrogen in the working fluid would warrant the use of a phase separator, a judicious amount of nitrogen in the working fluid can be completely condensed and still provide a very desirable performance benefit. This allows us to greatly simplify the process, thereby reducing the cost of the system. 
     While aspects of the present invention has been described in connection with the preferred embodiments of the various figures, it is to be understood that other similar embodiments may be used or modifications and additions may be made to the described embodiment for performing the same function of the present invention without deviating therefrom. The claimed invention, therefore, should not be limited to any single embodiment, but rather should be construed in breadth and scope in accordance with the appended claims.