Patent Publication Number: US-10767859-B2

Title: Wellhead gas heater

Description:
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
     Not applicable. 
     REFERENCE TO A MICROFICHE APPENDIX 
     Not applicable. 
     BACKGROUND 
     Traditional frac heaters are generally equipped with propane or diesel fired heater units. These propane or diesel fired heater units are designed to operate at well sites and heat water and/or other chemicals used for hydrocarbon production and/or well completion processes (i.e. fracking). Because large volumes of water are typically needed during fracking, large amounts of propane or diesel fuel are also needed to heat such large amounts of water. However, the cost of propane has increased exponentially in recent years, thereby escalating the associated production and/or well completion expenses. Typically, gas produced from the wellhead (referred to as “wellhead gas” or “dirty gas”), can experience rapid pressure fluctuations and is often contaminated with other chemicals. Due to the fluctuation of the wellhead gas pressure and contamination levels of the wellhead gas, previous attempts to use the wellhead gas to heat the water and/or other chemicals required for production and/or well completion processes have failed. Thus, wellhead gas is generally considered a byproduct and is burned off and/or flared in many instances. 
     SUMMARY 
     In some embodiments of the disclosure, a wellhead gas burner is disclosed as comprising a supply line configured to couple to a wellhead gas source and configured to flow wellhead gas at a first velocity, an expansion chamber in fluid communication with the supply line and configured to flow wellhead gas at a second velocity that is less than the first velocity, a fuel rail in fluid communication with the expansion chamber, and at least one fuel rail finger in fluid communication to the fuel rail, wherein the at least one fuel rail finger comprises a plurality of combustion chambers, and wherein each combustion chamber comprises a combustion tube holder that at least partially envelopes a combustion tube. 
     In other embodiments of the disclosure, a wellhead gas burner is disclosed as comprising a supply line configured to couple to a wellhead gas source and configured to flow wellhead gas at a first pressure, an expansion chamber in fluid communication with the supply line and configured to flow wellhead gas at a second pressure that is less than the first pressure, a first fuel rail in fluid communication with the expansion chamber, and at least one fuel rail finger connected in fluid communication to the first fuel rail, wherein the at least one fuel rail finger comprises a plurality of combustion chambers, wherein each combustion chamber comprises a combustion tube holder that at least partially envelopes a combustion tube, and wherein the plurality of fuel rail fingers are configured to integrate with a traditional gas burner. 
     In yet other embodiments of the disclosure, a method of burning wellhead gas is disclosed as comprising: producing wellhead gas from a wellhead; expanding the wellhead gas; distributing the expanded wellhead gas; combusting the distributed wellhead gas; heating a wellbore treatment fluid with heat produced by the combustion of the distributed wellhead gas; and treating a wellbore with the heated wellbore treatment fluid. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a more complete understanding of the present disclosure and the advantages thereof, reference is now made to the following brief description, taken in connection with the accompanying drawings and detailed description. 
         FIG. 1  is a schematic of a wellhead gas superheater system according to an embodiment of the disclosure, 
         FIG. 2  is a schematic of a wellhead gas burner according to an embodiment of the disclosure, 
         FIG. 3  is a detailed cutaway view of a combustion chamber mounted to a fuel rail finger of the wellhead gas burner of  FIG. 2  according to an embodiment of the disclosure, 
         FIG. 4  is a schematic of a wellhead gas burner according to another embodiment of the disclosure, 
         FIG. 5  is a detailed cutaway view of a combustion chamber mounted to a fuel rail finger of the wellhead gas burner of  FIG. 4  according to an embodiment of the disclosure, 
         FIG. 6  is a flowchart of a method of burning wellhead gas according to an embodiment of the disclosure, 
         FIG. 7  is a schematic of a superheater truck according to an embodiment of the disclosure, 
         FIG. 8  is a schematic of the burner box of the superheater truck of  FIG. 7  according to an embodiment of the disclosure, 
         FIG. 9  is a schematic of a portion of the vent of the superheater truck of  FIG. 7  according to an embodiment of the disclosure, 
         FIG. 10  is a schematic of a superheater truck according to another embodiment of the disclosure, 
         FIG. 11  is a schematic of a superheater truck according to another alternative embodiment of the disclosure, and 
         FIG. 12  is a flowchart of a method of operating a superheater truck according to an embodiment of the disclosure. 
     
    
    
     DETAILED DESCRIPTION 
     It should be understood at the outset that although an illustrative implementation of one or more embodiments are provided below, the disclosed systems and/or methods may be implemented using any number of techniques, whether currently known or in existence. The disclosure should in no way be limited to the illustrative implementations, drawings, and techniques illustrated below, including the exemplary designs and implementations illustrated and described herein, but may be modified within the scope of the appended claims along with their full scope of equivalents. 
     Referring now to  FIG. 1 , a schematic of a wellhead gas superheater system  100  is shown according to an embodiment of the disclosure. The wellhead gas superheater system  100  may generally be configured to receive unrefined or refined wellhead gas produced from the wellhead  102  and burn the wellhead gas to heat water and/or other chemicals used for hydrocarbon production drilling, and/or well completion processes (i.e. fracking). Wellhead gas may be defined as any gas produced from a wellhead that has not been refined, processed, and/or chemically altered in any manner. Wellhead gas therefore is substantially the same as the natural gas when it is in the subterranean formation (e.g. mostly methane with some heavier hydrocarbons). In some instances, the wellhead gas may also comprise the same temperature and/or pressure as the gas when it is located in the subterranean formation. As wellhead gas is produced from the wellhead  102 , a first flow line  104  is configured to receive the wellhead gas from the wellhead  102 . The first flow line  104  may generally comprise any suitable pipeline, tubing, and/or other hollow vessel suitable for carrying, receiving, and/or transporting wellhead gas. The first flow line  104  is configured to carry the wellhead gas to a separator  106 . 
     The separator  106  may generally comprise any device configured to receive wellhead gas and separate the gas to be used by the wellhead gas superheater system  100  from the produced oil and/or any other liquids produced from the wellhead  102 . More specifically, the separator  106  may be configured to remove hydrocarbons and/or any other particulates in order to regulate, maximize, and/or provide a consistent British Thermal Unit (BTU) level in the wellhead gas to be used in the wellhead gas superheater system  100 . A sufficient BTU level may generally comprise at least about 250 BTU per cubic foot, at least about 500 BTU per cubic foot, at least about 1000 BTU per cubic foot, at least about 2500 BTU per cubic foot, or at least about 3500 BTU per cubic foot. In some embodiments, the separator may comprise a HIPOWER Unprocessed Gas Conditioning System Model FCS-25, FCS-50, FCS-100, FCS-250, or FCS-500, manufactured by Himoinsa Power Systems, Inc or any other equivalent treator or separator from any other manufacturer. In some embodiments, the separator  106  may comprise a sales line  108 . The sales line  108  may be used to collect natural gas liquids, heavy oils, and/or other byproducts from the separator  106  that are not commercially valuable and/or utilized within the wellhead gas superheater system  100 . From the separator  106 , the wellhead gas is passed through a second flow line  110  to the superheater truck  112 . Similar to the first flow line  104 , the second flow line  110  may also comprise any suitable pipeline, tubing, and/or other hollow vessel suitable for carrying, receiving, and/or transporting wellhead gas. It will be appreciated that the first flow line  104  and the second flow line  110  comprise a diameter of at least about 1.5″ (38.1 mm). However, in some embodiments, the first flow line  104  and the second flow line  110  may comprise a diameter of at least about 2.0″ (51 mm), and/or at least about 2.5″ (63.5 mm). In alternative embodiments, the first flow line  104  and/or the second flow line  110  may comprise a diameter of at least about 0.5″ (12.7 mm) up to about 24″ (609.6 mm). 
     The superheater truck  112  may generally comprise at least one supply line union  114  that is configured to connect and/or couple to the second flow line  110  for receiving and/or importing the wellhead gas into the superheater truck  112 . In some embodiments, however, the superheater truck  112  may comprise a plurality of supply line unions  114  and be configured to receive wellhead gas from a plurality of wellheads  102 . From the supply line union  114 , the wellhead gas may be carried by a supply line (not pictured, but discussed in greater detail later) and delivered to a wellhead gas burner  116 . The wellhead gas burner  116  is generally configured to burn the wellhead gas produced from the wellhead  102 . By burning the wellhead gas in the wellhead gas burner  116 , heat produced from the combustion of the wellhead gas may be used to heat the water and/or other chemicals used in hydrocarbon production and/or well completion processes, including, but not limited to, fracking. The superheater truck  112  may also comprise a storage tank  120 . In some embodiments, the wellhead gas burner  116  may also comprise a heat exchanger that improves heat transfer between the water and/or other chemicals and the wellhead gas burner  116  and/or a traditional gas burner  118 . The traditional gas burner  118  may be configured to burn propane and/or diesel fuel to heat the water and/or other chemicals used for the aforementioned production and/or well completion processes. In some embodiments, and as will be discussed in greater detail herein, the traditional gas burner  118  may be used in conjunction with the wellhead gas burner  116 , to supplement the wellhead gas burner  116 , and/or in place of the wellhead gas burner  116 . It will be appreciated that the wellhead gas burner  116  and the traditional gas burner  118  may be referred to as a dual fuel burner and/or a duel fuel frac heater. 
     In some embodiments, the wellhead gas superheater system  100  may not comprise a separator  106 . In such embodiments, the first flow line  104  may be configured to carry the wellhead gas directly from the wellhead  102  to the supply line union  114  of the superheater truck  112 . Further, while the wellhead gas burner  116  and the traditional gas burner  118  are shown mounted to and/or carried by the superheater truck  112 , in some embodiments, the wellhead gas burner  116  and/or the traditional gas burner  118  may alternatively be a standalone burner unit and/or mounted on a skid or trailer. Additionally, it will be appreciated that in some embodiments a plurality of wellhead gas superheater systems  100  may be configured to receive wellhead gas produced from the wellhead  102  and burn the wellhead gas to heat water and/or other chemicals used for hydrocarbon production and/or well completion processes. 
     Referring now to  FIG. 2 , a schematic of a wellhead gas burner  200  is shown according to an embodiment of the disclosure. Wellhead gas burner  200  may generally be substantially similar to the wellhead gas burner  116  in  FIG. 1  and be capable of being used in the superheater truck  112  of the wellhead gas superheater system  100  of  FIG. 1 . Wellhead gas burner  200  generally comprises a supply line union  202 , a plurality of valves  206 ,  218 , a pressure regulator  210 , a plurality of supply line sections  204 ,  208 ,  216  configured to carry wellhead gas through the wellhead gas burner  200 , an expansion chamber  212 , a fuel rail  220 , a plurality of fuel rail fingers  222  that extend from the fuel rail  220 , and a plurality of combustion chambers  224  attached to each fuel rail finger  222 . 
     The supply line union  202  may generally be substantially similar to supply line union  114  in  FIG. 1  and be configured to connect and/or couple a first supply line section  204  to a fluid flow line, such as the first flow line  104  and/or the second flow line  110  of  FIG. 1 . In some embodiments, the supply line union  202  may comprise a 2.0″ (51 mm) hammer union, while the first supply line section  204  comprises a 2.0″ (51 mm) diameter pipe. In alternative embodiments, the supply line union  202  and/or the first supply line section  204  may comprise a diameter of at least about 0.5″ (12.7 mm) up to about 24″ (609.6 mm). The wellhead gas burner  200  may also comprise a first valve  206  connected and/or coupled to the first supply line section  204  at an end opposite from the supply line union  202 . The first valve  206  may be configured as a globe valve, a gate valve, a ball valve, and/or any other suitable shutoff valve that may substantially restrict and/or prevent fluid flow through the first valve  206  and/or the wellhead gas burner  200 . In some embodiments, the first valve  206  may comprise a 2.0″ (51 mm) valve. In alternative embodiments, the first valve  206  may comprise a diameter of at least about 0.5″ (12.7 mm) up to about 24″ (609.6 mm). The first valve  206  may generally be located between the first supply line section  204  and a second supply line section  208 . Similar to the first supply line section  204 , the second supply line section  208  may also comprise a 2.0″ (51 mm) diameter pipe. Alternatively, in other embodiments, the second supply line section  208  may comprise a diameter of at least about 0.5″ (12.7 mm) up to about 24″ (609.6 mm). 
     The wellhead gas burner  200  may also comprise a pressure regulator  210 . The pressure regulator  210  may be connected and/or coupled to the second supply line section  208  at an end opposite from the first valve  206 . The pressure regulator  210  may generally be configured to regulate the pressure of the wellhead gas flowing through the wellhead gas burner  200 . In some embodiments, the pressure regulator  210  may comprise a 0.374″ (9.5 mm) orifice that substantially regulates the pressure of the wellhead gas flowing through the wellhead gas burner  200 . The pressure regulator  210  may generally be connected to and/or coupled to the expansion chamber  212 . In some embodiments, however, the wellhead gas burner  200  may not comprise a pressure regulator  210 . 
     Because wellhead gas produced from a wellhead, such as the wellhead  102  in  FIG. 1 , can experience large pressure fluctuations, the expansion chamber  212  may generally be configured to accommodate, regulate, and/or control such pressure fluctuations in the wellhead gas. In some embodiments, the expansion chamber may accommodate wellhead gas pressures from about 5 pounds per square inch (psi) to about 15,000 psi. The expansion chamber  212  may also be configured to provide a sufficient volume for storing wellhead gas so that the flow of wellhead gas to the combustion chambers  224  remains uninterrupted. The expansion chamber  212  may also be configured to provide sufficient internal volume to allow for the wellhead gas to expand within the expansion chamber  212 . Further, by configuring the expansion chamber  212  with a sufficient volume, the wellhead gas burner  200  may accommodate the pressure fluctuations from the wellhead and/or provide a smoother, more consistent flow of wellhead gas to components disposed downstream of the expansion chamber  212  despite the wellhead gas pressure and/or fluctuations from the wellhead. In some embodiments, the expansion chamber  212  may comprise a 2.0″ (51 mm) diameter pipe and comprise a length of at least about 10 feet (3.048 meters). In embodiments where the expansion chamber comprises the 2.0″ (51 mm) diameter pipe, the wellhead gas burner  200  may accommodate at least about one-hundred sixty combustion chambers  224  and a wellhead gas flow rate of at least about 35,000 cubic feet of gas per hour. In other embodiments, the expansion chamber  212  may comprise a 3.0″ (76.2 mm) diameter pipe and comprise a length of at least about 10 feet (3.048 meters). In embodiments where the expansion chamber comprises the 3.0″ (76.2 mm) diameter pipe, the wellhead gas burner  200  may accommodate at least about three-hundred combustion chambers  224  and a wellhead gas flow rate of at least about 90,000 cubic feet of gas per hour. In alternative embodiments, the expansion chamber  212  may comprise a diameter of at least about 0.5″ (12.7 mm) up to about 24″ (609.6 mm). 
     The wellhead gas burner  200  may also comprise a second valve  218 . The second valve  218  may be substantially similar to the first valve  206  and be configured as a globe valve, a gate valve, a ball valve, and/or any other suitable shutoff valve that may substantially restrict and/or prevent fluid flow through the second valve  218  and/or the wellhead gas burner  200 . In some embodiments, the second valve  218  may comprise a 2.0″ (51 mm) valve. In alternative embodiments, the second valve  218  may comprise a diameter of at least about 0.5″ (12.7 mm) up to about 24″ (609.6 mm). The second valve may generally be connected to and/or coupled to the expansion chamber  212 . However, in some embodiments, the second valve  218  may be connected and/or coupled to the expansion chamber  212  through a fitting  214  and a third supply line section  216 . Similar to the first supply line section  204  and the second supply line section  208 , the third supply line section  216  may also comprise a 2.0″ (51 mm) diameter pipe. In alternative embodiments, the third supply line section  216  may comprise a diameter of at least about 0.5″ (12.7 mm) up to about 24″ (609.6 mm). 
     It will be appreciated that while a plurality of supply line sections  204 ,  208 ,  216  and only one fitting  214  are disclosed, in some embodiments the wellhead gas burner  200  may comprise a fewer or a greater number of supply line sections  204 ,  208 ,  216  and/or fittings  214  to accommodate a fewer or greater number of components and/or to route the supply line through a superheater truck, such as superheater truck  112  in  FIG. 1 . Further, it will be appreciated that the valves  206 ,  218  are included in the wellhead gas burner  200  for safety. Accordingly, in some embodiments, the wellhead gas burner  200  may only comprise one valve  206 ,  218 . However, in other embodiments, the wellhead gas burner  200  may comprise more than two valves  206 ,  218 . As one exemplary embodiment, in embodiments where the wellhead gas burner  200  comprises only valve  218 , the supply line union  202  may be connected and/or coupled to the pressure regulator  210  via either the first supply line section  204  or the second supply line section  208 . Still in some embodiments, it will be appreciated that no expansion chamber  212  may be used, and the pressure regulator  210  may be directly coupled in fluid communication with a third supply line  216  and/or the fuel rail  220 . It will further be appreciated that the components configured to carry and/or transport the wellhead gas to the wellhead gas burner  200  may comprise substantially similar sizes that may comprise a diameter range from at least about 0.5″ (12.7 mm) up to about 24″ (609.6 mm). 
     The wellhead gas burner  200  also comprises a fuel rail  220 . The fuel rail  220  may generally be connected to and/or coupled to the second valve  218 . In some embodiments, the fuel rail  220  may comprise at least about 1.5″ schedule  40  pipe. However, in some embodiments, the fuel rail  220  may comprise at least about 2.0″ schedule  40  pipe and/or at least about 2.5″ schedule  40  pipe. In yet other embodiments, the fuel rail  220  may comprise at least about 1.5″ schedule  80  pipe, at least about 2.0″ schedule  80  pipe, and/or at least about 2.5″ schedule  80  pipe for high pressure wellhead gas burner  200  applications. In alternative embodiments, the fuel rail  220  may comprise a diameter of at least about 0.5″ (12.7 mm) up to about 24″ (609.6 mm). 
     The fuel rail  220  generally comprises a plurality of fuel rail fingers  222  mounted, secured, welded, and/or otherwise attached to the fuel rail  220 . In some embodiments, the fuel rail  220  may comprise at least about eight fuel rail fingers  222 . However, in other embodiments, the fuel rail  220  may comprise any number of fuel rail fingers  222  depending on the configuration of the wellhead gas burner  200 . The fuel rail fingers  222  may also be in fluid communication with the fuel rail  220  and be configured to receive wellhead gas from the fuel rail  220 . In some embodiments, the fuel rail fingers  222  may comprise at least about 1.0″ schedule  40  pipe. However, in some embodiments, the fuel rail fingers  222  may comprise at least about 1.25″ schedule  40  pipe and/or at least about 1.5″ schedule  40  pipe. In yet other embodiments, the fuel rail fingers  222  may comprise at least about 1.0″ schedule  80  pipe, at least about 1.25″ schedule  80  pipe, and/or at least about 1.5″ schedule  80  pipe for high pressure wellhead gas burner  200  applications. Alternatively, the fuel rail fingers  222  may comprise a diameter of at least about 0.5″ (12.7 mm) up to about 24″ (609.6 mm). 
     Each fuel rail finger  222  generally comprises a plurality of combustion chambers  224  mounted, secured, welded, and/or attached to each of the fuel rail fingers  222 . Each of the plurality of combustion chambers  224  comprises a combustion tube holder  226 , a combustion tube  228 , and a combustion nozzle  230 . The combustion chambers  224  may generally be configured to allow wellhead gas to exit the fuel rail fingers  222  and combust within the combustion chamber  224 . It will be appreciated that in some embodiments, each fuel rail finger  222  comprises as many combustion chambers  224  as possible according to the length of the fuel rail fingers  222 . Accordingly, in some embodiments, the combustion chambers  224  may be spaced at least about 3.5″ (89 mm) apart as measured from the center of one combustion chamber  224  to the most adjacently located combustion chamber  224  and along the length of one of the fuel rail fingers  222 . However, in other embodiments, the combustion chambers  224  may be spaced at any distance as measured from center to center along the length of the fuel rail finger  222  to accommodate the largest number of combustion chambers  224  on each fuel rail finger  222  based on the largest overall outer diameter of the combustion chambers  224  and/or the outer diameter of the combustion tube holder  226 . Although not shown, the wellhead gas burner  200  may also comprise one or more igniters that facilitate ignition of the combustion process in the combustion chambers  224 . 
     Referring now to  FIG. 3 , a detailed cutaway view of a combustion chamber  224  mounted to a fuel rail finger  222  of the wellhead gas burner  200  of  FIG. 2  is shown according to an embodiment of the disclosure. As stated, each combustion chamber  224  comprises a combustion tube holder  226 , a combustion tube  228 , and a combustion nozzle  230 . Each combustion tube holder  226  may generally be configured to accommodate and/or receive a combustion tube  228  within the inner diameter of the combustion tube holder  226  such that the combustion tube holder  226  partially, substantially, or completely envelopes the combustion tube  228 . Accordingly, the inner diameter of each of the combustion tube holders  226  may be smaller than the outer diameter of the combustion tube  228 . In some embodiments, the combustion tube holders  226  may comprise at least about 2.0″ schedule  40  pipe, while the combustion tubes  228  comprise about 1.5″ schedule  40  pipe. However, in some embodiments, the combustion tube holders  226  may comprise at least about 2.5″ schedule  40  pipe and/or at least about 3.0″ schedule  40  pipe, while the combustion tubes  228  comprise about 2.0″ schedule  40  pipe and/or 2.5″ schedule  40  pipe, respectively. In yet other embodiments, the combustion tube holders  226  may comprise at least about 2.0″ schedule  80  pipe, at least about 2.5″ schedule  80  pipe, and/or at least about 3.0″ schedule  80  pipe, while the combustion tubes  228  comprise 1.5″ schedule  80  pipe, 2.0″ schedule  80  pipe, and/or 2.5″ schedule  80  pipe, respectively, for high pressure wellhead gas burner  200  applications. 
     Each combustion chamber  224  may be configured such that the combustion tube  228  may be longer than the combustion tube holder  226 . The combustion tube holder  226  and the combustion tube  228  may generally be aligned on the end that substantially abuts the fuel rail finger  222 . Accordingly, in some embodiments, the combustion tube holder  226  may comprise a length of at least about 2.0″ (51 mm), while the combustion tube  228  may comprise a length of at least about 5.0″ (127 mm). However, in other embodiments, the combustion tube holder  226  may comprise a length of at least about 2.0″ (51 mm), while the combustion tube  228  comprises any length that is greater than the length of the combustion tube holder  226  and/or that is configured to provide the most efficient wellhead gas combustion for the wellhead gas burner  200 . 
     The combustion nozzles  230  each generally comprise a threaded bung  232 , a threaded nozzle  234 , and an orifice  236  and are located substantially in the center of each associated combustion chamber  224 . The threaded bung  232  may generally be welded to the fuel rail finger  222  and disposed over an opening and/or hole in the fuel rail finger  222 . The threaded bung  232  comprises a threaded opening  238  that comprises threads that are complementary to threads on the outer surface of the threaded nozzle  234 . The threaded nozzle  234  may be inserted into the complementary threaded opening  238  of the threaded bung  232  by rotatably inserting the threaded nozzle  234  into the threaded opening  238  of the threaded bung  232 . The threaded nozzle  234  comprises an orifice  236  that extends through the threaded nozzle  234  substantially along the length of the threaded nozzle  234 . The orifice  236  may generally be configured to control the amount of the wellhead gas, the pressure of the wellhead gas, and/or the flow rate of the wellhead gas entering the combustion chamber  224 . In some embodiments, the orifice  236  may comprise at least about a #40 orifice (0.098″, 2.49 mm). However, in other embodiments, the orifice  236  may comprise at least about a #30 orifice and/or at least about a #50 orifice. It will be appreciated that the orifice size may be larger than that of a traditional gas burner, such as traditional gas burner  118  in  FIG. 1 , which may produce a hotter flame as compared to such traditional gas burners. The orifice  236  may generally remain in fluid communication with the threaded bung  232  and/or the hole and/or opening in the fuel rail finger  222  to allow wellhead gas that flows through the fuel rail finger  222  to escape the fuel rail finger  222  through a fluid path that extends through the orifice  236  of the threaded nozzle  234  and into an internal cavity  240  of the combustion chamber  224  that is defined by the inner volume of the combustion tube  228 . It is within the internal cavity  240  of the combustion chamber  224  that combustion of the wellhead gas occurs. Alternatively, as opposed to the threaded bung  232  and the threaded nozzle  234 , each combustion nozzle  230  may comprise an orifice  236  that comprises a hole drilled in the fuel rail finger  222 . In such embodiments, the orifices  236  may comprise at least about a #30 orifice up to about a #50 orifice. 
     Referring now to both  FIGS. 2 and 3 , in operation, the wellhead gas burner  200  may receive unrefined wellhead gas from a wellhead, such as wellhead  102  in  FIG. 1 , to heat water and/or other chemicals used for hydrocarbon production and/or well completion processes. In some embodiments, the wellhead gas may be passed through a separator, such as separator  106  in  FIG. 1 , prior to entering the wellhead gas burner  200 . However, in other embodiments, a separator, such as separator  106 , may not be used, and the wellhead gas may enter the wellhead gas burner  200  directly from the wellhead. The wellhead gas may enter the wellhead gas burner  200  through the supply line union  202 . From the supply line union  202 , the wellhead gas may flow through the first supply line section  204  to the first valve  206 . The first valve  206  may be configured to restrict and/or prevent flow through the wellhead gas burner  200 . After passing through the first valve  206 , wellhead gas may flow through the second supply line section  208  to the pressure regulator  210 . The pressure regulator  210  may be configured to restrict and/or prevent flow through the wellhead gas burner  200  and/or may be configured to control the pressure of the wellhead gas entering the expansion chamber  212 . For example, in some embodiments, the pressure regulator  210  may prevent the pressure in the expansion chamber  212  from exceeding about 150 psi. 
     In the expansion chamber  212 , the wellhead gas may expand. By expanding the wellhead gas in the expansion chamber  212 , the wellhead gas may substantially fill the expansion chamber  212 . Additionally, the pressure of the wellhead gas in the expansion chamber  212  may be less than the pressure of the wellhead gas in the first supply line section  204  and/or the second supply line section  208 . By controlling the pressure of the wellhead gas entering and/or contained within the expansion chamber  212 , pressure fluctuations from the wellhead may be neutralized, thereby allowing the flow rate of the wellhead gas through the remainder of the wellhead gas burner  200  to remain substantially constant and/or uninterrupted. Accordingly, by controlling the pressure of the wellhead gas in the expansion chamber  212  through the pressure regulator  210  and/or allowing the wellhead gas to expand within the expansion chamber  212 , fluctuations in wellhead gas pressure may have a minimal effect on the delivery of wellhead gas to the combustion chambers  224 . Further, it will be appreciated that the velocity of the wellhead gas through the expansion chamber  212  may be less than the velocity of the wellhead gas through the first supply line section  204  and/or the second supply line section  208 . 
     In some embodiments, the expansion chamber  212  may allow the wellhead gas to be continuously combusted by lowering the velocity of the wellhead gas. It is theorized that lower wellhead gas velocities in the expansion chamber (and hence greater residence time) can normalize pressure and composition fluctuations in the wellhead gas and produce a more stable combustion process. Generally, the wellhead gas velocity in the expansion chamber  212  may be about 10% to about 70%, about 40% to about 60%, or about 50% less than the wellhead gas velocity in the first supply line section  204 . For example, when the first supply line section  204  is 2″ schedule  40  pipe, the expansion chamber  212  is 3″ schedule  40  pipe, and the flow rate of the wellhead gas is 70,000 cubic feet per hour, the wellhead gas velocity in the supply line section  204  is about 208 feet per second (fps), whereas the wellhead gas velocity in the expansion chamber  212  is about 94.6 fps, a reduction of about 55%. 
     In other embodiments, the expansion chamber  212  may allow the wellhead gas to be continuously combusted by maintaining a consistent pressure of the wellhead gas. By maintaining consistent wellhead gas pressure in the expansion chamber  212 , a more stable combustion process may be maintained. Generally, the wellhead gas pressure in the expansion chamber  212  may be about 5-25% less, about 8-12% less, or about 10% less than the wellhead gas pressure in the first supply line section  204  when no separator, such as separator  106  in  FIG. 1 , is used. However, the wellhead gas pressure in the expansion chamber  212  may be about 5-50% less, about 10-40% less, or about 25% less than the wellhead gas pressure in the first supply line section  204  when a separator, such as separator  106  in  FIG. 1 , is used. 
     From the expansion chamber  212 , wellhead gas may be passed through a fitting  214  and/or a third supply line section  216  to the second valve  218 . The second valve  218  may be configured to further restrict and/or prevent the flow of wellhead gas through the wellhead gas burner  200 . After passing through the second valve  218 , the wellhead gas may enter the fuel rail  220 . Upon entering the fuel rail  220 , wellhead gas may be substantially evenly distributed through the plurality of fuel rail fingers  222 . In some embodiments, the pressure of the wellhead gas entering the fuel rail may be about 60 psi. Wellhead gas may flow through the fuel rail fingers  222  to the plurality of combustion chambers  224  and exit each of the plurality of fuel rail fingers  222  through a plurality of holes and/or openings in each of the fuel rail fingers  222  that are each in fluid communication with a respective orifice  236 . Wellhead gas may thereby exit the fuel rail finger  222  through the orifice  236  and enter the internal cavity  240  of the combustion chamber  224 , where the wellhead gas may be combusted to produce heat energy that may be used to heat water and/or other chemicals used for hydrocarbon production and/or well completion processes. 
     In a first preferred embodiment of the wellhead gas burner  200 , the fuel rail  220  may comprise a 1.5″ schedule  40  pipe, the fuel rail fingers  222  may comprise a 1.0″ schedule  40  pipe, the combustion tube holder  226  may comprise a 2.0″ inch schedule  40  pipe having a length of about 2.0″ (51 mm), the combustion tube  228  may comprise a 1.5″ schedule  40  pipe having a length of about 5.0″ (127 mm), and the orifice  236  may comprise a #40 orifice. In a second preferred embodiment of the wellhead gas burner  200  that may be used for substantially higher pressure wellhead gas applications, the fuel rail  220  may comprise a 2.5″ schedule  80  pipe, the fuel rail fingers  222  may comprise a 1.25″ schedule  80  pipe, the combustion tube holder  226  may comprise a 3.0″ inch schedule  80  pipe having a length of about 2.0″ (51 mm), the combustion tube  228  may comprise a 2.5″ schedule  80  pipe having a length of about 5.0″ (127 mm), and the orifice  236  may comprise a #40 orifice. 
     Referring now to  FIGS. 4 and 5 , a schematic of a wellhead gas burner  300  and a detailed cutaway view of a combustion chamber  324  mounted to a fuel rail finger  322  of the wellhead gas burner  300  is shown according to another embodiment of the disclosure. Wellhead gas burner  300  may generally be substantially similar to wellhead gas burner  116  in  FIG. 1  and wellhead gas burner  200  of  FIGS. 2-3  and be capable of being used in the superheater truck  112  of the wellhead gas superheater system  100  of  FIG. 1  in a manner substantially similar to that of wellhead gas burner  200 . Wellhead gas burner  300  comprises a supply line union  302 , a first supply line section  304 , a first valve  306 , a second supply line section  308 , a pressure regulator  310 , an expansion chamber  312 , a fitting  314 , a third supply line section  316 , a second valve  318 , a fuel rail  320 , a plurality of fuel rail fingers  322  attached to the fuel rail  320 , a plurality of combustion chambers  324  comprising a combustion tube holder  326  and combustion tube  328  that are each attached to each fuel rail finger  322 , and a plurality of combustion nozzles  330  that each comprise a threaded bung  332  welded to the fuel rail finger  322  and a threaded nozzle  334  that is threadably inserted into a threaded opening  338  of the threaded bung  332  and that comprises an orifice  336  in fluid communication with the threaded bung  332  and/or a hole and/or opening in the fuel rail finger  322  to allow wellhead gas that flows through the fuel rail finger  322  to escape the fuel rail finger  322  through the orifice  336  and into an internal cavity  340 . However, wellhead gas burner  300  is configured to be integrated with a traditional gas burner  342  that may be substantially similar to the traditional gas burner  118  of  FIG. 1 . Further, wellhead gas burner  300  may also be configured to be used in the superheater truck  112  of the wellhead gas superheater system  100  of  FIG. 1 . 
     The traditional gas burner  342  may generally comprise a traditional fuel rail  344 , a plurality of traditional fuel rail fingers  346  connected and/or coupled in fluid communication to the traditional fuel rail  344 , and a plurality of traditional combustion chambers  348  on each of the plurality of traditional fuel rail fingers  346 . Most generally, to integrate the wellhead gas burner  300  with the traditional gas burner  342 , the fuel rail fingers  322  of the wellhead gas burner  300  may be disposed (e.g. alternatingly) with the traditional fuel rail fingers  346  of the traditional gas burner  342 . Said differently, the fuel rail fingers  322  may be interstitially spaced between adjacent traditional fuel rail fingers  346 . In some embodiments, wellhead gas burner  300  may comprise the same number of fuel rail fingers  322  as the traditional gas burner  342  comprises traditional fuel rail fingers  346 . However, in other embodiments, the wellhead gas burner  300  may comprise a different number of fuel rail fingers  322  as compared to the traditional fuel rail fingers  346 . In yet other embodiments, the wellhead gas burner  300  may comprise one more fuel rail finger  322  than the traditional gas burner  342  comprises traditional fuel rail fingers  346 , such that the traditional fuel rail fingers  346  are substantially enveloped on each side by a fuel rail finger  322  and each traditional fuel rail finger  346  is substantially enveloped on each of two adjacent sides by a fuel rail finger  322  of the wellhead gas burner  300 . 
     To facilitate integration of the wellhead gas burner  300  with the traditional gas burner  342 , in some embodiments, the combustion chambers  324  of the wellhead gas burner  300  may be offset in a substantially longitudinal direction with respect to the length of a fuel rail finger  322  and/or the length of a traditional fuel rail finger  346 . In some embodiments, the combustion chambers  324  may be offset a longitudinal offset distance equal to about one-half of the center-to-center distance between adjacent traditional combustion chambers  348 . In other words, the combustion chambers  324  of the wellhead gas burner  300  may be disposed such that the combustion chamber  324  is substantially equidistant from each adjacent traditional combustion chamber  348 . However, in other embodiments, the combustion chambers  324  may be disposed in a space between traditional combustion chambers  348  of adjacent traditional fuel rail fingers  346  such that the combustion chambers  324  and the traditional combustion chambers  348  are not substantially in contact. 
     Alternatively, the wellhead gas burner  300  may be integrated with the traditional gas burner  342 , such that the fuel rail fingers  322  of the wellhead gas burner  300  are oriented perpendicularly with the traditional fuel rail fingers  346  of the traditional gas burner  342 . In such embodiments, the fuel rail fingers  322 ,  346  of one gas burner  300 ,  342  may rest on top of the fuel rail fingers  322 ,  346  of the other burner  300 ,  342 . Additionally, the the combustion chambers  324  may be offset a longitudinal offset distance equal to about one-half of the center-to-center distance between adjacent traditional combustion chambers  348 . In other words, the combustion chambers  324  of the wellhead gas burner  300  may be disposed such that the combustion chamber  324  is substantially equidistant from each adjacent traditional combustion chamber  348 . However, in other embodiments, the combustion chambers  324  may be disposed in a space between traditional combustion chambers  348  of adjacent traditional fuel rail fingers  346  such that the combustion chambers  324  and the traditional combustion chambers  348  do not substantially overlap. 
     The wellhead gas burner  300  may generally comprise substantially the same number of combustions chambers  324  as the traditional gas burner  342  comprises traditional combustion chambers  348 . However, in other embodiments, the wellhead gas burner  300  may comprise a different number of combustion chambers  324  as the traditional gas burner  342  comprises traditional combustion chambers  348 . Additionally, in some embodiments, the components of the combustion chambers  324  and the components of the traditional combustion chambers  348  may comprise substantially similar sizes. However, in some embodiments, the components of the combustion chambers  324  and the components of the traditional combustion chambers  348  may comprise different sizes. 
     To further facilitate integration of the wellhead gas burner  300  with the traditional gas burner  342 , wellhead gas burner  300  may comprise flexible finger connections  323 . The flexible finger connections  323  are configured to connect and/or couple the fuel rail  320  in fluid communication with the plurality of fuel rail fingers  322 . Each fuel rail finger  322  comprises a single flexible finger connection  323  to the fuel rail  320 . In some embodiments, the flexible finger connection  323  may allow the fuel rail fingers  322  to move, float, and/or shift between the traditional fuel rail fingers  346  and with respect to the traditional fuel rail fingers  346 . In some embodiments, the flexible finger connections  323  may comprise a flexible hose and/or a flexible tube that allows the fuel rail fingers  322  to individually move with respect to the fuel rail  320  and/or the traditional fuel rail fingers  346 . However, in other embodiments, the flexible finger connections  323  may comprise a rigid hose and/or tubing coupled with a flexible fitting. Configuring the wellhead gas burner  300  with flexible finger connections  323  may provide for more versatile installation configurations as compared to a fixed, welded connection between the fuel rail  220  and the fuel rail fingers  222  in wellhead gas burner  200  of  FIG. 2 . 
     Because the flexible finger connections  323  may allow the fuel rail fingers  322  to move with respect to the fuel rail  320  and/or the traditional fuel rail fingers  346 , burner supports  350  may be employed to provide support to the fuel rail fingers  322  and/or the traditional fuel rail fingers  346 . The burner supports  350  may generally span across the fuel rail fingers  322 ,  346  to support the weight of the fuel rail fingers  322 ,  346  and/or prevent the fuel rail fingers  322  of the wellhead gas burner  300  from moving once integrated in a final installation position with the traditional fuel rail fingers  346  of the traditional gas burner  342 . Further, the burner supports  350  may generally be disposed substantially perpendicularly to the fuel rail fingers  322  and/or the traditional fuel rail fingers  346 . 
     Still referring to  FIGS. 4-5 , in operation, the wellhead gas burner  300  may receive wellhead gas from a wellhead, such as wellhead  102  in  FIG. 1 , and be configured to operate in a substantially similar manner to the operation of the wellhead gas burner  200  in  FIGS. 2-3 . The wellhead gas burner  300  may generally be configured as the primary source of thermal energy to heat water and/or other chemicals used for hydrocarbon production and/or well completion processes, while the traditional gas burner  342  may be configured as a supplemental source of thermal energy. In some embodiments, at least about 150 psi of wellhead gas pressure is needed to operate the wellhead gas burner  300 . When the wellhead gas pressure drops below about 150 psi, the traditional gas burner  342  may be operated to burn methane, ethane, propane, butane, gasoline, diesel, liquified natural gas (LNG), natural gas liquids (NGLs), wellhead gas, and/or any other appropriate fuel source to provide supplemental heat to heat well completion fluids until the wellhead gas pressure increases to at least about 150 psi. Additionally, in some embodiments, wellhead gas may not be used. Instead, any two fuels may be used in the wellhead gas burner  300  and the traditional gas burner  342  (e.g. propane and LNG). Still further, in some embodiments, if the wellhead gas provides less than about 3500 BTU per cubic foot, the traditional gas burner  342  may be operated to burn any other fuel to provide supplemental heat to heat well completion fluids. In other embodiments, however, the traditional gas burner  342  may be operated to provide supplemental heat when the wellhead gas provides less than about 3500 BTU per cubic foot. In yet other embodiments, however, the wellhead gas burner  300  may be operated simultaneously with the traditional gas burner  342  to provide an additional amount of heat. 
     In a preferred embodiment of the wellhead gas burner  300 , the fuel rail  320  may comprise a 1.5″ schedule  40  pipe, the fuel rail fingers  322  may comprise a 1.0″ schedule  40  pipe, the combustion tube holder  326  may comprise a 2.0″ inch schedule  40  pipe having a length of about 2.0″ (51 mm), the combustion tube  328  may comprise a 1.5″ schedule  40  pipe having a length of about 5.0″ (127 mm), and the orifices  336  may comprise a #40 orifice. Further, it will be appreciated that the orifices  336  of the wellhead gas burner  300  may, at least in some embodiments, comprise a larger orifice diameter than orifices of the traditional gas burner  342 . For example, the orifices  336  of the wellhead gas burner  300  may comprise a #40 orifice while the orifices of the traditional gas burner  342  comprise a #50 orifice. Alternatively, as opposed to the threaded bung  332  and the threaded nozzle  334 , each combustion nozzle  330  may comprise an orifice  336  that comprises a hole drilled in the fuel rail finger  346 . In such embodiments, the orifices  336  may comprise at least about a #30 orifice up to about a #50 orifice. 
     Referring now to  FIG. 6 , a flowchart of a method  400  of burning wellhead gas is shown according to an embodiment of the disclosure. The method  400  may begin at block  402  by producing wellhead gas from a wellbore. The method  400  may continue at block  404  by expanding the wellhead gas. In some embodiments, this may be accomplished by flowing the wellhead gas through a pressure regulator and/or an expansion chamber. In some embodiments, expanding the wellhead gas may comprise reducing the pressure of the wellhead gas. The method  400  may continue at block  406  by distributing the expanded wellhead gas. In some embodiments, distributing the wellhead gas may be accomplished by flowing the wellhead gas through a fuel rail that is in fluid communication with a plurality of fuel rail fingers. In some embodiments, the wellhead gas may be further distributed from each fuel rail finger to a plurality of combustion chambers. The method  400  may continue at block  408  by combusting the distributed wellhead gas. In some embodiments, the wellhead gas may be combusted by flowing the wellhead gas through a plurality of orifices into a plurality of combustion chambers. The method  400  may continue at block  410  by heating a fluid with the heat produced as a result of combusting the distributed wellhead gas. However, in some embodiments, the wellhead gas burner may be integrated with a traditional gas burner. In such embodiments, the method  400  may include operating the traditional gas burner when the pressure of the gas produced from the wellhead drops below about 150 psi and/or when the BTU per cubic foot output from the wellhead gas burner drops below about 3500 BTU per cubic foot. However, in some embodiments, the wellhead gas burner and the traditional burner may be operated simultaneously. The method  400  may conclude at block  412  by treating the wellbore with the heated fluid. In some embodiments, treating the wellbore may comprise using the heated fluid in a hydraulic fracturing process. 
     Referring now to  FIGS. 7-9 , a schematic of a superheater truck  500  is shown according to an embodiment of the disclosure. Superheater truck  500  may generally be substantially similar to superheater truck  112  of  FIG. 1 . Superheater truck  500  comprises a burner box  502  comprising an intake port  504 , a shell  508  configured to house at least one burner  510  and at least one heat exchanger  511 , and an exhaust port  512 . Superheater truck  500  may also comprise a storage tank  120  configured to store heated and/or unheated fluid received from the heat exchanger  511 . Additionally, the storage tank  120  may comprise a vent  520 . The intake port  504  may be configured to allow a flow of air from outside of the shell  508  to enter the shell  508  and aid in combustion of gases by the burner  510 . In some embodiments, the burner box  502  may comprise a single intake port  504  that may be disposed in a side of the shell  508 . However, in other embodiments, the burner box  502  may also comprise at least one intake port  504  disposed on a bottom side of the burner box  502 . In this embodiment, the burner box  502  comprises an intake port  504  disposed in at least one side of the shell  508  and two intake ports  504  disposed on the bottom side of the burner box  502 . 
     The shell  508  may generally be configured to house the burner  510  and/or provide protection to the burner  510  from wind, rain, and/or other environmental factors that may affect the combustion provided by the burner  510 . The burner  510  may generally be substantially similar to burners  116 ,  118  of  FIG. 1  and be configured to provide combustion of a wellhead gas, propane, diesel fuel, and/or any other fuel source in the presence of ambient air received through at least one of the intake ports  504 . Further, heat produced from the combustion of the fuel source may be used to heat the water and/or other chemicals used in hydrocarbon production and/or well completion processes, including, but not limited to, fracking. The transfer of heat from the burner  510  to the water and/or other chemicals may be accomplished by passing the water and/or other chemicals through a heat exchanger  511  disposed above the burner  510 . Accordingly, heated water and/or other chemicals heated by the burner  510  may be stored in the storage tank  120 , which may comprise a vent  520  configured to vent gases within the storage tank  120  to ambient in order to relieve pressure on the storage tank  120 . Additionally, after combustion, combusted fuel and/or air/fuel mixture may be passed out of the burner box  502  and/or the shell  508  through the exhaust port  512  disposed at an uppermost part of the shell  508  of the burner box  502 . Furthermore, the superheater truck  500  may comprise an intake flame arrestor  506  on the intake port  504 , an exhaust port flame arrestor  514  on the exhaust port  512 , and/or a vent flame arrestor  522  on the vent  520  of the storage tank  120 . 
     Referring now to  FIG. 8 , a schematic of the burner box  502  of the superheater truck  500  of  FIG. 7  is shown according to an embodiment of the disclosure. As stated, the burner box  502  comprises a plurality of intake ports  504 , an intake flame arrestor  506  on each intake port  504 , a shell  508  that houses the burner  510  and a heat exchanger  511 , an exhaust port  512 , and an exhaust flame arrestor  514  on the exhaust port  512 . Most generally, each of the flame arrestors  506 ,  514  comprises a heat exchanging device having a plurality of substantially parallel rows of fins  516  and having a plurality of corrugated fins  518  disposed between adjacent fins  516 . The fins  516 ,  518  may generally be formed from a thermally conductive material (e.g. aluminum) and configured to dissipate heat generated by the combustion of gases by the burner  510 . As such, the flame arrestors  506 ,  514  may be configured to extinguish any combustion as gases pass through the flame arrestors  506 ,  514 . 
     The intake port flame arrestors  506  may generally be received within the intake ports  504 , disposed on an outside surface of the shell  508 , and/or disposed on the outside of each of the intake ports  504 . The intake port flame arrestor  506  may dissipate heat generated by the combustion of gases by the burner  510 . Without the intake port flame arrestor  506 , the heat from the combustion of gases by the burner  510  may freely escape the burner box  502  through the intake ports  504  and may ignite an external source of hydrocarbons and/or other combustible gases outside of the burner box  502 . As a result of dissipating the combustion heat, the intake flame arrestor  506  may control the location of the combustion. Accordingly, the intake port flame arrestor  506  may contain the combustion within the shell  508  and/or the burner box  502  and prevent, restrict, and/or substantially reduce the likelihood of combustion occurring externally to the burner box  502  at or near the intake ports  504 . The intake port arrestor  506  thereby may be configured to prevent ignition of an external source of hydrocarbons and/or other combustible gases outside of the burner box  502 . 
     The exhaust port flame arrestor  514  may generally be received within the exhaust port  512  and/or disposed on the outside of the exhaust port  512 . The exhaust port flame arrestor  514  may also dissipate heat generated by the combustion of gases by the burner  510 . Without the exhaust port flame arrestor  514 , the heat from the combustion of gases by the burner  510  may freely escape the burner box  502  through the exhaust port  512  and may ignite an external source of hydrocarbons and/or other combustible gases outside of the burner box  502 . As a result of dissipating the combustion heat, the exhaust flame arrestor  514  may control the location of the combustion and extinguish the combustion of gases passing through the exhaust port  512  to ambient. Accordingly, the exhaust port flame arrestor  514  may contain the combustion within the shell  508  and/or the burner box  502  and prevent, restrict, and/or substantially reduce the likelihood of combustion occurring externally to the burner box  502  at or near the exhaust port  512 . The exhaust port arrestor  514  thereby may be configured to prevent ignition of an external source of hydrocarbons and/or other combustible gases outside of the burner box  502 . Accordingly, it will be appreciated that the intake port flame arrestor  506  and the exhaust port flame arrestor  514  may collectively contain the combustion of gases within the burner box and prevent ignition of an external source of hydrocarbons and/or other combustible gases outside of the burner box  502 . 
     Referring now to  FIG. 9 , a schematic of a portion of the vent  520  of the superheater truck  500  of  FIG. 7  is shown according to an embodiment of the disclosure. As stated, the storage tank  120  may be configured to store water and/or other chemicals used in hydrocarbon production and/or well completion processes. The water and/or other chemicals used for these processes may often be heated and pressurized. The vent  520  may generally comprise an elongated tube, box, or opening configured to provide a pathway for heated and/or pressurized gases trapped within the storage tank  120  to escape the storage tank  120  to relieve pressure within the storage tank  120 . Such gases escaping the vent  520  may have a tendency to ignite outside of the vent  520 . As such, vent  520  comprises a vent flame arrestor  522 . The vent flame arrestor  522  may be substantially similar to flame arrestors  506 ,  514  and comprise a plurality of substantially parallel rows of fins  516  and having a plurality of corrugated fins  518  disposed between adjacent fins  516 . However, in some embodiments, the fins  516  may be arranged annularly and/or radially about a center of the vent flame arrestor  522 . The vent flame arrestor  522  may generally be configured to dissipate heat and extinguish the combustion of gases passing through the vent  520  and/or the vent flame arrestor  522 . Accordingly, any combustion that occurs within the storage tank  120  and/or the vent  520  may be contained within the storage tank  120  and/or the vent  520  by the vent flame arrestor  522 . Thus, the vent flame arrestor  522  may be configured to prevent, restrict, and/or substantially reduce the likelihood of combustion occurring externally to the vent  520 . 
     The vent  520  may also comprise a secondary vessel  524  configured to capture, retain, and/or collect liquids that may attempt to escape from the storage tank  120  through the vent  520 . The secondary vessel  524  may comprise a drain  526  that may be configured to allow selective removal of the liquids captured within an inner storage volume of the secondary vessel  524 . The secondary vessel  524  may comprise a hose that carries fluids from the vent  520  to a secondary storage tank. However, in other embodiments, the secondary vessel  524  may comprise an inline vessel disposed between the storage tank  120  and the vent flame arrestor  522 . As such, it will be appreciated that the secondary vessel  524  may be disposed upstream from the vent flame arrestor  522  with respect to a flow of fluids from the storage tank  120  through the vent  520  and the vent flame arrestor  522 . Accordingly, in some embodiments, the vent flame arrestor  522  may be disposed on a distal end of the vent  520 . The secondary vessel  524  may further comprise a liquid level indicator  528 . In some embodiments, the liquid level indicator  528  may comprise a sight glass that allows for visual inspection of a liquid level within the secondary vessel  524 . However, in other embodiments, the liquid level indicator  528  may comprise a mechanical and/or electronic gauge that indicates the liquid level within the secondary vessel  524 . 
     Referring now to  FIG. 10 , a schematic of a superheater truck  600  is shown according to another embodiment of the disclosure. Superheater truck  600  may generally be substantially similar to superheater truck  500 . However, superheater truck  600  comprises an electric heating system  602  instead of the burner box  502  of superheater truck  500 . Superheater truck  600  may also comprise a heat exchanger  604  that may be substantially similar to heat exchanger  511  of superheater truck  500 . It will be appreciated that in some embodiments, superheater truck  600  may also comprise a storage tank  120 , a vent  520 , a vent flame arrestor  522 , and/or a secondary vessel  524 . 
     The electric heating system  602  may generally comprise at least one electric resistive heating element that may produce heat when an electrical current is applied. However, in some embodiments, the electric heating system  602  may comprise a plurality of electric resistive heating elements. The heat produced by the electric heating system  602  may provide direct and/or indirect heat to the heat exchanger  604  to heat water and/or other chemicals used in hydrocarbon production and/or well completion processes, including, but not limited to, fracking. The transfer of heat from the electrical heating system  602  to the water and/or other chemicals may be accomplished by passing the water and/or other chemicals through the heat exchanger  604  that is subjected to the heat produced by the electric heating system  602 . Furthermore, after the water and/or other chemicals are heated by the electrical heating system  602 , the heated water and/or other chemicals may be stored in the storage tank  120 . It will be appreciated that by providing superheater truck  600  with an electrical heating system  602 , the burner box  502  of superheater truck  500  may be eliminated, thereby preventing ignition of an external source of hydrocarbons and/or other combustible gases present in the ambient air. 
     Referring now to  FIG. 11 , a schematic of a superheater truck  700  is shown according to another alternative embodiment of the disclosure. Superheater truck  700  may generally be substantially similar to superheater truck  500  and/or superheater truck  600 . However, superheater truck  700  comprises an infrared heating system  702  instead of the burner box  502  of superheater truck  500  and the electrical heating system  602  of superheater truck  600 . Superheater truck  700  may also comprise a heat exchanger  704  that may be substantially similar to heat exchanger  511  of superheater truck  500  and/or heat exchanger  604  of superheater truck  600 . It will be appreciated that in some embodiments, superheater truck  700  may also comprise a storage tank  120 , a vent  520 , a vent flame arrestor  522 , and/or a secondary vessel  524 . 
     The infrared heating system  702  may generally comprise at least one infrared burner and/or catalyst heater that be fueled by a hydrocarbon fuel, wellhead gas, propane, diesel fuel, and/or any other fuel source in the presence of ambient air. As such, the infrared burner and/or catalyst heater may be configured to emit infrared heat as a result of burning at least one of the hydrocarbon fuel, wellhead gas, propane, diesel fuel, and/or any other fuel source. However, in some embodiments, the infrared heating system  702  may comprise a plurality of infrared burners and/or catalyst heaters. The infrared heat produced by the infrared heating system  702  may be directed to the heat exchanger  704  to heat water and/or other chemicals used in hydrocarbon production and/or well completion processes, including, but not limited to, fracking. The transfer of infrared heat from the infrared heating system  702  to the water and/or other chemicals may be accomplished by passing the water and/or other chemicals through the heat exchanger  704  that is subjected to the infrared heat produced by the infrared heating system  702 . Furthermore, after the water and/or other chemicals are heated by the infrared heating system  702 , the heated water and/or other chemicals may be stored in the storage tank  120 . It will be appreciated that by providing superheater truck  700  with an electrical heating system  702 , the burner box  502  of superheater truck  500  may be eliminated, thereby preventing ignition of an external source of hydrocarbons and/or other combustible gases present in the ambient air. 
     Referring now to  FIG. 12 , a flowchart of a method  800  of operating a superheater truck is shown according to an embodiment of the disclosure. The method  800  may begin at block  802  by providing a superheater truck with a flame arrestor. In some embodiments, the flame arrestor may be intake port flame arrestor  506 , exhaust port flame arrestor  514 , and/or vent flame arrestor  522  of superheater truck  500 . The method  800  may continue at block  804  by combusting a fuel within a burner of the superheater truck. In some embodiments, the burner may be burner  510  of superheater truck  500 . The method  800  may continue at block  806  by preventing combustion of a flammable substance outside at least one of a burner box and a vent of a storage tank of the superheater truck. In some embodiments, this may be accomplished by at least one of the flame arrestors  506 ,  514 ,  522  dissipating heat produced by the combustion of the fuel within the burner  510  and/or dissipating heat produced by the combustion of gases within a vent  520  of the superheater truck  500 . In some embodiments, this may also be accomplished by at least one of the flame arrestors  506 ,  514 ,  522  containing the combustion within at least one of the burner box  510  and the vent  520  of the superheater truck  500 . 
     At least one embodiment is disclosed and variations, combinations, and/or modifications of the embodiment(s) and/or features of the embodiment(s) made by a person having ordinary skill in the art are within the scope of the disclosure. Alternative embodiments that result from combining, integrating, and/or omitting features of the embodiment(s) are also within the scope of the disclosure. Where numerical ranges or limitations are expressly stated, such express ranges or limitations should be understood to include iterative ranges or limitations of like magnitude falling within the expressly stated ranges or limitations (e.g., from about 1 to about 10 includes, 2, 3, 4, etc., greater than 0.10 includes 0.11, 0.12, 0.13, etc.). For example, whenever a numerical range with a lower limit, R l , and an upper limit, R u , is disclosed, any number falling within the range is specifically disclosed. In particular, the following numbers within the range are specifically disclosed R=R l +k*(R u −R l ), wherein k is a variable ranging from 1 percent to 100 percent with a 1 percent increment, i.e., k is 1 percent, 2 percent, 3 percent, 4 percent, 5 percent, . . . , 50 percent, 51 percent, 52 percent, . . . , 95 percent, 96 percent, 97 percent, 98 percent, 99 percent, or 100 percent. Unless otherwise stated, the term “about” shall mean plus or minus 10 percent of the subsequent value. Moreover, any numerical range defined by two R numbers as defined in the above is also specifically disclosed. Use of the term “optionally” with respect to any element of a claim means that the element is required, or alternatively, the element is not required, both alternatives being within the scope of the claim. Use of broader terms such as comprises, includes, and having should be understood to provide support for narrower terms such as consisting of, consisting essentially of, and comprised substantially of. Accordingly, the scope of protection is not limited by the description set out above but is defined by the claims that follow, that scope including all equivalents of the subject matter of the claims. Each and every claim is incorporated as further disclosure into the specification and the claims are embodiment(s) of the present invention.