Abstract:
A gas expansion cooling method for reducing hydrocarbon emissions includes feeding a high pressure cooling gas through a valve, decreasing a temperature of the cooling gas by decreasing its pressure; feeding the cooling gas into a heat exchanger; and diverting a hydrocarbon gas into the heat exchanger such that the cooling gas decreases a temperature of the hydrocarbon gas. The cooling gas may be drawn from a preexisting high pressure gas system that serves a purpose other than supplying a coolant for the gas expansion cooling system. A portion of the hydrocarbon gas may be condensed in the heat exchanger to form a hydrocarbon liquid, which may be separated from the hydrocarbon gas in a separation vessel. The hydrocarbon liquid may be recovered, while the hydrocarbon gas may be fed to a ventilation system.

Description:
CROSS REFERENCE TO RELATED PATENT APPLICATIONS 
     This application claims priority to U.S. Provisional Application No. 61/492,190, filed on Jun. 1, 2011, which is incorporated herein by reference. 
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS 
       FIG. 1  is a schematic view of the equipment involved in the gas expansion cooling method used to cool hydrocarbon vapors from a hydrocarbon storage tank. 
       FIG. 2  is a schematic view of an alternate equipment arrangement for the gas expansion cooling method shown in  FIG. 1 . 
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
     The United States Environmental Protection Agency (EPA) regulates the emission of harmful vapors into the air. For example, the EPA regulates the release of volatile organic compounds (VOCs) and mono-nitrogen oxides (NOx). VOCs are organic chemicals that have high vapor pressures at ambient conditions due to low boiling points. Many VOCs are dangerous to human health or harmful to the environment. It has been established that many petroleum products are not only toxic, but are also carcinogens. This is especially true of many of the lighter fractions of petroleum products, formed of relatively light weight molecules and having relatively high vapor pressures. In the past, these products were routinely vented to the atmosphere. The EPA now regulates the release of hydrocarbon vapors and VOCs into the atmosphere. The Clean Air Act requires that Maximum Achievable Control Technology (MACT) removes VOCs with at least 95% efficiency. 
     A method for cooling a fluid using a gas cooled by a decrease in pressure (i.e., an expansion of the gas). The cooling gas may be supplied by a preexisting gas line on a job location having a high pressure. The preexisting gas line may be present on the job location for a purpose other than for use of the gas as a coolant. For example, gas recovered from an oil and gas well may be compressed before being transported by pipeline. A portion of the high pressure gas exiting the compressor may be diverted for use as a cooling gas in a heat exchanger for cooling another fluid. The high pressure gas may be cooled by flowing through a pressure reduction valve, such as a Joule-Thomson valve (JT valve), which causes the gas to expand thereby decreasing the temperature of the gas. This cooling gas may be fed into the shell portion of a heat exchanger, while a fluid is fed through an inner portion of the heat exchanger. The fluid flowing through the inner portion of the heat exchanger is cooled by the cooling gas flowing through the shell portion. After exiting the heat exchanger, the cooling gas may be returned to the compressor. 
     The gas expansion cooling method may include cooling a high pressure gas by decreasing the pressure, and causing the cooled gas to flow through a heat exchanger to cool and/or condense another fluid flowing through the heat exchanger. 
     One application for the gas expansion cooling method is in the control of emissions from hydrocarbon storage tanks, such as the method disclosed in U.S. Pat. No. 5,897,690, issued to Robert L. McGrew on Apr. 27, 1999, which is incorporated herein by reference. Gas expansion cooling system  10  for cooling hydrocarbon vapors from source  12  is illustrated in  FIG. 1 . In one embodiment, source  12  may be a hydrocarbon storage tank. Certain types of hydrocarbons held in storage tanks vaporize within the tanks. These hydrocarbon vapors may flow into vapor line  14 . Atomizer  16  may assist in the flow of the hydrocarbon vapors into vapor line  14  through the creation of a slight vacuum. Vapor line  14  may ultimately lead to ventilation system  18 , but three way valve  20  positioned on vapor line  14  may divert the hydrocarbon vapors into hydrocarbon input line  22 . The hydrocarbon vapors may flow through hydrocarbon input line  22 . In some embodiments, the hydrocarbon vapors may contain small amounts of impurities, such as water vapor. Atomizer  16  may be a nozzle or other spraying device, and it may be positioned on hydrocarbon input line  22 . Alternatively, atomizer  16  may be positioned within an inner portion of heat exchanger  24 . Atomizer  16  may create a slight vacuum in hydrocarbon input line  22  as described in more detail below. The hydrocarbon vapors may flow into an inner portion of heat exchanger  24 . In one embodiment, the hydrocarbon vapors may flow into a tube portion of heat exchanger  24 . 
     A cooling gas may enter gas cooling system  10  through cooling gas input line  26 . In one embodiment, the cooling gas may be supplied by a preexisting gas line on a job location having a high pressure. For example, the cooling gas may be a portion of the process gas from an oil &amp; gas well. The high pressure cooling gas may be cooled by flowing through valve  28  on cooling gas input line  26 . Valve  28  may cause the cooling gas to expand by forcing it through a restriction orifice, thereby decreasing the pressure and temperature of the gas. In this way, the hydrocarbon gas is cooled through expansion. Valve  28  may be any type of pressure reduction valve, such as a JT valve. The cooling gas may be cooled to a predetermined temperature based on the composition of the hydrocarbon gas in hydrocarbon input line  22 . In one embodiment, the cooling gas may be cooled to about 40° F. The cooling gas may be fed into a shell portion of heat exchanger  24 . 
     The cooling gas flowing through the shell portion of heat exchanger  24  may cool the hydrocarbon vapor flowing through the inner portion of heat exchanger  24 , thereby condensing the heavier and more harmful hydrocarbons in the hydrocarbon vapor in the inner portion. The remaining hydrocarbon vapors and the condensed hydrocarbon fluid may flow from the inner portion of heat exchanger  24 , through hydrocarbon fluid output line  30 , and into separation vessel  32 . The hydrocarbon fluid flowing through hydrocarbon fluid output line  30  may be mostly liquid with only trace amounts of hydrocarbon vapors. The remaining hydrocarbon vapors in separation vessel  32  include only lighter hydrocarbons (e.g., methane, ethane). The remaining hydrocarbon vapors and the condensed hydrocarbon fluid separate in separation vessel  32 . The remaining hydrocarbon vapors rise within separation vessel  32  and exit through hydrocarbon gas output line  34 . The condensed hydrocarbon fluid settles to the bottom of separation vessel  32 , and exits through hydrocarbon liquid output line  36 . In some embodiments, additional amounts of the hydrocarbon liquid may vaporize while in separation vessel  32  depending upon ambient temperatures and the length of time the hydrocarbon liquid remains in separation vessel  32  before exiting through hydrocarbon liquid output line  36 . These additional vaporized hydrocarbons may also rise within separation vessel  32  and exit through hydrocarbon gas output line  34 . The cooling gas may flow from the shell portion of heat exchanger  24  and into cooling gas output line  38 . 
     Cooling gas output line  38  may feed the cooling gas into a shell portion of second heat exchanger  40 , while hydrocarbon gas output line  34  may feed the remaining hydrocarbon vapors into an inner portion of second heat exchanger  40 . The cooling gas may cool the remaining hydrocarbon vapors in second heat exchanger  40 , thereby condensing any residual heavy hydrocarbons in the remaining hydrocarbon vapor. Any condensed hydrocarbons may drain from the inner portion of second heat exchanger  40  back into hydrocarbon gas output line  34  and separation vessel  32 . The remaining hydrocarbon vapors may exit second heat exchanger  40  through second hydrocarbon gas output line  42  and into vapor line  14 , which may direct the remaining hydrocarbon vapors to ventilation system  18 . Ventilation system  18  may include a vapor recovery system or a flare. Alternatively, ventilation system  18  may vent the remaining hydrocarbon vapors to the atmosphere. 
     The composition of the hydrocarbon vapors in lines  14 ,  22 ,  30 ,  34 , and  42  may vary. For example, vapor line  14  and hydrocarbon input line  22  may contain the highest concentration of VOCs or heavier hydrocarbon vapors. Hydrocarbon fluid output line  30  may contain hydrocarbon vapors and hydrocarbon liquids. The hydrocarbon vapors in line  30  may contain a lower concentration of VOCs or heavier hydrocarbon vapors, as these vapors may have condensed in heat exchanger  24 . Second hydrocarbon gas output line  42  may contain a lower concentration of VOCs or heavier hydrocarbon vapors than hydrocarbon gas output line  34 . 
     Hydrocarbon liquid output line  36  may feed the condensed hydrocarbon fluid from separation vessel  32  to source  12 . Alternatively, hydrocarbon liquid output line  36  may feed the condensed hydrocarbon fluid from separation vessel  32  into a collection vessel separate from source  12 . Pump  46  may assist in transporting the condensed hydrocarbon fluid through hydrocarbon liquid output line  36 . A portion of the condensed hydrocarbon fluid may be diverted from hydrocarbon liquid output line  36  and into atomizer feed line  48 , which may feed the cool condensed hydrocarbon fluid to atomizer  16 . Atomizer feed line  48  may be positioned downstream from pump  46  on hydrocarbon liquid output line  36 . Atomizer  16  may spray the condensed hydrocarbon fluid into the hydrocarbon vapor in hydrocarbon input line  22 . Because the spray of condensed hydrocarbon fluid is cooler than the hydrocarbon vapor, the hydrocarbon vapor is cooled and the pressure of the hydrocarbon vapor is decreased, thus creating a slight vacuum that may help to draw the hydrocarbon vapors from source  12  and into vapor line  14 . This pre-cooling step performed with atomizer  16  may increase the condensing efficiency of heat exchanger  24 . In an alternative embodiment, gas expansion cooling system  10  may include one or more atomizers positioned within the inner portion of heat exchanger  24 . In another alternative embodiment, one or more atomizers may be positioned within hydrocarbon gas output line  34  from separation vessel  32  to improve the efficiency of condensing heavier hydrocarbon vapors. Any condensed hydrocarbon fluid from this secondary cooling step may be drained into separation vessel  32 , and returned to source  12 . In yet another alternative embodiment, gas expansion cooling system  10  may include no atomizers. 
     The cooling gas may exit the shell portion of second heat exchanger  40  through second cooling gas output line  50 , which may return the cooling gas to its original position at the job location. For example, if the cooling gas was taken from a preexisting high pressure gas system on a job location, second cooling gas output line  50  may return the cooling gas to a low pressure gas system. Alternatively, if a low pressure system is not available, a gas booster may be positioned on second cooling gas output line  50  to compress the cooling gas, which may then be fed into the high pressure gas system. If the cooling gas is a hydrocarbon gas, second cooling gas output line  50  may feed the cooling gas to a fuel line, and the cooling gas may be used as a fuel on the job location. None of the gas in the high pressure system is lost through its use as a cooling gas. All of the cooling gas is recovered. In a more specific example, if the cooling gas was taken from a high pressure hydrocarbon gas pipeline, second cooling gas output line  50  may return the cooling gas to an inlet (or low pressure side) of a compressor in the pipeline in order to increase the pressure of the cooling gas to the pressure it had when taken into cooling gas input line  26 . Alternatively, if the compressor is already functioning at its intended capacity, a gas booster may be positioned on second cooling gas output line  50  to compress the cooling gas, which may then be fed into an outlet line (or high pressure side) of the compressor or into a pipeline directly. 
     Gas expansion cooling system  10  may further include level indicator  52  designed to indicate the level of the condensed hydrocarbon fluid within separation vessel  32 . Level control  54  may be designed to adjust a setting of control valve  56  on atomizer feed line  48  and control valve  58  on hydrocarbon liquid output line  36 . In one embodiment, control valve  56  may be a “normal open” valve, which has an open default position and a closed position when activated, while control valve  58  may be a “normal closed” valve, which has a closed default position and an open position when activated. With the default settings in this embodiment, the condensed hydrocarbon fluid may flow through hydrocarbon liquid output line  36  and into atomizer feed line  48 . In this embodiment, when level control  54  detects a predetermined liquid level within separation vessel  32 , level control  54  may activate control valves  56  and  58  such that control valve  56  closes and control valve  58  opens in order to drain the condensed hydrocarbon fluid from separation vessel  32  into hydrocarbon liquid output line  36  and back into source  12 . Level safety high control  59  may detect when a fluid level in level indicator  52  reaches a level safety high. 
     Meter  60  may be positioned on hydrocarbon liquid output line  36 , and may be designed to measure the amount of condensed hydrocarbon fluid returned to source  12 . Flow safety valve  62  may be positioned on hydrocarbon liquid output line  36  near source  12  in order to prevent the flow of hydrocarbon liquids from source  12  back into hydrocarbon liquid output line  36 . Shutdown valve  64  positioned on cooling gas input line  26  may be designed to stop the flow of the cooling gas through cooling gas input line  26  in the event that the fluid level in separation vessel  32  rises above a predetermined safe limit or in the event that the pressure rises above a predetermined safe limit. Thermostat  66  may be positioned on cooling gas input line  26  in order to indicate the temperature of the cooling gas in the cooling gas input line  26 . Pressure safety valve  68  may be positioned on a conduit leading from cooling gas input line  26 . Pressure safety valve  68  may be designed to measure the pressure of the cooling gas, and to open if the measured pressure value is above a predetermined pressure limit in order to vent some of cooling gas to ventilation system  70 . Ventilation system  70  may be the same system as ventilation system  18 . Alternatively, ventilation system  70  may be separate from ventilation system  18 . 
     If level safety high control  59  detects that the level safety high is reached in level indicator  52 , it may isolate gas expansion cooling system  10  by closing shutdown valve  64  to stop the flow of the cooling gas into cooling gas input line  26 , shutting down pump  46  to stop the flow of the condensed hydrocarbon fluid from separation vessel  32 , and adjusting three way valve  20  to prevent the hydrocarbon vapors in vapor line  14  from entering hydrocarbon input line  22 . Gas expansion cooling system  10  may include further safety and measuring devices or, alternatively, may not include one or more of devices  52 - 70 . 
       FIG. 2  illustrates an alternative embodiment of gas expansion cooling system  10 . In this embodiment, hydrocarbon liquid output line  36  may lead the condensed hydrocarbon fluid from separation vessel  32  and into source  12 . First pump  80  may be positioned on hydrocarbon liquid output line  36  to assist in returning the condensed hydrocarbon fluid to source  12 . In this embodiment, atomizer feed line  48  may lead a portion of the condensed hydrocarbon fluid directly from separation vessel  32  to atomizer  16 . Second pump  82  may be positioned on atomizer feed line  48 . Level control  54  may be designed to activate first pump  80  on hydrocarbon liquid output line  36  when a predetermined liquid level is reached in separation vessel  32  such that the condensed hydrocarbon fluid is drained from separation vessel  32 , thereby lowering the liquid level in separation vessel  32 . 
     Another application for the gas expansion cooling method is in the control of emissions from glycol reboilers, such as the method disclosed in U.S. Pat. No. 5,234,552, issued to Robert McGrew and John P. Broussard on Aug. 10, 1993, which is incorporated herein by reference. The gas expansion cooling method may be used for cooling steam and hydrocarbon vapors from a glycol reboiler. Glycol reboilers are designed to remove water from glycol after its use as a desiccant. Steam and vaporized hydrocarbons exiting the glycol reboiler are fed into an inner portion of a heat exchanger, while an atomizer sprays the steam and vaporized hydrocarbons with a cooling fluid and while a cooling fluid is fed into a shell portion of the heat exchanger. The cooling fluid may be a portion of the hydrocarbon gas line exiting a compressor at a high pressure, which is then cooled through expansion as described above in connection with the hydrocarbon storage tank application. This cooling gas is fed through the shell portion of the heat exchanger and may be returned to any low pressure system or the inlet (or low pressure side) of a compressor. Alternatively, if the compressor is already functioning at its intended capacity, the cooling gas leaving the heat exchanger may be compressed using a gas booster and then fed into the outlet line (or high pressure side) of the compressor or into the pipeline directly. No process gas (or cooling gas) is lost through its use as a cooling gas; all of the process gas is recovered. 
     The gas expansion cooling method may be used where a coolant is not readily available, but where a high pressure gas system is available. The method may be used in other applications, including, but not limited to, the cooling in rotating equipment lube oil systems, cooling in oil/liquid hydrocarbon cooler systems, or cooling in any hydrocarbon vapor emission systems. 
     The Clean Air Act requires that Maximum Achievable Controlled Technology (MACT) be at least 95% efficient in removing VOCs from vapor emission streams. Independent tests have shown that a similar method was more than 96% efficient at VOC removal using a cooling fluid having the same temperature as the cooling gas in this method. 
     The gas expansion cooling method may utilize the energy released by dropping the high pressure gas to a lower pressure gas. In this situation, the method has little to no operating cost. A return on investment may be achieved through the sale of recovered liquid hydrocarbons. The return volume will be determined by the API gravity (“American Petroleum Institute” gravity) of the hydrocarbon along with other factors. In a test model using small storage tanks, returns were between two and three barrels per day. In this situation, the return on investment was approximately $200-300 per day. 
     While preferred embodiments of the present invention have been described, it is to be understood that the embodiments are illustrative only and that the scope of the invention is to be accorded a full range of equivalents, many variations and modifications naturally occurring to those skilled in the art from a review hereof.