Patent Abstract:
The present invention provides for a natural gas well vapor processing system and method comprising recovering gaseous hydrocarbons to prevent their release into the atmosphere including providing a method for preventing the gaseous hydrocarbons from returning to a liquid state.

Full Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims the benefit of the filing of U.S. Provisional Patent Application Ser. No. 60/612,278, entitled “Vapor Process System”, filed on Sep. 22, 2004, and the specification of that application is incorporated herein by reference. 
    
    
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention (Technical Field) 
     The present invention relates to vapor processing systems for use with natural gas wells. The invention comprises a pumping system used with an engine instead of plunger lifts and can be used to remove evolved gases from hydrocarbon liquids to storage at or near atmospheric pressure. 
     2. Background Art 
     In addition to producing natural gas, many natural gas wells produce hydrocarbon liquids and water. The liquids, hydrocarbons and water, are separated from the flowing natural gas by a separator installed in the line carrying the flowing gas stream. The inline separator may operate at pressures as high as 1,500 psig or as low as 30 psig. The inline separator may separate the separated liquids into hydrocarbon and water components. The separated water is dumped to disposal, and the separated hydrocarbons are dumped to storage. The storage for the separated hydrocarbons is generally a steel tank or tanks with each tank having a capacity of 200 to 500 barrels. The storage tanks may operate at pressures as high as 16 ounces per square inch above atmospheric pressure to as low as atmospheric pressure. 
     An intermediate pressure separator is often used on natural gas wells that are operating at elevated pressures (150 to 1,500 psig). The intermediate pressure separator may operate at pressures of 125 to 25 psig. The intermediate pressure separator receives the total separated liquid from the inline separator. The intermediate pressure separator separates the liquid into its components, hydrocarbons and water. As described above, the water is dumped to disposal and the hydrocarbons are dumped to storage. As a result of the reduction of pressure, the intermediate pressure separator also releases most of the entrained natural gas from the separated hydrocarbons. Without a means to recover the entrained natural gas or a means designed to collect and burn the entrained natural gas, the entrained natural gas released in the intermediate pressure separator will be vented to the atmosphere and wasted. In most systems designed to collect and burn the entrained natural gas, the heat energy released by burning the natural gas is wasted to the atmosphere. A means is needed to prevent entrained natural gas from being released to the atmosphere. 
     Because of the reduction in pressure from the intermediate pressure separator to the storage tank, the liquid hydrocarbons dumped to the storage tanks will release additional entrained natural gas, and any component of the natural gas liquids that is not stable at the storage tank pressure and temperature will begin to evolve from the hydrocarbon liquids and change from a liquid to a gaseous state. The changing in the storage tank of hydrocarbon liquids from a liquid to a gaseous state is commonly referred to as “weathering”. Again, without a system to either recover or burn the gases released from the hydrocarbon liquids dumped to the storage tank, the gases will vent to the atmosphere and be wasted. The gases released from the storage tank are a high BTU value of approximately 3,000 BTU per cubic foot compared to the standard of 1,000 BTU per cubic foot required for residential gas. A means is needed to prevent gases released from liquid hydrocarbons from being released to the atmosphere. 
     For many years, systems have been made available to collect the gaseous hydrocarbons that are released from liquid hydrocarbons separated at elevated pressures and then transferred to storage tanks operating at near atmospheric pressure. In addition to operating problems that can occur with the currently available recovery systems, the biggest problem that has limited their application has been capital cost, and the systems have generally been applied to gas wells that have operated at pressures of 250 psig or less and that have produced volumes of hydrocarbon liquids in the range of 100 barrels per day or more. 
     Natural gas wells that can produce 100 barrels per day or more of hydrocarbon liquids do not generally require any type of artificial lift to lift the liquid hydrocarbons to the surface. In most cases, smaller volume natural gas wells do require artificial lift to lift the liquid hydrocarbons to the surface. A widely used artificial lift systems is called a “plunger lift”. The plunger is a metal device that falls to the bottom of the natural gas well tubing while the gas flow is shut off at the surface. The plunger remains at the bottom of the tubing for a period of time while the gas well builds up enough pressure to provide enough gas flow to bring to the surface the plunger and the load of liquid hydrocarbons the plunger is lifting. When the gas well is again opened, the plunger and liquid hydrocarbons rise to the surface. Often, the liquid hydrocarbons arrive at the surface as a slug that is much larger than the normal hydrocarbon liquid production of the well. The liquid hydrocarbon slug can create a volume of flash and evolved gases that will overload the vapor recovery system. 
     On natural gas wells where the plunger lift or other types of artificial lift creates a slugging condition that overloads the vapor recovery system, a pumping system developed by Unico, Inc. (“Unico”) can be used to lift the produced liquid hydrocarbons to the surface. Up until now, pumping of natural gas wells has been avoided because of pumping problems. Some of the problems with pumping gas wells have been gas locking (a condition where the pumping barrel fills with gas and no fluid can be pumped), gas interference (a condition where the pumping barrel only partially fills with fluid each stroke of the pump), and fluid pounding (a condition where the downward stroke of the pump contacts the fluid in a less than fluid filled barrel). The Unico pumping system presents a solution to the problems of pumping gas wells by only pumping the amount of fluids the well is producing. Pumping only the amount of fluids the well is producing prevents “pump-off” (a condition where the well bore is pumped dry thereby allowing gas to enter the pump barrel). A method is needed to eliminate gas entering the pump barrel to eliminate the problems associated with pumping natural gas wells. 
     BRIEF SUMMARY OF THE INVENTION 
     An embodiment of the present invention provides for a natural gas well vapor processing system and method comprising recovering gaseous hydrocarbons to prevent their release into the atmosphere including providing a method for preventing the gaseous hydrocarbons from returning to a liquid state. 
     In one embodiment of the present invention, evolved gases are entrained at the vacuum port of an eductor into a fluid stream and compressed. The fluid flowing through the eductor discharges into an emissions separator where the compressed gases separate from the fluid, and the compressed gases flow to the outlet of the emissions separator to be further processed while the fluid falls to the bottom of the emissions separator. The fluid collects in the bottom of the emissions separator to provide a continuous closed circuit fluid feed to the suction of a circulating pump. 
     The emissions separator also receives entrained gas that evolves from hydrocarbon liquids when the liquids are separated from a flowing gas stream at higher pressure and dumped to the lower pressure of an intermediate pressure separator. In the emissions separator, the two gases mix to form a homogeneous mixture. The homogeneous gas mixture flows from the outlet of the emissions separator to the suction of a gas compressor where the gases are compressed to the pressure of the flowing gas stream. The compressed gases are discharged back into the flowing gas stream at the inlet to the inline separator where the compressed gases mix with the flowing gas stream to form, in the inline separator, a second homogeneous gaseous mixture. The second homogeneous gas mixture flows from the outlet of the inline separator to other processing or to points of sale. 
     Another embodiment provides for mixing a high BTU and vapor pressure gas with a lower BTU and vapor pressure gas flowing in the pipeline to reduce the BTU and partial pressure of the compressed gas while at the same time slightly raising the BTU and partial pressure of the flowing gas stream. Lowering the BTU and partial pressure of the compressed gases reduces the tendency of the gases evolved and recovered from the tank to return to a liquid state. Any of the compressed gases that return back to a liquid state prior to passing out of the inline separator are again separated and dumped back to the storage tank. 
     Thus, an embodiment of the present invention provides a method for preventing the release of natural gas in a natural gas well processing system from entering the atmosphere comprising, collecting evolved gases from a storage tank, entraining the evolved gases into a fluid stream, compressing the evolved gases and fluid stream, sending the evolved gases and fluid stream to an emissions separator, and separating the gases from the fluid for further processing. Preferably, the evolved gases are collected using a vacuum, and preferably, the method further comprises providing an eductor to create the vacuum and to entrain the gasses into the liquid stream. The method preferably further comprises mixing a first compressed gas with a second compressed gas flowing in a pipeline, the second compressed gas having a BTU lower relative to the BTU of the first compressed gas to prevent gaseous hydrocarbons in the natural gas well processing system from entering a liquid state. 
     Another embodiment provides a method for preventing the release of gaseous hydrocarbons at a natural gas well processing system from entering the atmosphere, the method comprising providing an emissions separator, sending to the emissions separator the entrained gases that evolve form hydrocarbon liquids when the liquids are separated from a flowing gas stream at higher pressure and put in the lower pressure of an intermediate separator, sending the gaseous hydrocarbons to a compressor and compressing the gaseous hydrocarbons, and sending the compressed gaseous hydrocarbons to a flowing gas stream for further processing or point of sale. 
     Another embodiment provides a natural gas well processing system comprising a hydrocarbon storage tank, an eductor linked to the storage tank to receive gasses that evolve in the storage tank, entrain said gasses into a fluid stream, and compress the gasses and said fluid stream, and an emissions separator linked to the eductor for receiving the evolved gases and fluid stream for separation of the gasses from the fluid stream and for sending the gasses out of the emissions separator for further processing. 
     Other objects, advantages and novel features, and further scope of applicability of the present invention will be set forth in part in the detailed description to follow, taken in conjunction with the accompanying drawings, and in part will become apparent to those skilled in the art upon examination of the following, or may be learned by practice of the invention. The objects and advantages of the invention may be realized and attained by means of the instrumentalities and combinations pointed out in the appended claims. 
    
    
     
       BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS 
       The accompanying drawings, which are incorporated into and form a part of the specification, illustrate one or more embodiments of the present invention and, together with the description, serve to explain the principles of the invention. The drawings are only for the purpose of illustrating one or more preferred embodiments of the invention and are not to be construed as limiting the invention. In the drawings: 
         FIG. 1  is a flow diagram of an embodiment of the invention; and 
         FIG. 2  is a flow diagram of a modification of the embodiment of  FIG. 1 . 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     The present invention provides a pumping system to replace plunger lifts used on natural wells. For example, in one embodiment, the pumping system such as that disclosed and marketed by Unico, Inc. (“Unico”) (or other appropriate) pumping system can be used with an engine such as that provided by Marathon Engine Systems (or other appropriate engine) to replace plunger lifts on natural gas wells. Replacing the plunger lift increases a well&#39;s production time by eliminating the lost production time associated with shutting down the well to allow the plunger to fall to the bottom as well as eliminating the lost production time required for the well to build up enough pressure to cause the plunger to rise to the surface. Often, the lost production time is greater than a well&#39;s production time. Besides increasing a well&#39;s production time, the Unico pumping system further increases a well&#39;s production by lowering the pressure the producing formation is producing against. The fluids produced by the well are pumped up through the tubing, and the gas is produced out the casing, eliminating the pressure deferential between the casing and tubing required to produce both the fluids and gas up through the tubing. 
     An embodiment of the present invention provides an economical system for use on natural gas wells that produce a small volume of hydrocarbon liquids (5 to 50 barrels per day), although the present invention can also be used for larger volumes. The system collects and returns the gaseous hydrocarbons to a gas stream flowing at 250 psig or less, the gaseous hydrocarbons released as a result of separating liquid hydrocarbons from the flowing gas stream and transferring to, and storing in, tanks, at near or atmospheric pressure, the separated liquid hydrocarbons. 
     In an embodiment of the present invention, an engine generator set such as, for example, a 7.5 horsepower engine generator set (e.g. a generator set such as supplied by Marathon Engine Company), is used to provide the power to operate the gas recovery system. The engine generator set powers electric motors (for example, two electric motors). One electric motor powers a circulating pump to provide fluid energy to power an eductor that creates a vacuum to collect evolved gases from the storage tanks. The evolved gases are entrained at the vacuum port of the eductor into the fluid stream and compressed to a maximum of, for example, 30 psig. The fluid flowing through the eductor discharges into an emissions separator where the compressed gases separate from the fluid and the compressed gases flow to the outlet of the emissions separator to be further processed while the fluid falls to the bottom of the emissions separator. The fluid collects in the bottom of the emissions separator to provide a continuous closed circuit fluid feed to the suction of a circulating pump. 
     The emissions separator also receives entrained gas that evolves from hydrocarbon liquids when the liquids are separated from a flowing gas stream at higher pressure and dumped to the lower pressure of an intermediate pressure separator. On most installations, the intermediate pressure separator and the emissions separator operate at the same pressure (e.g. 30 psig or less), but on some installations it is desirable to use a back pressure to hold the intermediate pressure separator at a higher pressure than the operating pressure of the emissions separator. In the emissions separator, the two gases (one at, for example, approximately 3,000 BTU per cubic foot from the storage tanks and the other at, for example, approximately 2,000 BTU per cubic foot from the intermediate pressure separator) mix to form, for example, an approximately 2,500 BTU per cubic foot homogeneous mixture. The 2,500 BTU homogeneous gas mixture flows from the outlet of the emissions separator to the suction of a small capacity, conventional, reciprocating, gas compressor where the gases are compressed to the pressure of the flowing gas stream (e.g. 250 psig or less). The compressed gases are discharged back into the flowing gas stream at the inlet to the inline separator where the compressed gases mix with the flowing gas stream to form, in the inline separator, a second homogeneous gaseous mixture. The second homogeneous gas mixture flows from the outlet of the inline separator to other processing or to points of sale. 
     Mixing the relatively small volume of high BTU and vapor pressure gas (e.g., approximately 2,500 BTU per cubic foot compressed gas) with the larger volume of lower BTU and vapor pressure gas (e.g., approximately 1,000 BTU per cubic foot gas) flowing in the pipeline greatly reduces the BTU and partial pressure of the compressed gas while at the same time slightly raising the BTU and partial pressure of the flowing gas stream. Lowering the BTU and partial pressure of the compressed gases reduces the tendency of the gases evolved and recovered from the tank to return to a liquid state. Any of the compressed gases that return back to a liquid state prior to passing out of the inline separator are again separated and dumped back to the storage tank. The physical process of gases evolving from hydrocarbon liquids stored at low pressure, the gases being compressed to a higher pressure, then, after compression, the gases changing state from a gas back to a liquid, and, again, the liquid being dumped back to low pressure storage to begin evolving into a gas again, greatly increases the compressor horsepower required to recover evolved gases. The higher the flowing line pressure, the more gases that will be evolved when hydrocarbon liquids are separated from a flowing gas stream and then dumped from the higher pressure to a lower pressure Also, the higher the flowing line pressure, the greater is the tendency for the evolved gases from liquid hydrocarbons, dumped from a higher pressure to a lower pressure, to change from a gaseous state back to a liquid state when the gases are collected and compressed back to the higher pressure. 
     The tendency of hydrocarbon liquids to change state from liquids to gases and then back to liquid again can create what are commonly called “recycle loops”. At times, the recycle loops can become large enough to force the required compressor horsepower needed to recover the evolved gases to become infinite and a simple vapor recovery system cannot be used. The “Hero” system described in U.S. Pat. No. 4,579,565, was designed to address applications where simple vapor recovery was not practical. 
     Another object of the present invention is to provide a process that allows the use, with some modifications, of the previously described components of the simple vapor recovery system to collect the evolved gases from hydrocarbon liquids separated at pressures as high as, for example, 500 to 1,000 psig and then dumped to storage at, or near, atmospheric pressure. As previously described, without modifications to the process, the simple vapor recovery system can develop, at high flowing gas pressures, recycle loops that could cause the horsepower required by the recovery system to become infinite. 
     To decrease the tendency of gases evolved from hydrocarbon liquids separated at high pressure, dumped to storage at low pressure, collected at low pressure, and then, again, compressed back to high pressure to change state from a gas to a liquid, the previously described simple vapor recovery system is modified in the embodiment of the present invention described below. 
     In one embodiment, the collected volume of high BTU gas forming the suction volume of any stage of the reciprocating compressor is increased by as much as 5% to 10% by introducing lower BTU line gas from the inline separator into the volume of collected suction gas. Changing the partial pressure of the homogenous gas mixture, by introducing lower BTU line gas into the higher BTU suction gas, decreases the tendency of the higher BTU suction gas to change state from a gas to a liquid when the homogenous gas mixture is compressed and cooled. In another embodiment, the temperature between stages of compression of the homogenous gas mixture is controlled to maintain the suction temperature of each stage of compression at approximately 100 to 120 degrees Fahrenheit. Both embodiments can be combined in one system. 
     Turning now to the figures,  FIG. 1  is a flow diagram of the vapor system which accomplishes decreasing the tendency of the higher BTU suction gas to change state from a gas to a liquid. Referring to  FIG. 1 , line  3  comprises a flowing natural gas stream. The flowing natural gas stream in line  3  enters inline separator  1  at inlet  2 . While flowing through inline separator  1 , the free fluids, liquid hydrocarbons and water, are separated from the flowing natural gas. The flowing natural gas exits inline separator  1  at exit  5  and flows through line  4  to sales or other processing. 
     The free fluids fall to the bottom of inline separator  1  and are dumped through valve  6  (valve  6  is actuated by a liquid level control (not shown)) and flow through line  8  to enter intermediate pressure separator  10  at inlet  12 . The free fluids fall to the bottom of intermediate separator  10 . In the bottom of intermediate separator  10 , the free fluids are separated by a conventional weir system into the free fluids components, liquid hydrocarbons and water. The water is dumped by valve  14  (valve  14  is actuated by a liquid level control (not shown)) and flows through line  16  to disposal. The liquid hydrocarbons are dumped through valve  18  (valve  18  is actuated by a liquid level control (not shown)) and flow through line  20  to the inlet  22  of storage tank  24 . The changes to the liquids being dumped from intermediate separator  10  to storage tank  24  are described below. 
     The gas that flashes as a result of the liquid hydrocarbons being dumped from the higher pressure of inline separator  1  to the lower pressure of intermediate separator  10  form a first body of homogeneous gas mixture which comprises water vapor, portions of natural gas that were entrained in the liquid hydrocarbons, and components of the liquid hydrocarbons which have flashed and have changed state from a liquid to a gas. The first body of homogenous gas mixture exits intermediate pressure  10  at exit  26  and flows through line  28  to the inlet  30  of emissions separator  32 . The length of flow line  28  varies from location to location and in most cases, but not always, it is installed above ground. During winter, line  28  may be exposed to low ambient temperatures which could cool the first body of homogenous gas mixture flowing in line  28  to a temperature in which the gaseous liquid hydrocarbons and water vapor contained in the first body of homogenous gas mixture could begin to change state from a gas to a liquid. It is desirable that none of the gases contained in the first body of homogeneous gas mixture change state from a gas to a liquid. The presence of any free water in flow line  28  as a result of water vapor condensing from the first body of homogeneous gas mixture would pose a risk of ice forming in flow line  28  thus blocking the flow in line  28  of the first body of homogeneous gas mixture. 
     Several types of gas-to-gas heat exchangers can be used to provide heat to the first body of homogenous gas mixture flowing in line  28 . The gas-to-gas heat exchangers exchange the heat (e.g., between 225 and 300 degrees Fahrenheit) contained in the hot discharge gas flowing in line  36  with the first body of homogeneous gas mixture flowing in line  28  thus raising the temperature of the gas flowing in line  28 . 
     Both flow lines  28  and  36  may be field installed and connect the vapor processing system to the inlet of inline separator  1  and the outlet of intermediate separator  10  which are in close proximity to each other. One type of heat exchange that may be used is to field lay lines  28  and  36  so that they touch each other, and the two lines are may be insulated with heat resistant insulation. The heat of compression (e.g., 250 to 300 degrees Fahrenheit) from flow line  36  provides heat along the entire length of line  28  to substantially prevent some of the gases contained in the first body of homogenous gas mixture from changing state from a gas to a liquid, and the heat from flow line  36  prevents freezing of any water vapor that might condense in flow line  28 . 
     The first body of homogenous gas mixture flowing in line  28  enters emissions separator  32  at inlet  30 . Emissions separator  32  is approximately half full of ethylene glycol (other appropriate liquids or mixture of liquids can also be used). The purpose of the body of ethylene glycol contained in emissions separator  32  is described below. The first body of homogeneous gas mixture entering emissions separator  32  from intermediate pressure separator  10  mixes with the higher BTU fourth body of homogeneous gas mixture collected from the tanks and forms a second body of homogenous gas mixture (collection of the tank gases is described below). Any liquids that might condense from the collected second body of homogeneous gas mixture will separate from the gas and be dumped through motor valve  46  (motor valve  46  is controlled by a liquid level controller (not shown)) and flow line  48  into storage tank  24 . The collected second body of homogeneous gas mixture exits emissions separator  32  at outlet  38 . The collected second body of homogeneous gas mixture at approximately 27 psig flows through lines  41  and  40  to the suction  42  of reciprocating compressor  34 . Reciprocating compressor  34  compresses the collected gases up to a pressure range of, for example, approximately 125 to 250 psig. The discharge pressure of reciprocating compressor  34  is determined by the pressure of the flowing gas stream contained in inline separator  1 . From the discharge port  44  of reciprocating compressor  34 , the collected second body of homogeneous gas mixture flows through line  71  to point  72 . At point  72 , line  71  divides to form lines  74  and  36 . Line  74  terminates at pressure regulator  76 . Pressure regulator  76  is set at approximately 27 psig to maintain a near-to-constant suction pressure at suction port  42  of reciprocating compressor  34 . Compressor  34  is sized to compress more gas than the volume of gas entering line  40  from emissions separator  32 . Any time the suction pressure at suction port  42  drops below the set point of pressure regulator  76 , gas flows from pressure regulator  76  through line  78  to inlet  79  on emissions separator  32  to maintain a near-to-constant pressure at suction port  42 . From point  72 , the collected second body of homogeneous gas mixture flows through line  36  to point  142 . From point  142 , the second body of homogeneous gas mixture flows through line  3  to the inlet  2  of inline separator  1 . In inline separator  1 , the collected higher BTU second body of homogeneous gas mixture from line  36  mixes with the larger volume lower BTU gases flowing through inline separator  1  and forms a third body of homogeneous gas mixture. 
     Referring again to  FIG. 1 , and as previously described herein, the liquid hydrocarbons, from intermediate pressure separator  10  flow through motor valve  88  and line  20  and enter storage tank  24  at inlet  22 . The liquids from separator  10  flash to form a fourth body of homogenous gas mixture as a result of the pressure change from the pressure in intermediate separator  10  to the near or atmospheric pressure in storage tank  24 . In addition to the immediate flash, the liquid hydrocarbons contained in tank  24  continue to evolve gases as the liquid hydrocarbons attempt to reach equilibrium with the gases contained in tank  24 . The fourth body of homogenous gas mixture of flash and evolved gases exit storage tank  24  at outlet  50 . The fourth body of homogeneous gas mixture from storage tank  24  flows through lines  51 , back pressure regulator  53 , line  52 , line  55 , and line  57  to the vacuum inlet  54  of eductor  56 . 
     Eductor  56  is powered by ethylene glycol or other appropriate fluid that is pumped from emissions separator  32  by circulation pump  58 . The ethylene glycol exits emissions separator  32  at fluid outlet  60 . The ethylene glycol (at, for example, approximately 27 psig) flows through line  64  to suction inlet  62  of circulation pump  58 . Circulation pump  58  increases the pressure of the ethylene glycol to approximately 120 psig. The pressurized ethylene glycol exits circulation pump  58  at discharge port  66  and flows through line  68  to power port  61  of eductor  56 . While flowing through eductor  56 , the pressurized ethylene glycol powers eductor  56  to create a vacuum at vacuum port  54 . The vacuum generated by eductor  56  is controlled to a few inches of water column (e.g., 3 to 12 inches) by a vacuum controller such as, for example, a model 12 PDSC supplied by Kimray, Inc. Vacuum controller  82  is connected to line  52  at point  81 . Vacuum controller  82  outputs a throttling pressure signal to normally opened motor valve  88 . Normally opened motor valve  88  is installed at the termination of line  86 . Line  86  begins at point  84  at the end of line  41  and terminates at the inlet of normally opened motor valve  88 . Normally opened motor valve  88  is connected by line  90  to line  55  at point  92 . When the vacuum at point  81  exceeds the set point of vacuum controller  82 , vacuum controller  82  decreases the output pressure to normally open motor valve  88 . The decrease of output pressure to normally opened motor valve  88  causes normally opened motor valve  88  to partially open thereby increasing the flow of gas from emissions separator  32  through line  86 , motor valve  88 , and line  90  into line  55 . Increasing or decreasing the volume of gas flowing from emissions separator  32  to vacuum port  54  of eductor  56  maintains the desired vacuum in line  52 . 
     The fourth body of homogeneous gas mixture from storage tank  24  is drawn into eductor  56  through line  51 , back-pressure regulator  53 , line  52 , line  55 , and line  57  by the vacuum created by eductor  56 . To prevent air entering the system, back-pressure regulator  53  holds a positive pressure of approximately 8 ounces per square inch above atmospheric pressure on tank  24 . The collected fourth body of homogenous gas mixture is drawn into eductor  56  through vacuum port  54  and is entrained into the flowing ethylene glycol and compressed to a pressure of, for example, approximately 27 psig contained in emissions separator  32 . The ethylene glycol and the entrained and compressed fourth body of homogenous gas mixture exit eductor  56  at port  68  and flow through line  70  to inlet  72  of emissions separator  32 . In emissions separator  32 , as previously described, the collected fourth body of homogenous gas mixture from storage tank  24  mixes with the first body of homogenous gas mixture from intermediate pressure separator  10  and forms a second body of homogeneous gas mixture. The ethylene glycol separates from the entrained gases and falls toward the bottom of emissions separator  32 . The ethylene glycol discharged by eductor  56  joins the body of ethylene glycol contained in the approximate bottom two-thirds of emissions separator  32 . The ethylene glycol is continuously circulated in a closed loop by circulation pump  62  to provide power to eductor  56 . 
     Heat is generated by the pumping of the ethylene glycol as well as the compression of the collected gases. It is desirable to control the temperature of the ethylene glycol to, for example, between approximately 100 and 120 degrees Fahrenheit. Forced draft cooler  101  provides cooling for the ethylene glycol. Forced draft cooler  101  is connected to circulating pump  58  discharge line  68  at point  94 . Line  96 , hand valve  98 , line  97 , thermostatically controlled mixing valve  102 , and line  100  connect inlet  99  of forced draft cooler  101  to point  94 . Outlet  103  of forced draft cooler  101  is connected by line  105  and line  104  to emissions separator  32  at point  106 . 
     A side stream of ethylene glycol under pressure from circulating pump  58  flows through forced draft cooler  101  and returns to emissions separator  32  thus cooling the ethylene glycol. The volume of ethylene glycol (e.g., 3 to 6 gallons per minute) flowing in the side stream is controlled by adjusting hand valve  98 . To maintain the desired temperature of the ethylene glycol of between 100 and 120 degrees Fahrenheit, thermostatically controlled mixing valve  102  can bypass through line  107  a part of, or the entire side stream of, ethylene glycol. Whenever the ethylene glycol becomes too cold, thermostatically controlled mixing valve  102  reduces the volume of the side stream flowing through forced draft cooler  101 . 
       FIG. 2  is a flow diagram of the embodiment wherein the temperature between stages of compression of the homogenous gas mixture is controlled to maintain the suction temperature of each stage of compression. As noted above, the embodiment shown in  FIG. 2  is intended for applications where the flowing gas pressure is elevated to pressures above, for example, 250 psig and where the changing of liquid hydrocarbon vapors back from a gas to a liquid state creates recycle loops. 
     All of the components described in  FIG. 1  are incorporated into  FIG. 2  and only the components of  FIG. 1  required to explain the modifications shown in  FIG. 2  are described detail below. 
     As shown in  FIG. 2 , a third stage of compressor  110  is added to receive the discharge gas from second stage compressor  34 . The hot (e.g., 225 to 300 degrees Fahrenheit), compressed, and collected second body of homogeneous gas mixture exits compressor  34  at discharge port  44  and flows to point  72 . From point  72 , the hot, compressed, and collected second body of homogeneous gas mixture flows through line  36  to point  112  where a side stream of sales gas from inline separator  1  enters line  36  and mixes with the hot, compressed, collected second body of homogenous gas mixture forming a fifth body of homogeneous gas mixture. The volume of gas from inline separator  1  that enters line  36  at point  112  increases the total volume of gas passing through point  112  by approximately 5% to 10%. The side stream of gas flows from inline separator  1  through line  4  to point  114 . From point  114 , the side stream of gas flows through line  116 , flow meter  118 , line  120 , flow control valve  122 , and line  124  to point  112 . Flow control valve  122  is controlled by a PLC or other flow control device (not shown) to allow the required volume of side stream gas from inline separator  1  to increase the volume of gas flowing through point  112  by, for example, approximately 5% to 10%. 
     As described above, mixing a lower BTU and vapor pressure gas with a higher BTU and vapor pressure gas reduces the tendency of some of the components of the higher BTU gas to change state from a gas to a liquid thereby reducing the chance of recycle loops forming. 
     From point  112 , the fifth body of hot homogeneous gas mixture flows through line  127  to inlet  128  of forced draft cooler  133 . While flowing through forced draft cooler  133  the gases are cooled to an approximately 20 degrees Fahrenheit approach to ambient temperature. The cooled gases exit forced draft cooler  133  at outlet  130  and flow through line  132  to cool gas inlet port  125  of thermostatic bypass valve  126 . Thermostatic bypass valve  126  monitors the temperature of the gas flowing out of outlet  129  into line  134 . When the gas temperature exiting outlet port  129  of thermostatic bypass valve  126  drops to approximately 120 degrees Fahrenheit, thermostatic bypass valve  126  begins to bypass some of the hot gas around cooler  133 . The hot gas flows from point  135  through bypass line  131  to hot gas inlet port  139  of thermostatic bypass valve  126 . The hot gas from hot gas inlet port  139  mixes in thermostatic bypass valve  126  with the cooled gas from cool gas inlet port  125  thereby maintaining the gas temperature in line  134  at approximately 120 degrees Fahrenheit. Keeping the gas in line  134  at approximately 120 degrees Fahrenheit prevents most of the liquid hydrocarbon condensation that might occur at a cooler temperature in line  134  or separator  146 . 
     The approximately 120 degrees Fahrenheit temperature fifth body of homogeneous gas mixture enters separator  146  at inlet  148 . Separator  146  removes any liquids that may have resulted from a phase change from a gas to liquid after the fifth body of homogenous gas mixture is compressed and cooled. The liquids separated in separator  146  are dumped by motor valve  150  (motor valve  150  is actuated by a liquid level controller not shown) through lines  152  and  154  into intermediate pressure separator  10 . As described above, some of the gases and liquids contained in the liquid from separator  146  will flash. The balance of the liquids from separator  146  will drop to the bottom of intermediate pressure separator  10  and mix with the liquids from inline separator  1 . The overall operation of intermediate separator  10  has been described above. 
     The fifth body of homogenous gas mixture in separator  146  exits at outlet  156  of separator  146  and flows through line  158  to enter third stage compressor  110  at suction port  136 . Third stage compressor  110  compresses the fifth body of homogenous gas mixture to the pressure of the flowing gas stream. From discharge port  139  of third stage compressor  110 , the gas flows through line  140  (as previously described, line  140  is installed to be in heat exchange relationship with line  28  from intermediate pressure separator  10 ) to point  142 . At point  142 , the fifth body of homogenous gas mixture enters line  3  and mixes with the flowing gas stream to form, in inline separator  1 , the previously described third body of homogeneous gas mixture. The function of inline separator  1 , as well as the function of the rest of the process, has been described above. 
     The embodiments described herein have been shown utilizing only three stages of compression (the eductor and two stages of compression). However, it should be understood that other embodiments of the present invention can incorporate more than three stages of compression. Also, it should be understood that mixing gases of different BTU&#39;s in relation to each other (i.e., a lower BTU gas with a higher BTU gas such as a lower molecular gas such as methane with a higher molecular weight gas such as butane) can be done between any stage of compression (or at any point in the system). Thus, such a mixing of gases can be performed between the first and second stages and/or between the second and third stages of compression shown in  FIG. 2 . 
     There is the potential in cold climates of gas hydrates forming in volume control valve  122  and motor valve  150  (hydrates are an ice-like substance that can form from natural gas when the proper temperature, pressure, and water content are present). Where needed, the potential of hydrates forming in the system can be eliminated by installing a gas-to-gas heat exchanger upstream of volume control valve  122  and a gas-to-liquid heat exchanger upstream of motor valve  150 . The hot gas for both exchangers can be the hot discharge gas from compressor  34 . 
     The preceding examples can be repeated with similar success by substituting the generically or specifically described compositions, biomaterials, devices and/or operating conditions of this invention for those used in the preceding examples. 
     Although the invention has been described in detail with particular reference to these preferred embodiments, other embodiments can achieve the same results. Variations and modifications of the present invention will be obvious to those skilled in the art and it is intended to cover all such modifications and equivalents. The entire disclosures of all references, applications, patents, and publications cited above, and of the corresponding application(s), are hereby incorporated by reference.

Technology Classification (CPC): 2