Patent Abstract:
A slug-containing vapor recovery system wherein pressure and/or fluid level sensors are provided which monitor for conditions caused by the entry of a slug of hydrocarbon liquid, including that caused by a plunger-lift system. The system can be configured to accommodate virtually any anticipated slug-events.

Full Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims priority to and the benefit of the filing of U.S. Provisional Patent Application Ser. No. 61/388,468, entitled “High Efficiency Slug Containing Vapor Recovery”, filed on Sep. 30, 2010, and the specification thereof is incorporated herein by reference. 
     BACKGROUND OF THE INVENTION 
     Field of the Invention 
     Technical Field 
     Embodiments of the present invention provide a vapor recovery system for a hydrocarbon well. Particularly, embodiments of the present invention a vapor recovery system which is capable of handling large slugs of liquids without inducing large recycle loops thereby permitting the use of a relatively small compressor 
     BRIEF SUMMARY OF EMBODIMENTS OF THE PRESENT INVENTION 
     An embodiment of the present invention relates to a slug-containing vapor recovery system having a first flow of hydrocarbon vapors in fluid communication with a first pressure sensor, the hydrocarbon vapors traveling to an inlet scrubber; allowing a flow of liquid hydrocarbons to flow from a flash separator and be heated into a vapor before joining the first flow of hydrocarbon vapors; and reducing the flow of liquid hydrocarbons from the flash separator when the first pressure sensor senses a pressure in excess of a predetermined amount. Optionally, reducing the flow of liquid hydrocarbons can include stopping the flow of liquid hydrocarbons from the flash separator. Heating the flow of liquid hydrocarbons into a vapor can include heating the flow of liquid hydrocarbons with a heat exchanger. 
     In one embodiment, the heat exchanger is disposed within a two-phase stabilizing reboiler, and the stabilizing reboiler can be heated by a firetube. The system can also include providing a two-phase, slug-containing flash separator, which itself can have a gas expansion vessel communicably coupled to it. The gas expansion vessel can be in fluid communication with a well-stream inlet separator. The gas expansion vessel can allow the pressure of contents therein to increase due to the arrival of a slug of liquid hydrocarbons. 
     An embodiment of the present invention also relates to a slug-containing vapor recovery system having a gas expansion vessel communicably coupled to receive an incoming flow of hydrocarbons from a well-stream inlet, a two-phase, slug-containing flash separator in fluid communication with the gas expansion vessel, a first pressure sensor sensing a pressure of contents of the gas expansion vessel, and operating a compressor which compresses hydrocarbon vapors, the compressor operating at a first speed when pressure sensed by the first pressure sensor is less than a first predetermined amount and the compressor operating at a second speed when pressure sensed by the first pressure sensor is greater than the first predetermined amount, the first speed being less than the second speed. 
     The system can divert the incoming flow of hydrocarbons to bypass at least a portion of the system when the first pressure sensor senses a pressure which is greater than a second predetermined amount. The system can optionally divert the incoming flow of hydrocarbons such that they travel from the existing well-stream inlet separator into a hydrocarbon storage tank. 
     Optionally, the system can also include: providing a second pressure sensor in fluid communication with a first flow of hydrocarbon vapors traveling to an inlet scrubber; allowing a flow of liquid hydrocarbons to flow from a flash separator and be heated into a vapor before joining the first flow of hydrocarbon vapors; and/or reducing the flow of liquid hydrocarbons from the flash separator when the first pressure sensor senses a pressure in excess of a predetermined amount. The gas expansion vessel can include a liquid level switch. The incoming flow of hydrocarbons can be diverted around at least a portion of the system in response to the detection of a liquid by the liquid level switch. Optionally, the incoming flow of hydrocarbons can be diverted around at least a portion of the system for a predetermined amount of time, which can optionally include diverting the incoming flow of hydrocarbons into a hydrocarbon storage tank, which itself can optionally have a volume of at least 200 barrels. 
     An embodiment of the present invention also relates to a slug-containing vapor recovery apparatus having a first hydrocarbon vapors passageway, the passageway in fluid communication with a first pressure sensor, the first hydrocarbon vapors passageway communicable with an inlet scrubber, a liquid hydrocarbon vaporizing heater, the vaporizing heater communicably coupled to a condensate outlet of a flash separator and the vaporizing heater communicably coupled to the first hydrocarbon vapors passageway, and an apparatus capable of reducing a flow of liquid hydrocarbons from the flash separator when the first pressure sensor senses a pressure in excess of a first predetermined amount. 
     Optionally, a diverting valve can be activated in response to the first pressure sensor sensing a pressure which is in excess of a second predetermined amount. In one embodiment, the diverting valve can be communicably coupleable to an outlet of a hydrocarbon producing well and to an inlet of a hydrocarbon storage tank. 
     An embodiment of the present invention also relates to a slug-containing vapor recovery apparatus having a gas expansion vessel communicably coupleable to an outlet of a hydrocarbon-producing well, a two-phase slug-containing flash separator in fluid communication with the gas expansion vessel, a first pressure sensor, the first pressure sensor positioned to sense a pressure of contents of the gas expansion vessel, and an at least two speed compressor, the compressor communicably coupled to an outlet of a first stage inlet scrubber, the compressor selectively speed controlled based on an output of the first pressure sensor. The compressor can be caused to operate at a speed which is faster when the pressure sensor detects a pressure that is in excess of a predetermined amount, as compared with the speed of the compressor when the sensor detects a pressure that is below the predetermined amount. Optionally, the apparatus can also include a liquid level switch positioned to detect a liquid level within the gas expansion vessel. 
     In one embodiment, a diverting valve can be activated in response to a sensed liquid level by the liquid level switch. The diverting valve can be communicably coupleable to an outlet of a hydrocarbon producing well and to an inlet of a hydrocarbon storage tank. 
     An embodiment of the present invention also relates to a slug-containing vapor recovery apparatus having a compressor, a reboiler, and a gas expansion vessel, the gas expansion vessel allowing the pressure of a hydrocarbon gas to increase upon receipt of an incoming hydrocarbon slug, thereby increasing a gas storage capacity of the gas expansion vessel, the vapor recovery apparatus configured such that if the pressure of the gas in the gas expansion vessel reaches a predetermined set point a pressure control process of the vapor recovery apparatus causes the dumping of liquid hydrocarbons into the reboiler to cease, thus allowing the additional capacity of the compressor to be applied to reducing the pressure of the gas in the gas expansion vessel. 
     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 particularly 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: 
         FIGS. 1A-D  (hereinafter referred to as “FIG.  1 ”) illustrate a schematic diagram of an embodiment of the present invention in use with a 2-stage compressor; and 
         FIGS. 2A-D  (hereinafter referred to as “FIG.  2 ”) illustrate a schematic diagram of an embodiment of the present invention in use with a 3-stage compressor. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     An embodiment of the present invention relates to a high efficiency slug containing vapor recovery system. Referring now to  FIG. 1 , a flow diagram for a two-stage compressor embodiment of the present invention is illustrated. The system of the present invention can optionally be powered by an internal combustion engine an electric motor, other power means or a combination thereof. Although the components of the present invention can be selected so as to handle virtually any pressure, in one embodiment, the system is constructed to handle a maximum discharge pressure of about 400 psig. For applications requiring higher discharge pressures, a compressor with three or more stages can be used and will produce desirable results. Because of higher discharge pressures, the amount of heat generated by three stages or more of compression will be greater than the amount of heat generated by a two stages of compression. On some high pressure applications, atmospheric cooling can optionally be used to cool parts of the process, particularly those which generate very high temperatures. For embodiments of the present invention which are used with several stages of compression, additional compression temperature control is preferably provided for each additional stage of compression. 
     As illustrated in  FIG. 1 , flash separator vessel  1 , is a two phase slug containing flash separator which performs the functions of a flash separator and a liquid slug containment vessel. In one embodiment, vessel  1  can have a maximum working pressure of about 175 to about 250 psig. Vessel  1  preferably retains enough liquids to at least partially, and most preferably fully immerse cooling coil  2 . While desirable results can be provided when vessel  1  is a two-phase slug containing flash separator, desirable results can also be produced when vessel  1  is configured as a three-phase slug containing flash separator. Reboiler  3  can be selected to have a maximum working pressure for any given site-location requirements, but in one embodiment, reboiler  3  preferably has a maximum working pressure of about 75 to about 125 psig. Firetube  4  is preferably immersed in the condensates in reboiler  3 . In one embodiment, reboiler  3  preferably heats, under about 35 psig pressure, liquid condensates to a temperature of about 200 to 250 degrees Fahrenheit. Stabilizing column  5  is preferably mounted on top of and in communication with reboiler  3 . Stabilizing column  5  can be filled with pall rings  6  or other types of packing. Stabilizing column  5  preferably performs two functions. First, it aids in stripping high vapor pressure components such as propane, butane, etc., from the condensate. As the condensate falls through the packing, it is heated by the rising heated vapors from reboiler  3 . Heating of the condensate preferably causes some of the high vapor components of the condensate to flash into the vapor phase. Second, stabilizing column  5  preferably aids in refluxing back into the liquid phase some of the lower vapor pressure components of the heated vapors from reboiler  3 . As the heated vapors from reboiler  3  rise through the cooler condensate, the heated vapors are cooled while forming gas bubbles within the condensate. Cooling and intimate contact of the heated vapors with the condensate causes some of the lower vapor pressure components of the heated vapors to return to the liquid phase. 
     While flowing through heat exchanger  7 , the cool condensate from vessel  1  is preferably heated and the hot condensate from reboiler  3  is preferably simultaneously cooled. Heating coil  8  is preferably immersed in the hot liquids contained in reboiler  3 . Inlet suction scrubber  9  preferably collects and dumps, through dump valve  27  to liquid hydrocarbon storage tank  26 , any liquid that might condense from the collected vapors so that only hydrocarbon vapors are introduced into the compressor. In one embodiment liquid hydrocarbon storage tank  26  preferably has a capacity of at least about 10 barrels, more preferably a capacity of at least about 200 barrels, and most preferably a capacity of at least about 400 barrels. 
     First and second stages  10  and  11  are two stages of a two-stage compressor. Interstage scrubber  12  is preferably located between an outlet of compression stage  10  and an inlet of compression stage  11 . Various functions of the system of the present invention are preferably controlled, at least in part via PCL (process logic controller)  13 . Condensates separated from the well stream by the high pressure separator or separators enter gas expansion vessel  15  at inlet  16 . Since flash separator  1  and gas expansion vessel  15  are preferably at a lower pressure than the entering well stream, some entrained gas as well as some vapors will flash from the condensate. In one embodiment, back pressure valve  17  is set to hold an operating pressure of about 50 psig on gas expansion vessel  15  and flash separator  1 . In one embodiment, back pressure valve  24  is set to hold a pressure that is about 20 psig less than the lowest operating pressure of the high pressure separators (not shown); or else, back pressure regulator  24  is set slightly below the maximum working pressure of flash separator  1  and gas expansion vessel  15 . 
     Referring to first stage of compression  10 ,  28  is a flow line that connects gas discharge port  29  of first stage compression  10  to point  30 . At point  30 , line  28  splits into lines  31  and  32 . Line  31  connects to cooling coil  2 . Line  32  connects to by-pass port  33  of temperature control valve  34 . Outlet  35  of cooling coil  2  preferably connects to cooled gas port  36  of temperature control valve  34 . Line  37  connects outlet port  38  of temperature control valve  34  to inlet port  39  of interstage scrubber  12 . 
     In one embodiment, line  128  connects outlet port  129  of interstage scrubber  12  to suction port  40  of second compression stage  11 . Line  41  preferably connects discharge port  45  of second compression stage  11  to point  42 . Point  42  splits into two lines  43  and  44 . Line  44  carries the collected hydrocarbon vapors to the sales meter/sales  210 . Line  43  connects to inlet port  46  of gas recycle pressure control valve  47 . 
     Line  48  connects discharge  49  of recycle valve  47  to point  50 . Point  50  splits into lines  51  and  68 . Line  51  carries the collected vapors, as well as any recycled vapors required for operation of the compressor, to suction port  52  of first stage of compression  10 . 
     Referring to gas expansion vessel  15 , line  94  connects from outlet port  95  of gas expansion vessel  15  to inlet port  96  of back pressure valve  24 . Line  98  connects from outlet port  97  of back pressure valve  24  to point  93 . Point  93  splits into two lines  92  and  99 . Line  105  connects to vapor outlet port  106  of expansion vessel  15  to inlet port  130  of back pressure valve  17 . Line  108  connects from outlet port  109  of back pressure valve  17  to inlet port  110  of pressure control valve  22 . Line  132  connects pressure transducer  131  to PLC  13 . Line  134  connects electric liquid level control  133  to PLC  13 . 
     Referring to flash separator  1  and reboiler  3 , line  69  connects condensate outlet port  68  of flash separator  1  to inlet port  70  of condensate dump valve  23 . Line  72  connects from condensate dump valve outlet port  71  to point  73 . Point  73  splits into two lines  74  and  119 . Line  74  connects from point  73  to cool condensate inlet port  75  of condensate to condensate heat exchanger  7 . Line  76  connects from heated outlet port  77  of condensate to condensate heat exchanger  7  to condensate inlet port  78  of stabilizing column  5 . Line  79  connects from vapor outlet port  80  of stabilizing column  5  to inlet port  81  of back pressure valve  25 . In one embodiment, back pressure valve  25  is set to hold a pressure of about 35 to 45 psig on reboiler  3 . Line  83  connects from outlet port  82  of back pressure valve  25  to point  55 . Point  55  splits into lines  53  and  56 . Line  53  connects outlet port  54  of pressure control valve  22  to point  55 . Line  56  connects point  55  to point  57 . Point  57  splits into two lines  60  and  59 . Line  60  connects point  57  to the inlet  58  of heating coil  8 . Line  59  connects point  57  to bypass port  61  of temperature control valve  62 . Line  64  connects outlet port  63  of heating coil  8  to hot gas port  65  of temperature control valve  62 . Line  20  connects outlet port  66  of temperature control valve  62  to inlet port  67  of inlet scrubber  9 . Line  68  connects vapor outlet port  69  of inlet scrubber  9  to point  50 . Point  50  splits into lines  48  and  51 . Line  48  connects outlet port  49  of recycle valve  47  to point  50 . Line  51  connects point  50  to suction port  52  of first stage of compression  10 . 
     Reboiler  3  is preferably adjusted via condensate liquid level control  103 . Line  104  is a tubing line that sends a pressure signal from liquid level control  103  to liquid dump valve  90 . Line  84  connects from hot condensate outlet port  85  of reboiler  3  to hot liquid inlet port  86  of condensate to condensate heat exchanger  7 . Line  87  connects from cooled condensate outlet port  88  of condensate to condensate heat exchanger  7  to inlet port  89  of cooled condensate dump valve  90 . Line  92  connects from outlet port  91  of cooled condensate dump valve  90  to point  93 . At point  93  the lines split to form lines  98  and  99 . Line  99  connects from point  93  to point  100 . At point  100  the line splits to form lines  101  and  113 . Line  101  connects from point  100  to inlet  102  of storage tank  26 . Line  113  connects from outlet port  114  of dump valve  27  to point  100 . 
     Inlet scrubber  9  is preferably adjusted via liquid level control  111 . Line  112  is preferably formed from tubing and carries a pneumatic signal to dump valve  27 . Line  113  connects from outlet port  114  of dump valve  27  to point  100 . Electrical line  116  transmits an electrical signal from transducer  115  to PLC  13 . 
     Interstage scrubber  12  is preferably adjusted with liquid level control  117 . Line  119  connects outlet port  120  of dump valve  118  to point  73 . Tubing line  121  carries a pneumatic control signal from liquid level control  117  to dump valve  118 . 
     As used throughout this application, a reference to “normal operation” is intended to mean that the present invention is operating within the normal design capacity without the influence of a large slug of produced liquids and/or liquids and gases; whereas “abnormal” or “upset conditions” means that the present invention is operating under the influence of a slug of produced liquids and/or liquids and gases, which could exceed the capacity of the present invention, particularly the reboiler and compressor. Such abnormal conditions can be caused by arrival of a slug into flash separator  1  and gas expansion vessel  15 . 
     In embodiments of the present invention wherein three stages of compression are required for a particular application, the preceding description is equally applicable in conjunction with the following discussion regarding this additional third stage. Referring to  FIG. 2 , liquids collected in inner-stage scrubber  167  are dumped by liquid level control  170  and dump valve  172  through line  197  to point  73 . At point  188 , the liquids from inner-stage scrubbers  12  and  167  flow through common line  119  to point  73 . Additional stages of compression, such as four or five stages of compression can optionally be used in accordance with the teachings of the present invention simply by duplicating the configuration of this third stage of compression. 
     Handling of Liquids Under Normal Operation 
     Condensates from the high pressure separator or separators enter gas expansion vessel  15  at point  16 . The condensates flow downward into flash separator  1  and the gas and vapors collect in the top of gas expansion vessel  15 . As previously described, flash separator  1  is designed to maintain a hydrocarbon liquid level that is most preferably above cooling coil  2 . Any volume of liquid hydrocarbons in excess of that required to maintain the minimum liquid level in separator  1  is sensed by liquid level control  21  and dumped to stabilizing column  5 . While being dumped to stabilizing column  5 , the condensates are heated by heat exchanger  7 . The heated condensates pass downward through the packing  6  in stabilizing column  5  and mix with the heated condensate already in reboiler  3 . The condensates entering reboiler  3  are heated by firetube  4  to a high enough temperature to vaporize the volatile components such as butane, propane, etc which were previously condensed into liquid form. Any other suitable source of heat such as hot oil, electric heaters, and/or captured waste heat may be used in place of firetube  4 . 
     The level of condensates in reboiler  3  are preferably maintained by liquid level control  103 . When liquid level control  103  senses an increase in condensate level in reboiler  3 , it activates through tubing line  104  and dump valve  90  to dump the stabilized condensate to storage tank  26 . While being dumped to storage tank  26  the hot stabilized condensate is cooled in heat exchanger  7  by the cool condensate from flash separator  1 . 
     Handling of Liquids Under Abnormal Operation. 
     As previously described, in some instances, the condensates entering flash separator  1  and gas expansion vessel  15  can arrive suddenly in the form of a large slug of produced liquids and/or liquids and gases. The increased volume of condensates increases the volume of flashed gases and hydrocarbon vapors being released in flash separator  1 , gas expansion vessel  15 , and reboiler  3 . The increased volume of flash gases causes the pressure in line  20 , which carries the flash gases to inlet scrubber  9 , to increase. During slugging conditions the condensate level in flash separator  1  is above the operating level of throttling liquid level control  21 , causing liquid level control  21  to begin completely opening dump valve  23 . Increased opening of dump valve  23  increases the flow of condensates to reboiler  3 , thereby causing an overload of condensate and vapors in reboiler  3 . 
     Pressure controller  18  monitors through sensing line  19  the pressure in line  20 . Tubing line  203  carries the pressure signal from pressure controller  18  to pressure control valve  22  and liquid Level control  21 . When solenoid  136  is not activated, tubing line  204  carries a pneumatic signal from liquid level control  21  to dump valve  23 . Pressure controller  18  controls the supply pressure going to liquid level controller  21  and pressure control valve  22 . In one embodiment, pressure controller  18  is set to maintain a predetermined set pressure, which can optionally be about 40 psig on line  20 . As long as the pressure in line  20  is at or below the set pressure, pressure controller  18  allows full supply pressure to flow to both pressure control valve  22  and liquid level controller  21 . Full supply pressure holds pressure control valve  22  completely open and allows liquid level controller  21  to operate normally to dump through dump valve  23  the condensate from flash separator  1  to reboiler  3 . Whenever the pressure in line  20  begins to rise above the predetermined set pressure, pressure controller  18  begins reducing the supply pressure going to pressure control valve  22  and liquid level controller  21 . Reduction of the supply pressure causes pressure control valve  22  and dump valve  23  to begin closing. Closing pressure control valve  22  reduces the flow of gas and vapors from gas expansion vessel  15 . Closing dump valve  23  reduces the volume of condensate being dumped from vessel  1  to reboiler  3 . 
     As previously described, in one embodiment, back pressure valve  17  is set to maintain a pressure of about 50 psig on flash separator  1  and gas expansion vessel  15 , and back pressure valve  24  is set to hold a pressure that is about 20 psig less than the lowest operating pressure of the high pressure separators (not shown). Alternatively, back pressure regulator  24  can be set slightly below the maximum allowable working pressure of flash separator  1  and gas expansion vessel  15 . Flash separator  1  and gas expansion vessel  15  are preferably sized with excess capacity to hold the largest liquid slug that are expected to be produced. Electric liquid level control  133  is preferably installed at a level in gas expansion vessel  15  that is above any liquid level that gas expansion vessel  15  is expected to handle. Pressure transducer  131 , located in the top of gas expansion vessel  15 , is set to send an electrical signal through line  132  to PLC  13  anytime the pressure in gas expansion vessel  15  increases to within about 10 psig of the set pressure of back pressure valve  24 . When PLC  13  receives an electric signal from pressure transducer  131 , PLC  13  sends an electric signal through line  135  to activate solenoid  136 . Activating solenoid  136  causes the pneumatic signal from liquid level control  21  going to dump valve  23  to be vented. Closing dump valve  23  stops condensate from being dumped from flash separator  1  to reboiler  3 , thereby reducing the amount of vapors flowing from reboiler  3  and allowing the full capacity of the compressor to be used to rapidly reduce the pressure in flash separator  1  and gas expansion vessel  15 . As soon as the pressure in flash separator  1  and gas expansion vessel  15  has been reduced about 20 to about 25 pounds per square inch gauge below the set pressure of back pressure valve  24 , PLC  13  opens solenoid  136  re-establishing the connection between liquid level control  21  and dump valve  23 . Re-establishing the connection between liquid level control  21  and dump valve  23 , returns the unit to operation where pressure controller  18  is controlling the opening of pressure control valve  22  and dump valve  23 . After a period of time, the gases and liquids created by the slugging condition are processed and the unit thus returns to normal operation. 
     Handling of Gases and Vapors Under Normal Operation 
     Referring to  FIG. 1 , as previously described, the relative cool flash gases and vapors flow from flash separator  1  through line  53  to point  55 . At point  55  the flash gases and vapors from flash separator  1  are combined with the hot vapors stripped from the condensate by the heat of reboiler  3  and the stripping action of stabilizing column  5 . The operating pressure of reboiler  3  and stabilizing column  5  is maintained at about 35 psig by back pressure valve  25 . From point  55  the combined gas and vapor stream flows through line  56  to point  57 . At point  57  the combined gas and vapor stream can split into two streams with one portion of the combined gas and vapor stream flowing through line  59  to cool port  61  of temperature control valve  62  and the other portion flowing through line  60  and heating coil  8  to hot port  65  of temperature control valve  62 . Temperature control valve  62  is controlled by thermostat  150  which is mounted in discharge line  28 . Line  28  is the hot discharge line from first stage compression cylinder  10 . Thermostat  150  is set to control temperature control valve  62  to mix the cool and hot portions of the combined gas and vapor stream to obtain a temperature in inlet scrubber  9  high enough to be above the hydrocarbon dew-point of the combined gas and vapor stream and low enough to maintain the temperature of first stage of compression  10  below approximately 300 degrees Fahrenheit. From the common port  66  of temperature control valve  62 , the temperature controlled combined gas and vapor stream flows through line  20  to inlet scrubber  9 . Inlet scrubber  9  separates any hydrocarbon liquids that might be in the combined gas and vapor stream. The liquid level in inlet scrubber  9  is maintained by liquid level control  111  and dump valve  27 . Liquid hydrocarbons separated by inlet scrubber  9  are dumped through dump valve  27 , line  113 , and line  101  into hydrocarbon storage tank  26 . The liquid free combined gas and vapor stream exits inlet scrubber  9  at point  69  and flows through lines  68  and  51  into suction port  52  of first stage of compression  10 . The combined gas and vapor stream exits first compression stage  10  at a temperature in excess of the hydrocarbon dew-point of the combined gas and vapor stream and at an intermediate pressure of about 100 psig. The pressurized and heated combined gas and vapor stream flows through line  28  to point  30 . At point  30  the pressurized and heated combined gas and vapor stream can split into two streams with one portion of the combined gas and vapor stream flowing through line  32  to the hot port  33  of splitter valve  34  and the other portion flowing through line  31  and cooling coil  2  to the cool port  36  of temperature control valve  34 . The condensates in flash separator  1  serve as a heat sink to cool the hot vapors flowing through cooling coil  2 . Temperature control valve  34  is controlled by thermostat  151  which is set to maintain a discharge temperature from second stage of compression  11  that is above the hydrocarbon dew-point of the combined gas and vapor stream but less than 300 degrees Fahrenheit. As further illustrated in  FIG. 1 , thermostat  151  is mounted in line  44 . Line  44  is the hot discharge line from second stage of compression  11 . From the common port  38  of splitter valve  34  the temperature controlled combined gas and vapor stream flows through line  37  to the inlet port  39  of interstage scrubber  12 . Interstage scrubber  12  separates hydrocarbon liquids that are in the cooled, pressurized, combined gas and vapor stream from first stage compression  10 . The liquid level in interstage scrubber  12  is maintained by liquid level control  117  and dump valve  118 . Liquid hydrocarbons separated by interstage scrubber  12  are dumped through dump valve  118  and line  119  to point  73 . At point  73 , liquid hydrocarbons from interstage scrubber  12  are combined in line  72  with the condensates from flash separator  1  and flow to heat exchanger  7 . The liquid free combined gas and vapor stream exits interstage scrubber  12  at discharge port  129  and flows through line  128  into the suction port  40  of the second stage of compression  11 . The combined gas and vapor stream exits second stage of compression  11  through discharge port  45  at a temperature that is preferably in excess of the hydrocarbon dew point but less than about 300 degrees Fahrenheit and a discharge pressure that is preferably about 200 to about 500 psig. The pressurized and heated combined gas and vapor stream flows through line  41  to point  42 . During normal operation, the combined gas and vapor stream flows from point  42  through line  44  to sales  210 , but, at times the amount of gas and vapors being produced by the process will not be enough to keep the compressor fully loaded. When needed, pressure regulator  47  causes circulation of enough of the discharged gas and vapors to maintain the suction pressure at about 15 psig in inlet scrubber  9  to flow back through lines  43 ,  48  and  68 . 
     Handling of Gases and Vapors Under Abnormal Operation 
     Conditions that create slugging have been previously described in the liquid handling section. When a slug of liquid hydrocarbons is introduced into flash separator  1 , the liquid volume displaces, almost instantaneously, the same volume of gas contained in flash separator  1 . In addition to the displaced gases the liquid slug creates, almost instantaneously, flash gases and released vapors. The sudden introduction of an increase in the volume of gases and vapors that the unit is required to process will, unless controlled, overload the capacity of the compressor. 
     As previously described, gas expansion vessel  15  is designed to control the effects of a sudden introduction of a large volume of gas and vapors into the unit. When the volume of gas and vapors entering gas expansion vessel  15  increase enough to exceed the capacity of the compressor, the pressure in gas expansion vessel  15  is allowed to increase. Increasing the pressure in gas flash separator  1 , has the effect of increasing the gas and vapor capacity of gas expansion vessel  15  as well as slowing the release of gases and vapors from the liquid hydrocarbons. 
     As previously described, if the pressure in gas expansion vessel  15  increases to a point where gases can be released to storage tank  26 , the full capacity of the compressor is applied to rapidly reduce the pressure in gas expansion  15  by stopping the processing of hydrocarbon liquids in reboiler  3 . 
     In one embodiment, the speed of the compressor of the present invention is preferably variable from about half speed to full speed. The speed of the compressor in this embodiment is optionally controlled by changing the speed of the drive unit, which can optionally be an electrically-powered drive unit, a pneumatic-powered drive unit, an internal combustion drive unit, or a combination thereof. 
     Referring to  FIG. 1 , pressure transducer  115  is preferably disposed in inlet scrubber  9 . Pressure transducer  115  sends an electric signal through line  116  to PLC  13 . PLC  13 , responding to pressure transducer  115  sends an electric signal to either a VFD (electric drive) or a governor (internal combustion engine). The VFD or governor varies the speed of the driver and in turn the speed of the compressor depending upon the pressure in inlet scrubber  9 . 
     In case of a mechanical failure, such as a frozen dump line, an inoperable dump valve, etc., which could possibly lead to an uncontrolled release to the environment of hydrocarbon liquids or gases, three-way diverter valve  152  is preferably provided and can be disposed on line  153 , the inlet to flash separator  1  and gas expansion vessel  15 . In this embodiment, under most operating conditions three-way valve  152  remains open to allow hydrocarbon liquids and gases to enter flash separator  1  and gas expansion vessel  15 ; however, if a problem should occur that would allow hydrocarbon liquids to rise high enough in expansion vessel  15  to activate electric level control  133 , an electric signal is preferably sent through line  134  to PLC  13 . PLC  13  then sends an electric signal through line  158  to solenoid  156 . Activating solenoid  156 , in turn, preferably sends a pneumatic signal through tubing line  157  to three-way valve  152  causing the valve to switch and send all the liquid hydrocarbon production to storage tank  26  via flow line  154 . After three-way valve  152  has switched to send all the liquid hydrocarbon production to storage tank  26 , a time delay, which can preferably be anywhere from about 1 minute to about 2 hours and is most preferably between about 15 to about 30 minutes is preferably provided. If electric liquid level control  133  remains activated after the time delay, the problem of a high level can be detected and would thus be considered a major malfunction, thereby causing the unit to automatically shut down. If, during the time delay, the liquid level dropped enough to de-activate electric liquid level control  133  the malfunction would thus be considered a possible temporary problem, and the unit would not be automatically shut down. In this case, three-way valve  152  is preferably switched, thus sending the liquid hydrocarbon production to the unit. As soon as three-way valve  152  switches the liquid hydrocarbon production back to the unit, a new timer is preferably activated and most preferably has a duration of about 15 minutes to about 4 hours and most preferably has a duration of about 1 hour. If during the 1-hour event, the fluid level rises again and activates liquid level control  133 , the problem would not be consider temporary, in which case the liquid hydrocarbon production is again be switched back to storage tank  26  and the unit is automatically shutdown. 
     While the bulk of this application discusses a two stage compressor embodiment, on applications where the discharge pressure is high, a compressor having three or more stages can be used. All the operating principles remain the same, regardless of whether a two, three, or more stage compressor is used. The main difference between a unit with a two or three stage compressor is that an additional cooling coil, with a temperature control valve, thermostat, etc., is preferably provided on the three stage compressor to control the compression temperature of the third stage. These additional components are readily observed simply by comparing and contrasting  FIGS. 1 and 2 . 
     As illustrated in the three-stage compression system of  FIG. 2 , the same configuration as was used in the two stage compression system is also preferably used, except that now, instead of line  44  exiting to the gas sales line, it preferably splits at point  173  before being directed into through line  176  to the hot port  177  of splitter valve  169  and the other portion flowing into cooling coil  165  to the cool port  174  of temperature control valve  169 . The condensates in flash separator  1  serve as a heat sink to cool the hot vapors flowing through cooling coil  165 . Temperature control valve  169  is controlled by thermostat  168  which is set to maintain a discharge temperature from third stage of compression  166  that is above the hydrocarbon dew-point of the combined gas and vapor stream but less than 300 degrees Fahrenheit. As further illustrated in  FIG. 2 , thermostat  168  is mounted in line  186 . Line  186  is the hot discharge line from third stage of compression  166 . From the common port  187  of splitter valve  169  the temperature controlled combined gas and vapor stream flows through line  179  to the inlet port  180  of interstage scrubber  167 . Interstage scrubber  167  separates hydrocarbon liquids that are in the cooled, pressurized, combined gas and vapor stream from second stage compression  11 . The liquid level in interstage scrubber  167  is maintained by liquid level control  170  and dump valve  172 . Liquid hydrocarbons separated by interstage scrubber  167  are dumped through dump valve  172  and line  197  to point  73 . At point  73 , liquid hydrocarbons from interstage scrubber  167  are combined in line  72  with the condensates from flash separator  1  and flow to heat exchanger  7 . The liquid free combined gas and vapor stream exits interstage scrubber  167  at discharge port  181  and flows through line  182  into the suction port  183  of the third stage of compression  166 . The combined gas and vapor stream exits third stage of compression  166  through discharge port  178  at a temperature that is preferably in excess of the hydrocarbon dew point but less than about 300 degrees Fahrenheit and a discharge pressure that is preferably about 450 to about 1000 psig. The pressurized and heated combined gas and vapor stream flows through line  184  to point  185 . During normal operation, the combined gas and vapor stream flows from point  185  through line  186  to sales, but, at times the amount of gas and vapors being produced by the process will not be enough to keep the compressor fully loaded. When needed, pressure regulator  47  causes circulation of enough of the discharged gas and vapors to maintain the suction pressure at about 15 psig in inlet scrubber  9  to flow back through lines  43 ,  48  and  68 . 
     In one embodiment, the additional components illustrated in  FIG. 2 , which are not illustrated in  FIG. 1 , are preferably duplicated again for a four-stage or additional-stage compressor, etc. While embodiments of the present invention preferably use some pneumatic control mechanisms, alternative embodiments of the present invention optionally use other known mechanisms, including but not limited to hydraulic control, electrical control, electro-mechanical control, and combinations thereof in place of one or more of such pneumatic control mechanisms. 
     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, including in the appended claims, all such modifications and equivalents. The entire disclosures of all references, applications, patents, and publications cited above and/or in the attachments, and of the corresponding application(s), are hereby incorporated by reference.

Technology Classification (CPC): 1