METHOD AND APPARATUS FOR SEPARATING GASES AND LIQUIDS FROM WELL-HEAD GASES

Abstract: An apparatus and method for improving the volumetric yield of well-head gas and the hydrocarbon composition of the liquid condensate from a natural gas well by the use of multiple stages of gas-liquid separation and gas compression including the use of heating means (10) for heating the well-head gas stream to a predetermined temperature; valve means (11) associated with the heating means for reducing the pressure of the well-head gas stream in the heating means (10) to a predetermined reduced pressure to produce a reduced pressure and reduced temperature well-head gas stream; mixing means (5) for mixing the reduced pressure well-head gas stream with compressed gases and vapors wich have been subjected to multiple stages of compression; high pressure gas liquid separation means (20) for separating gases from liquids in the heated, reduced pressure well-head gas stream that have been mixed with compressed gases and vapors; second gas-liquid separation means (30) operating at a lower pressure than the high pressur gas-liquid separation means (20) for further separation of gases and vapors from the liquid separated by the high pressure gas-liquid separation means (20) to produce flashed gases, vapors and liquid components; and gas compression means for compressing and liquifying the flashed components recovered from the second gas-liquid separation means and means (92, 94) for introducing the compressed flashed components into the reduced pressure well-head gases in the mixing means.

Description: METHOD AND APPARATUS FOR SEPARATING GASES AND LIQUIDS FROM WELL-HEAD GASES This invention relates to the separation of gases and vapors from the liquids present in the well- head gas from natural gas wells. In particular, this invention relates to a method and apparatus for improv¬ ing the production of natural gas wells by the use of multiple stages of gas and vapor compression in a manner which can recover additional liquid hydrocarbons and enrich the sales gas stream. Many natural gas wells produce a relatively high pressure well stream of natural gas containing significant volumes of high vapor pressure condensates which will normally contain absorbed and dissolved natural gas, propane, butane, pentane and the like. Currently these liquid and dissolved hydrocarbons are only partially recovered by conventional, high pressure, separator units. The liquid hydrocarbon by-products normally removed from.the well stream, with high pressure separator unit, are collected and then typically dumped to a low pressure storage tank means. A substantial amount of dissolved gas and high vapor pressure hydro¬ carbons remain in the liquid hydrocarbon by-products. Some of these gases and hydrocarbons vaporize by flashing in the storage tank due to the substantial reduction in pressure in the tank which permits the volatile com¬ ponents to evaporate or off-gas into the gas and vapor OMPI SUBSTITUTE SH -^§ over the condensate. In this manner, some gas, and en¬ trained liquid hydrocarbons are vented to the atmosphere and wasted. In addition to this initial vaporization and loss, further evaporation occurs when the condensate stands for a period of time in the storage tank. This is described in the industry as weathering. Thus, natural gas wells, which produce signifi¬ cant amounts of high vapor pressure condensates along with the natural gas, present a great opportunity for improvement in production methods including a reduction in discharge to the envixonrπent and economic gain by recovery of otherwise wasted by-products. As previously described, present production equipment waste to the atmosphere large quantities of recoverable liquid and gaseous hydrocarbons, including absorbed and dissolved natural gas components. This * waste occurs when the high vapor pressure liquid condensates and the dissolved gases are removed from the flowing gas stream by the separator, and through valving and sometimes intermediate pressure vessels, flashed when the pressure on the con¬ densates is reduced to approximately atmospheric in the storage tanks. One prior method directed at reducing the loss of the heavier liquid hydrocarbon components, which would otherwise be lost from flashing, has involved the use of a staging flash separator where the pressure of the condensate is reduced in stages. For example, the condensate pressure could be reduced in stages before transfer to a storage tank maintained at about atmospheric pressure. Staging, in the manner described, can increase the recovered hydrocarbons by as much as 10% to 15%, but staging alone does not remove all of the absorbed gases and volatile hydrocarbon vapors from the conden- sate. The resulting liquid condensate still contains important components which, as previously described, cannot be completely held in the liquid phase at atmos- pheric pressure and will still be carried into the gases and vapors during flashing with the attendant loss of heavier entrained liquid hydrocarbon components of the condensate. It is, therefore, an objective of the present invention to provide an apparatus and method for more efficiently processing the additional recoverable gas and liquid hydrocarbon components normally contained in the condensates obtained from a natural gas well-head gas-liquid separation system. The present invention provides an apparatus and method for enhancing the overall production of natural gas wells by the use of multiple stages of gas-liquid separation in a process wherein the pressure on the condensate is reduced in a manner that increases the recovery of absorbed gases and vapors before the transfer of the remaining liquid to a storage tank at nearly atmospheric pressure, and includes compressing the gases and vapors recovered from separation stage, and then reintroducing these recovered components back into the well-head stream, under specific predetermined conditions, which also enhances the recovery of the heavier liquid hydrocarbon components which might otherwise be wasted. The present invention employs compressor means selected to receive and compress the relatively by¬ product gas from a second separator means provided in the system, and for subsequently injecting the compressed gases and vapors thus into the well-head gas stream at a predetermined location and under conditions which facilitate enrichment of the volume, composition and B.T.U. content of the sales gas stream and liquid hydro-, carbon recovery. In one embodiment of the present invention, the second separator means selected can be a staging separator which, in a preferred embodiment, may, in addition con¬ tain heat exchanger means whereby some of the heat of compression imparted to the compressed gases and vapors "g j SE OMPI by the compressor means is used to maintain a predeter¬ mined temperature in the staging separator. In another embodiment of the present invention, the separation means employed is a trayed stripping tower reboiled with a natural gas fired heater. The heat of compression can again be used to offset the heater gas usage. The use of the stripper and reboiler described allows the vapor pressure of the resulting condensate to be reduced to below atmospheric pressure thereby essentially eliminating all subsequent vapor and liquid loss from the condensate tank. Fig. 1 is a schematic flow diagram of the method of the present invention for separating gases from the condensable liquids present in natural gas well-head gases. Fig. 2 is a partial flow diagram of the heater, high pressure separator, and staging separator apparatus used in the method of the present invention. .- Fig. 3 is a schematic of a typical, single, high pressure gas-liquid separator process. Fig. 4 and 4a is a schematic of one embodiment of the present invention. Figs. 5 and 5a is a schematic of another embodi¬ ment of the present invention. Figs. 6 and 6a are schematic drawings of a recovery system utilizing only staging separator with¬ out compression means. Fig. " 7 is a side elevation of a trayed stripping tower useful in one embodiment of the present invention. Fig. 8 is a side elevation of a reboiler useful with the stripping tower shown in Fig. 7. Fig. 9 is an end view of the reboiler shown in Fig. 8. The gas-liquid separation apparatus and method of the present invention is shown schematically in Fig. 1. The well-head gas is heated, passed through a choke and then mixed with high pressure, high temperature gas which had previously undergone multiple stages of com¬ pression. The mixed gases are then subjected to high pressure gas-liquid separation to initially remove the liquid condensates and to produce an enriched sales gas that is suitable for further treatment such as dehydration if desirable before use. For example, a dehydrating system of the type shown in United States patents, Nos. 4,342,572, issued August 3, 1982; 4,198 214, issued April 15, 1980; and 3,094,574, 3,288,448, 3,541,763, and co-pending application of Charles R. Gerlach et. al., U.S. Serial No. 277,266, the disclosures of which are incorporated herein by reference, can be employed in combination with the herein described invention. The gas-liquid separation apparatus and system of the present invention shown in Figs. 1, 2, and 3, begins with a heater 2 having a heat exchanging tube coil 4 into which the gaseous product from a well-head are introduced. The well-head gases are conveyed via interconnected gas heating coils 4 and 6, which are immersed in an indirect heating medium 3, such as a glycol and water solution in heater 2. A choke valve 5 is inserted in the pipe connecting gas heating coils 4 and 6, and is used to reduce the well-head pressure to a pressure compatible with the operating pressure of separator 20 and the sales gas line 26. The heating medium 3 can be heated by means of a conventional fire tube heater shown at 10. The fire tube heater 10 is controlled by means of a thermostatically controlled valve 11 connected to a gas burner unit 12, and the heater 10 is connected to a flu 13. Heating coil 6 is connected to high pressure separator 20 by means of a pipe 21. This high pressure separator 20 operates to mechanically separate the gas and liquid components at a predetermined operating temperature and pressure. Typically the gas-liquid mixture introduced into high pressure separator 20 will be at a pressure of from about 1,000 psig to about 500 Λ . OMPI psig and temperature of from about 70°F. (22°C.) to about 90°F. (33 β C). The valve 22 is controlled by the liquid level inside the high pressure separator 20 such that when the liquid level reaches a predetermined height, the valve 22 will be opened drawing off the liquid under the pressure of the gaseous component by means of pipe 25 which transmits the liquid component to an intermediate pressure separator 30. The gaseous components are removed from the high pressure separator by means of pipe 26, and are subsequently sold after further process¬ ing, if necessary. The sales gas may advantageously be further dried by the removal of water using for example, a glycol dehydration system as previously described. The intermediate pressure or staging separator 30 is generally operated at pressures of less than about 125 psig. Most of the absorbed natural gas and some of the higher vapor pressure components of the condensates removed from the high pressure separator 20 will be flashed- from the liquid phase into the vapor phase in the intermediate pressure separator 30. The intermediate pressure separator 30 consists of a tank 35, a water dump valve 36, an oil dump valve 37, an oil liquid level control and water liquid level control (not shown) , a thermostat 39, a heating coil 34 a bypass line 32, and a three way temperature splitter valve 33, shown in Fig. 2, as well as safety and control monitoring devices such as gauge glasses, safety release valves and the like. The oil dump valve 37, which operates in response to the oil liquid level control (not shown) , passes oil from the intermediate pressure separator 30 via pipe 44 into the storage tank 50, (shown in Fig. 1). The primary function of the intermediate pressure separator 30 is to flash at a higher than atmospheric pressure most of the absorbed natural gas and high vapor pressure components of the condensates into a vapor phase. The flashed gases are removed from intermediate pressure separator 30 by means of a pipe 40 through a back pressure -1- valve 41 and conveyed onto the multiple stages of com¬ pression, shown in Figs. 4, 4a, 5 and 5a. The liquid condensate storage tank 50 operates at nearly atmospheric pressure. The further pressure reduction from the pressure in the intermediate pressure separator 30 will permit some limited further flashing of the hydrocarbons to occur as the pressure is reduced. A pressure relief valve 51 as shown in Fig. 1, is provided for pressure control on the storage tank 50. The flashed gases and vapors are removed from storage tank 50 by means of a vent pipe 55. The multiple stages of compression provided, receive the gas from the staging separator and compresses the gas up to the pressure of the gas line immediately downstream of the choke valve 5 in the heater 2. Preferably the compressed gases are transferred, as by line 92, shown in Fig. 2, to a heat exchanger in the staging separator 30 to recover some of the heat of compression to heat the fluids in the staging separator for greater gas and vapor recovery from the separated liquids in the staging separator before the liquids are discharged to the storage tank 50. Most preferably the compressed gases from the transfe pipe 92 are introduced into the three way temperature control splitter valve 33 which is external of the staging separator 30. The three way splitter valve 33 controls the introduction of the high pressure and high temperature compressed gases from the compressor means by means of a thermostat 39 which senses the temperature of the liquids contained in the separator 30. The three way splitter valve 33, receiving the gases and vapors from the last stage of the compressor means diverts the high pressure, high temperature gases either directly to heat exchanger 3.4, inside the staging separator - 30, when required, or bypasses the heat exchanger 34, depending on the conditions required in the intermediate pressure separator 30, and then through a transfer line 94 for reintroduction of the gas and vapor into the gas heating coil 6 contained in heater 2 at a point down¬ stream of choke valve 5. In the embodiments shown in Figs. 4, 4a, 5 and 5a, it is preferable to use the heat from the heated liquids in the staging separator to raise the temperature of the liquids going to the staging separator from the high pressure separator and to cool the liquids going to the storage tank 50. This is shown schematically in both embodiments by providing a heat exchanger between these two lines. In the embodiment utilizing a stripper in the place of the staging separator, a natural gas fired reboiler (Fig. 8 and 9) is employed with a stripper unit (Fig. 7} to stabilize the liquids going to the storage or condensate tank. The recovered gases and vapors from the stripper unit are then also compressed, as in the first embodiment, and the gases and vapors are returned to the well head gas downstream of the choke valve, as previously described. Condensate from the intercoolers is preferably returned to the stripper unit via the re¬ boiler for additional separation of additional hydro¬ carbon gas and vapors. The condensate from the stripper is transferred to the storage tank. As shown by the dotted line on Figs. 5, 5a and 6a, some of the compressed gases and vapors from the compressor means can be returned to the stripper feed stream such as shown, at 8C in Fig. 5, to maintain the compressor suction pressure during periods where the stripping operation is not producing enough gases and vapors. Likewise, cooler sales gas from the sales gas line can also be used, if desired, to maintain the compressor suction pressure. An example of this is also shown by dotted lines in Figs. 5a and 6a. The use of the sales gas stream for this function will of course require controllable valve means and pressure reduction means, not shown. In the embodiments shown, the selection of compressor capacity, intercooler capacity between com- pression stages and other equipment described, can be selected from conventional commercially available com¬ ponents to satisfy the overall system requirements for a particular natural gas well. Operation of the Invention In operation, the well-head gases from a natural gas well are conveyed into a gas heating coil 4 which is totally immersed within indirect heating medium 3 contained in the heater 2. The heater 2 is heated by means of a typical fuel gas burner 12 controlled by valve 11 which is responsive to a thermostat 8 in high pressure gas liquid separator 20 which senses the gas temperature in separator 20 and controls the amount of fuel gas flow¬ ing to the burner assembly 12. In this manner the tempera- ture of the indirect medium in heater 2 can be changed, as required, to meet the gas temperature requirements of high pressure separator 20. Normally, the heating medium 3 is maintained at a temperature which is dependant on the .composition and pressure of the well head gas to obtain the optimum separation of the gases and liquids in the high pressure separator 20 while still permitting the reintroductions of compressed gases and vapors from - the compression means for the hydrocarbon enrichment of the product gas stream and enhanced liquid hydrocarbon recovery described herein. In addition to the temperature control provided by the thermostat 8 and the fuel gas control valve 11, high pressure and high temperature compressed gases are introduced from the third stage of the multiple stage gas, compression system shown in Figs. 4, 4a, 5, and 5a into a heating coil 6 which is connected to heating coil 4 through a choke valve means 5. The high tempera¬ ture, high pressure compressed gases are introduced down stream of choke valve 5 which normally reduces the well-head pressure to between about 1000 psig and 500 psig. The well head pressures encountered in the field will vary widely, however, the advantages of the present S UBSTITUTE SH£ET OMPI WIP invention can still be achieved to different degrees at pressures higher or lower than described. The expansion of the gases exiting from choke valve 5 produces a degree of cooling below the desired operating temperatures thereby requiring a predetermined residence time in the second heating coil 6 for additional heat absorption so that /the temperature sensed at 8 will be at the proper predetermined value. This reduction in temperature and pressure is desirable for the enhanced recovery of gases and liquid hydrocarbons which can be achieved by the present inven¬ tion. The cooling by expansion provides for greater condensation of. the heavier hydrocarbon vapor components of the compressed gases and vapors and the pressure reduction allows the higher vapor pressure by-product gases to enrich the gas stream going into the high pressure separator. Therefore, the introduction of high pressure and high temperature compressed gases into the well-head gas after choke valve 5 and before additional heating in heating coil 6, enriches the hydrocarbon content in the gas stream, thereby producing a higher BTU content in the sales gas. In addition, any liquid condensates from the compressed gases and vapors that are present in the gas-liquid stream flowing through line 21, or condensed into the stream, as previously described, and introduced into a conventional high pressure separator 20, as previously described, are mechanically separated by internal baffles and the like (not shown) , to provide for a relatively condensate free sales gas product exhausted from the high pressure separator 20 through line 26. High pressure separator units which can be used advantageously in the present invention are commercially available. As the liquid level in high pressure separator 20 increases, the liquid level control 7 actuates motor valve 22 so that the liquid condensates can be exhausted OMH via pipe 23 and line 25 to staging separator 30. The intermediate pressure separator 30 is maintained at a lower pressure than the high pressure separator 20. Under the conditions of temperature and pressure selected for the operation of the staging separator 30, most of the absorbed natural gas and higher vapor pressure hydro¬ carbon components contained in the condensates will flash into the vapor phase. The flashed gases are permitted to flow through line 40 and through back pressure valve 41 and line 42 for " subsequent compression in the multiple stage compression system. The staging separator 30 also accumulates liquid condensates which include both hydro¬ carbons as well as water. The water level in intermediate pressure separator 30 can be controlled by means of a liquid level control, which is commercially available, that is responsive to the rise in the hydrocarbon-water emissible phase and controls dump valve 36 which will exhaust a portion of the water to waste, under the pres¬ sure of the flashed vapors in the staging separator 30. A second liquid level control is provided which is responsive to the level of the hydrocarbon condensates in the staging separator 30 to control a valve 37 which when open will, in a like manner, remove a portion of the hydrocarbon condensates through line 44 and into storage tank 50, shown in Fig. 1. Typical float operated controls which are suitable for this purpose are avail¬ able from Kimray, Inc. and Custom Engineering and Manufacturing Corp., of Tulsa, Oklahoma. As previously described, the high temperature, high pressure compressed gases , vapors and liquids from the compression means shown in Figs. 4, 4a, 5, and 5a, are introduced via line 92 into a three way temperature control splitter valve 33. A thermostat 39 sensing the temperature of the hydrocarbon condensates in the staging separator 30 controls the flow of the high temperature * , high pressure compressed gases and vapors from line 92 through either a by-pass line 32 or heat exchanger 34 O ?I depending on whether additional heating is required for the condensed hydrocarbons in the staging separator 30 for the desired flashing of the high vapor pressure components of the condensed hydrocarbons to occur. The liquid hydrocarbons from staging separator 30 which pass through line 44 are introduced to the storage tank 50 which operates at about atmospheric pressure. Under these conditions of temperature and pressure the hydrocarbons introduced from the staging separator 30 will undergo some further flashing of the remaining high vapor pressure components as well as releasing some absorbed natural gas and the like. The reduction in flashed vapors expected to be produced by this system can be seen in Table 3, Column 18A. When necessary, storage tank 50 can be evacuated through valve at 52. As shown in Figs. 5, 7, 8 and 9, it is possible according to this invention, to replace the staging separator with a trayed stripping tower to achieve the desired increase in sales gas volume, and BTU content by the recovery of the hydrocarbon gases and vapors that would otherwise be vented and wasted during the flashing in the storage tank and by weathering of the condensate in the storage tank. As previously described, the compression means (Fig. 5a) provides gases and vapors to the gas stream after the choke valve and the condensed liquids from the intercoolers between compression stages are preferably reintroduced into the stripper unit. A typical trayed stripping column 100 which will accomplish the objects of this invention is shown in Fig. 7. The outer tube 101 contains tray spacing defined by bubble trays as shown at 102 and 103. The condensate from the high pressure separator is introduced at 105 and descends through the trays σountercurrent with heated gases and vapors introduced at 110. The resultant gases and vapors are discharged -to compressor suction -W E OMr at 106. The column size, that is, its length and dia¬ meter can be selected for the specific application. The heated gases and vapors introduced at 110 can be obtained by the use of a typical reboiler such as shown in Figs. 8 and 9, with the stripping column 100 shown in place. A gas fired fire tube 120 is employed on the inside of the horizontal reboiler 115 and controlled (not shown) to achieve the specific temperatures required for heating the condensate that descends through the stripping column 100 to produce the gases and vapors which will ascend countercurrently in contact with the condensate to flash the desired dis¬ solved hydrocarbons and high vapor pressure gases for reintroduction into the well gas stream, as previously described. The following examples of the operation of the systems of the present invention show superior results in comparison with the usual results using conventional equipment not employing the present invention. The performance data was simulated using established data from Northern California Gas Company's (NCG) well number 3 - 14. The well data and feed composition used for the simulation are shown in Table 1. The well-head gas com¬ position is based on analysis of current product natural gas combined with a typical condensate analysis for the well. TABLE 1 WELL HEAD GAS DATA WELL DESIGNATION: NCG WELL NO. 3 - 14 Nominal Flow Rate MMSCFD = 4.5 WELL HEAD Flowing Pressure (Pf) Psig = 2150 Flowing Temperature (Tf) °F = 75 Phase at Tf and Pf = MIXED GAS RATE VAPOR LIQUID FRACTION FRACTION TOTAL LB/DAY 238,645 39,809 278,454 M SCFD 4,425.5 gal/day 8537.8 WELL HEAD GAS ANALYSIS COMPONENT % MOLE LB MOLE/DAY H 2 0 0.04 4.8 C χ 80.90 10070.55 C0 2 2.04 254.5 N 2 0.20 24.3 C 2 8.86 1103.1 C 3 3.72 463.0 "IC 4 0.66 82.4 NC 4 0.75 93.3 c 5 0.10 12.1 NC 5 0.11 14.0 C_ 2.62 326.2 *C0 2 figure includes trance non-hydrocarbon gas analysis. The results of the computer simulation are shown on Tables 2, 3, and 4 which present the heat and material balance for each situation. In Table 2, the typical results from this particular well is shown where the system only employs a conventional heater, high pressure separator and condensate tank. Normal levels of product natural gas volume, condensate tank vapor and condensate are shown as well as the typical hydrocarbon composition of the natural gas product, condensate tank vapor and storage tank condensate. OMPI TABLE 2 6A 7A 8A 9A SI-REAM 1A 2A 3A 4A 5A H.P. M ER CCNDEN- OCHXNSATE Description WELL HEAD CHCKE CHOKE HEATER PBDOJCT DRAW SATE GAS JMOT OUTLET OUTLET NATURAL SEPARATOR GAS LIQUID TANK VAPOR 0.25 0.03 0.67 2.08 1.41 2.61 0.92 1.41 90.63 - TABLE 2 Columns 1A - 9A Part II ENTHALPY -2.378 4.022 4.022 10.637 10.511 0.126 1.388 -0.116 MMBTU DAY PHASE MIXED MIXED MIXED MIXED VAPOR LIQUID VAPOR LIQUID VAPOR MSCP/DAY 4425.5 4496.6 4424.8 4507.0 4507.0 109.3 MACP/DAY 20.8 24.0 62.3 71.5 71.5 111.4 LB/CF T f P f 11.4 10.2 3.6 3.3 3.3 0.087 HEATING VALUE 1148 1892 BTU/SCP LIQUID GAL DAY 60 # P. 8537.8 6976.9 10177.4 8093.9 (1.517GAL/ 8093.9 5502.2 MSCF) 5 Table 3 shows the same results from the use of a staging separator and compressor added to the same system and well whose results are shown in Table 2. Q- -PI X O JL O - . αi J JL STREAM IB 2B 3B 4B 5B 6B 7B 8B Description WELL HEAD CHOKE CHOKE CHOKE OUTIJΞT HEATER PRODUCT H.P. H.P. GAS -_NJ_EΓ OUTLET W/RECYCLE OUTLET NATURAL SEPARATOR LIQUID GAS LIQUID TO COOLER ENTHALPY -2. 378 4.022 4.022 5.101 11.296 11.145 0.150 0.150 MfflTU DAY MIXED MIXED MIXED MIXED MIXED VAPOR LIQUID MIXED PHASE VAPOR • MSCP DAY 4425.5 4496.6 4424.8 4515.8 4597.6 4597.5 87.7 MACF/DAY 20.8 24.0 62.3 64.0 72.7 72.7 22.5 IB CP T-P - 11. 4 10.2 3.6 3.6 3.3 3.3 0.27 HEATING VALUE , 1157 BTU SCF LIQUID GAl/CήY β0*F. 8537.8 6976.9 10177.4 10596.6 8518.7 (1.631 GAI/ 8518.7 6646.7 MSCF) 7808.0 6858.4 9899.8 10344.7 8621.5 8621.5 6602.5 TABLE 3 Columns 1 - - 8 Part I STREAM B 2B 3B 4B 5B 6B 7B 8B Description WELL HEAD CHOKE CHOKE CHOKE OUΠ_ET HEATER PRODUCT H.P. H.P. GAS INtET OUTLET W/RECYCI-E CUTLET NATORAL SEPARATOR LIQUID GAS LIQUID TO CCOI-E Moleβ Day % % " C- 10070.5 80.90 10070.5 10070.5 10204.3 10204.3 10067.8 83.10 136.5 136.5 - OD-8M- 278.8 2.24 278.8 278.8 285.5 285.5 278.5 2.30 7.0 7.0 - c- 1103.1 8.86 1103.1 1103.1 1155.9 1155.9 1097.4 9.06 58.5 58.5 " c3 463.0 3.72 463.0 463.0 509.6 509.6 446.6 3.69 63.0 63.0 " !C 4 82.4 0.66 82.4 82.4 93.5 93.5 73.4 0.61 20.1 20.1 " NC 4 93.3 0.75 93.3 93.3 106.7 106.7 77.8 0.64 28.9 28.9 « ιc 5 12.1 0.10 12.1 12,1 13.6 13.6 7.8 0.06 5.8 5.8 " NC 5 14.0 0.11 14.0 14.0 15.6 15.6 8.1 0.07 7.5 7.5 " C 6 + 326.2 2.62 326.2 326.2 336.0 336.0 52.9 0.44 283.2 283.2 • HjO 4.8 0.04 4.8 4.8 5.1 5.1 4.8 0.04 0.3 0.3 TOTAL 12448.2 12448.2 12448.2 12726.0 12726.0 12115.1 610.9 610.9 MLB DAY 278.4 278.4 278.4 286.9 286.9 240.7 46.2 46.2 TEMPERATURE 76.5 104.5 51.3 54.7 85 85 85 50°F. PRESSURE PSIG 2150 2140 810 810 800 800 800 40 TABLE 3 Columns 9 - 16 Part I STREAM 9B 10B 11B 12B 13B 14B 15B 16B Description L.P. WATER L.P. 2nd STAGE 3rd STAGE COMPRESSOR RECYCLE L.P. SEPARATOR DRAW SEPARATOR SUCTION SUCTION DISCHARGE GAS SEPARAT PEED VAPOR LIQUID Moleβ/Day -c. 136.5 NBGL. 133.8 133.8 133.8 133.8 133.8 2.7 " OO-8N- 2 2 7.0 6.7 6.7 6.7 6.7 6.7 0.3 , 2 58.5 52.8 52.8 52.8 52.8 52.8 5.7 " c 3 63.0 46.6 46.6 46.6 46.6 46.6 16.4 " « 20.1 11.1 11.1 11.1 11.1 11.1 9.0 " NC 4 28.9 13.4 13.4 13.4 13.4 13.4 15.5 " rc 5 5.8 1.5 1.5 1.5 1.5 1.5 4.3 " ∞5 7.5 1.6 1.6 1.6 1.6 1.6 5.9 " C 6+ 283.2 9.8 9.8 9.8 9.8 9.8 273.5 - ll ) 0.3 0.3 0.3 0.3 0.3 0.3 TRACE TOTAL 610.9 277.6 277.6 277.6 277.6 277.6 333.3 MLBtlAY 46.2 8.6 8.6 8.6 8.6 8.6 37.6 TEMPERATURE 71 100 170 170 304 161 100 PRESSURE PSIG 35 35 85 270 815 810 35 TABLE 3 Columns 9 - 16 Part II STREAM . 9B 10B 11B 12B 13B 14B 15B 16B Description L.P. L.P. 2nd STAGE 3rd STAGE COMPRESSOR RBCΪCLE L.P. SEPARATOR DRAW SEPARATOR SUCTION SUCTION DISCHARGE GAS SEPARATO VAPOR LIQUID ENTHAIPY 0.786 1.262 1.524 1.453 1.93 1.080 0.374 WB-TU IDAY PHASE MIXED VAPOR VAPOR VAPOR VAPOR MIXED LIQUID VAPOR >* MSCP DAY 96.3 105.4 105.4 105.4 105.4 96.6 MACF/DAY 28.4 32.7 18.2 5.9 2.4 1.5 IB/CF T j p j , 0.25 0.26 0.47 1.4 3.6 4.8 HEATING VALUE KΠJ SCF LIQUID GAV AY 60*F 6394.8 GAVDAY T j P f 6437.4 SP GR. T j P f 0.727 0.465 0.722 TABLE 3 Columns 17 - 19 Part I STREAM 17B 18B 19B Description CONDENSATE CONDENSATE CONDENSATE TO TANK TANK VAPOR Moles/Day % - c λ 2.7 2.4 17.02 0.3 0.09 « C0 2 8N 2 0.3 0.2 1.42 0.1 0.03 " c ", 3 16.4 4.4 31.20 12.0 3.76 • ιc 4 9.0 1.2 8.51 7.8 2.44 H NC 4 15.5 1.4 9.93 14.1 4.42 6 M IC 5 4.3 0.2 1.42 4.1 1.28 • NC 5 5.9 0.2 1.42 5.7 1.78 I " C 6+ 273.5 0.8 5.67 272.7 85.43 j • H 2 0 TRACE TRACE TRACE TOTAL 333.3 14.1 319.2 MLB/DAY 37.6 0.6 37.0 TEMPERATURE 65 75 75 PRESSURE PSIG 30 0 0 r JrABLE 3 Columns 17 -- 19 Part II STREAM 17B 18B 19B Description CONDENSATE CONDENSATE CONDENSATE TO TANK TANK VAPOR ENTHALPY -0.262 .078 -0.094 MMBTU/DAY PHASE LIQUID VAPOR LIQUID VAPOR n Li -i MSCP/DAY 5.4 MACF/DAY 5.4 c,_ H LB/CF T f P f 0.11 M HEATING VALUE 2342 BTU/SCP π π LIQUID H GAL/DAY 60 • P. 6111.5 5967.0 GAL/DAY T f P f 6128.7 6020.1 SP GR. T f P f 0.738 0.739 API 60*F. 57.9 Table 4 is the same system as Table 2 where the staging separator is replaced with a stripper column. TABLE 4 Columns 1 - 8 Part I STREAM 1C 2C 3C 4C 5C 6C 7C 8C Description WELL HEAD CHOKE CHOKE CHOKE OUTLET HEATER PRODUCT H.P. H.P. GAS INIJE3T OUTLET W/RBCYCEE OUTLEΓ NATORAL SEPARATOR LIQUID GAS LIQUID O STRIPPE Moles/Day % % 12.1 . W IC 5 0.10 12.1 12.1 14.7 14.7 8.3 0.07 6.4 6.4 « C 5 14.0 0.11 14.0 14.0 16.9 16.9 8.6 0.07 8.3 8.3 ! " C 6 + . 326.2 2. .62 326.2 326.2 346.6 346.6 54.3 0.45 292.3 292.3 « H 2 0 4.8 0, .04 4.8 4.8 5.2 5.2 4.9 0.04 0.3 0.3 TOTAL 12448.2 12448.2 12448.2 12775.5 12775.5 12137.6 637.9 637.9 MLB/DAY 278.4 278.4 278.4 289.4 289.4 241.6 47.8 47.8 TliMPERATURE °P . 76.5 104.5 51.3 60.3 85 85 85 171.3 PRESSURE PSIG 2150 2140 810 810 800 800 800 795 TABLE 4 Columns 1 - 8 Part II STREAM IC 2C 3C 4C 5C 6C 7C 8C Description WELL HEAD CHOKE CHOKE CHOKE OUTLET HEATER PRODUCT H.P. H.P. GAS INLET OUTIET W/REJCYCIE . OUTLET NATURAL SEPARATOR LIQUID GAS LIQUID O STRIPPE ENTHALPY -2.378 4.022 4.022 6.313 11.431 11.269 0.1629 2.566 MMBTUtΛY PHASE MIXED MIXED MIXED MIXED MIXED VAPOR LIQUID MIXED VAPOR MSCF DAY 4425.5 4496.6 4424.8 4538.0 4605.9 4605.9 27.9 MACF DAY 20.8 24.0 62.3 65.5 72.7 72.7 0.5 LB CF T^ 11.4 10.2 3.6 3.6 3.3 3.3 3.3 HEATING VALUE 1160 BTU/SCF LIQUID GAlVDAY 60°F. 8537.8 6976.9 .0177.4 10561.0 8825.4 (1.664 GAI 8825.4 8266.9 MSCF) GAI/DAY TJP f 7808.0 6858.4 9899.8 10384.0 8932.8 8932.8 9157.4 SP GR. T^ 0.611 0.597 0.640 0.634 0.641 0.641 0.603 API 60° l S TABLE 4 Olurms 9 - 17 Part I STREAM 9C IOC 11C 12C 14C 15C 16C 17C Description WATER STRIPPER 2nd STAGE 3rd STAGE RECYCLE STRIPPER CONDEN- CONDEN¬ CONDEN DRAW OVERHEAD SUCTION SUCTION GAS BOTTCM SATE TO SATE SATE TANK TANK VAPOR Moles/Day NBGL. 142.5 142.5 142.5 0 0 NONE 0 n ■ * < ■ _ ' 142.5 - O0.8M. 7.4 7.4 7.4 7.4 0 0 0 -c 2 60.5 60.5 60.5 60.5 0.7 0.7 0.7 0. " C 56.6 56.6 56.6 56.6 10.0 10.0 10.0 3. -ιc 4 14.9 14.9 14.9 14.9 6.7 6.7 6.7 2. « NC 4 19.2 19.2 19.2 19.2 12.2 12.2 12.2 3. iϊ -ιc 5 2.6 2.6 2.6 2.6 3.8 3.8 3.8 1. « NC 5 2.9 2.9 2.9 2.9 5.4 5.4 5.4 1. " C 6 + 20.4 20.4 20.4 20.4 271.9 271.9 271.9 87. 4 « H 2 0 0.3 0.3 0.3 0.3 TRACE TRACE TRACE TOTAL 327.3 327.3 327.3 327.3 310.6 310.6 310.6 MLB DAY 11.0 11.0 11.0 11.0 TEMPERATURE *F. 125.6 170 170 274.7 223.4 100 75 PRESSURE PSIG 35 91 285 815 35.6 30.6 0 TABLE 4 Columns 9 - 17 Part II STREAM 9C IOC 11C 12C 13C 14C 15C 16C 17C Description WATER STRIPPER 2nd STAGE 3rd STAGE RECYCLE STRIPPER CONDEN¬ CONDEN¬ COND DRAW OVERHEAD SUCTION SUCTION ; GAS BOTTOM SATE TO SATE SATE TANK TANK VAPOR ENTHALPY 1.811 2.011 1.803 2.296 2.750 0.347 -0. MMBTU DAY PHASE VAPOR VAPOR MIXED 1 VAPOR UQUID LIQUID LIQU VAPOR MΣ_CF/TJAY 124.1 124.1 119.9 124.2 NONE MACF DAY 40.3 20.0 6.3 2.5 IB CP T JP f 0.27 6.55 1.6 4.4 HEATING VALUE BTU SCF LIQUID GA tAY 60 P P 154. 5 1 5872.6 5872.6 587 As can be seen, the normal production unit perform ance from Table 2 yielded 4507.0 M SCFD a natural gas with a high heating value (HHV) of 1148 BTU/SCF and 5502.2 gallon per day (gal/day) of condensate with an estimated Ried Vapor Pressure (RVPJ of 20 psi. The vapor loss from the conden¬ sate tanks was 109.3 MSCFD with a heating value of 1892 BTU/SCF. The production unit has a heater duty of 13.0 MM BTU/day. By comparison, the results from the use of a system-two employing an intermediate pressure separator (Table 3) should yield 4597.5 MSCFD of natural gas with a heating value of 1157 BTU/SCF and 5967.0 gal/day of conden¬ sate with a RVP of 20 psi. The vapor loss from the condensa tank is reduced to 5.4 MSCFD with a heating value of 2342 BTU/SCF. The heater duty is slightly reduced to 12.6 MM BTU/day and a compressor requirement of 21 brake horse¬ power GhpJ is added. The results using a system employing a stripper unit, (Table 4) should yield 4605.9 MSCFD of natural gas at 1159 ' BTU/SCF.- The condensate yield is 5872.6 gal/day with RVP of 12 psi. There is no vapor loss from the tank. The heater duty is reduced to 11.5 MM BTU/day and the compressor requirement is 24 bhp. The stripper reboiler adds a heater requirement of 2.0 MM BTU/day. The foregoing process simulations give an accurate analysis of the operation of the present invention. Since the condensate tank can accept or reject heat from and to the atmosphere, the tank was simulated as an iso¬ thermal flash occurring at 75°F. This temperature is a reasonable estimate given the daily and seasonal climate variations and the results therefore represent an annual average. In warm weather the condensate tank will operate hotter than 75°F. and more vapor will be lost. The reverse is true if the tank is cooler than 75°F. The economics of the two embodiments described are compared against the standard production unit in Table 5. For these economics, natural gas is valued at $3.39/MSCF O PI based on a heating value of a 1000 BTU/SCF (equivalent value $3.39/MM BTU) . Condensate is valued at $29.50 per barrel CO.07 per gallon). Gas fired heater duties are assumed to be 80 percent efficient based on the fuels gas high heat value (HHV) . This high heat efficiency assumes the use of the Engineered Concepts Automatic Secondary Air Shutter which is capable of maintaining combustion efficiency greater than 90 percent based on the gas low heat value (LHVJ C8Q percent based on the HHV) . The compressor used in the compression stages is assumed to have a gas engine drive requiring 8000 BTUCLHV)/bhp hr. This energy requirement is equivalent to 8850 BTUCHHV}/bhp hr or 0.212 MM BT (HHV)/bhp day. As can be seen on Table 5, the two separator unit recovers an increment of gas worth $492 per day and an increased condensate yield worth $326 per day. The addition operating costs are $11 per day for a total net income increase of $807 per day or $294,555 per year (365 days). The production unit with the stripper recovers an increment of gas worth $556 per day and an increased conden¬ sate yield $260 per day. The addition operating costs an $19 per day for a total net income increase of $797 per day or $290,905 per year. While the overall hydrocarbon re¬ covery is higher for this unit, the net income in this case could be less than for a system employing two separator units. This is due to the current prices which values the gas at $3.39 per million BTU and $29.50 per barrel for condensate which is roughly equivalent to $5.60 per million BTU for the stable condensate. The stripper unit increases the gas recovery at the expense of condensates. Both the normal production unit and the two separator unit system yield a condensate with a RVP of 20 psi after the vapor is lost from the tank. The production unit with the stripper is simulated to produce a condensate with a true vapor pressure of 12.7 psi at 100°F. equal to a RVP of 12. This is done so that the unit can be installed at high altitude and produce a stable condensate with essentially no vapor loss from the condensate tank. Once installed, the stripper can be adjusted to produce a higher vapor pressure product to suit local conditions and still limit vapor loss. This, of course, will increase the condensate yield. The stable condensate from the unit with the stripper has a higher than normal value to the refiner or end user due to its composition. Depending on the prevailing prices for con¬ densate, it may be possible to obtain even greater economic advantages from the use of this invention. The additional income per year for production unit with the stripper will equal the additional income of the two separator unit if the value of the condensate is incrementally increased. Bot embodiments therefore offer the possibility of greater incom ClwP TABLE 5 EC :ONOMIC COMPARISON CASE STANDARD TWO SEPARATOR SEPARATOR PRODUCTION UNIT WITH UNIT at 20° RUP STRIPPER 12° RVP INCOME Natural Gas Rate MSCFD 4507.0 4597.5 4605 Heating Value 1148 1157 1159 MM Btu/day 5174.0 5319.3 5338 Income at $3.39/mm Btu $ 17,540 18,032 $ 18,096 Incremental Income/day BASE $ 492 $ 556 Condensate gal/day 5505 5967 5873 Income/day at $.70/gal $ 3,851 $ 4,177 $ 4,111 Incremental Income/day BASE $ 326 $ 260 OPERATING COST Heater Duty mm Btu/day 13.0 12.6 11 Cost/day at $3.39/mm * Btu and 80% eff. $ 55 $ 53 $ 49 Incremental Cost/day BASE $ -2 $ 06 Reboiler Duty mm Btu/day NONE NONE 2 Cost/Day at $3.39 mm Btu. and 80% eff. $ 8 Incremental Cost/day BASE NONE $ 8 Compressor bhp NONE 21.0 24 Required mm Btu/day 4.4 5 Cost/Day at $3.39 mm Btu .$ 13 $ 17 Incremental Cost/Day BASE $ 13 $ 17 SUMMARY OF INCREMENTAL INCOME AND COSTS Income Natural <Gas BASE $ 492 $ 556 Condensate BASE $ 326 $ 260 IΠUIAΛTU T'lMNI-V--. , -PTUTlΓkM-'i-'-i ' lM>'JT. 1 AΔiTl. TTlMV-Ό.V'iMTIC?. * BASE 818 $ 816 INCREMENTAL OPERATING COSTS Heater BASE $ -2 $ -6 Reboiler BASE $ • 8 Compressor BASE $ 13 TOTAL INCREMENTAL OPERATING COST 11 Additional income, per day Clncome Less Operating Costs) $ 807 $ 797 Additional income per year C365 days) $294,555 $290,905 By comparison. Table 6, which is keyed to the process schematic shown in Figs. 6 and 6A, simulates the use of a staging separator operated at 100°F. and 35 psig. with a reboiler for the necessary heat but without compressi and recycle to the choke outlet, which is an important characteristic of the present invention. A careful analysis of the data shown for the process schematics employing the present invention with the results from the processes shown in Table 2, Fig. 3 and Table 6, Fig. 6, demonstrates that, in addition to the improvement in sales gas yield and quality, the liquid condensate recovery is improved, with an improvement in the composition of the condensate. While presently preferred and illustrative embodiments of the invention have been described, it is contemplated that the inventive concepts may be otherwise embodied and employed. Thus, it is intended the appended claims be construed to cover alternative embodiments of the invention except insofar as limited by the prior art. ! O ^ WI TABLE 6 Columns 1 - 8 Part I STREAM ID 2D 3D 4D 5D 6D 7D 8D Description WELL HEAD CHOKE CHOKE CHOKE OUTLET HEATER PRODUCT H.P. H.P. GAS iM_-__τ OUTLET W/RECYCLE OUTLET NATURAL SEPARATOR LIQUID GAS LIQUID TO COOLE Moles/Day % 10070.5 80.9 10070.5 10070.5 " C l 10070.5 9942.6 83.72 127.9 127.9 " C0 2 8N 2 278.8 2.24 278.8 278.8 278.8 272.2 2.29 6.6 6.6 M C , 2 1103.1 8.86 1103.1 1103.1 1103.1 1049.7 8.84 53.3 53.3 " c 3 463.0 3.72 463.0 463.0 463.0 407.9 3.43 55.1 55.1 » ιc 4 82.4 0.66 82.4 82.4 82.4 65.2 0.55 17.2 17.2 » C 4 93.3 0.75 93.3 93.3 93.3 68.8 0.58 24.5 24.5 » ιc 5 12.1 0.10 12.1 12.1 12.1 7.1 0.06 5.0 5.0 « NC 5 14.0 0.11 14.0 14.0 14.0 7.4 0.06 6.6 6.6 326.2 " C 6 + 2.62 326.2 326.2 326.2 51.0 0.43 275.2 275.2 • H j O 4.8 0.04 4.8 4.8 4.8 4.6 0.04 0.2 0.2 TOTAL 12448.2 12448.2 12448.2 12448.2 11876.5 571.7 571.7 MLB DAY 278.4 278.4 278.4 278.4 234.0 44.4 44.4 TEMPERATURE 76.5 104.5 51.3 85 85 85 52.3 PRESSURE PSIG 2150 2140 810 800 800 800 40.0 rAt-Lt- t> uoiumns l - a rart ii STREAM ID 2D 3D 4D 5D 6D 7D 8D Description WELL HEAD CHOKE CHOKE CHOKE CUTLET HEATER PRODUCT H.P. H.P. GAS INLET OUTLET W/RECYCLE OUTLET NATURAL SEPARATOR LIQUID GAS LIQUID TO GOOI- ENTHALPY -2.378 4.022 4.022 10.637 10.511 0.1261 0.1261 PHASE MIXED MIXED MIXED MIXED VAPOR LIQUID MIXED ■ ' VAPOR , MSCF DAY 4425.5 4496.6 4424.8 4507.0 4507.0 80.6 MACF ftY 20.8 24.0 62.3 71.5 71.5 20.8 LB/CF T £ P f 11.4 10.2 3.62 3.27 3.27 0.266 HEATING VALUE 1148.5 HΠJ/SCF LIQUID GAVDAY 60»F. 8537.8 6976.9 , 10177.4 8093.9 (1.517 Gal 8093.9 6384.7 MSCF) GA__ DAY T^ 7808.0 6858.4 9899.8 8189.6 8189.6 6351.3 SP GR. T-P f 0.611 0.597 0.640 0.650 0.650 0.7 API 60° TABLE 6 Columns 9 -16 Part I STREAM 9D 10D 11D 12D 13D 14D 15D 16D Description L.P. WATER L.P. 2nd STAGE 3rd STAGE COMPRESSOR RECYCLE L.P. SEPARATOR DRAW SEPARATOR SUCTION SUCTION DISCHARGE GAS SEPARAT FEED VAPOR LIQUI 127.9 125.2 49.84 2.7 " < * -. , " C0 2 8N 2 6.6 6.3 2.51 0.3 2 53.3 47.9 19.07 5.4 •* c 55.1 ^3 40.1 15.96 15.0 • ιc 4 17.2 9.2 3.66 8.0 " NC 4 24.5 11.0 4.38 13.5 " ic 5 5.0 1.3 0.52 3.7 " C 5 6.6 1.4 0.55 5.2 " C ϋ 6+ 275.2 8.6 3.42 266.6 TOTAL 571.7 251.2 320.4 MLB tlAY 44.4 7.6 • 36.8 1IMPERA-CURE 72.9 100 100 PRESSURE PSIG 35 35 35 TABLE 6 Columns 9 - 16 Part II STREAM 9D 10D 11D 12D 13D 14D 15D 16D Description L.P. WATER L.P. 2nd STAGE 3rd STAGE COMPRESSOR RECYCLE L.P. SEPARATOR DRAW SEPARATOR SUCTION SUCTION DISCHARGE GAS SEPARA FEED VAPOR LIQUID ENTHALPY 0.7088 1.102 0.3560 HMBTU/DAY PHASE MIXED VAPOR LIQUID VAPOR MSCF DAY 87.9 95.3 MACF DAY 26.0 29.6 IB/CF T^ 0.249 0.256 HEATING VALUE 1705.9 BTO/SCF LIQUID GA tftY 60 β F, 6169.5 5938.1 GAVDAY T^ 6216.6 6083.4 TABLE 6 Columns 17 -- 19 Part I STREAM 17D 18D 19D Description CONDENSATE CONDENSATE CONDENSATE TO TANK TANK VAPOR Moles/Day % % w C l 2.7 2.4 19.05 0.3 0.10 - C0 2 8N 2 0.3 0.2 1.59 0.1 0.03 " c2 5.4 3.0 23.81 2.4 0.78 C 3 15.0 3.7 29.37 11.3 3.67 n ιc 4 8.0 1.0 7.94 7.0 2.27 " NC 4 13.5 1.1 8.73 12.4 4.03 - ιc 5 3.7 0.1 0.79 3.6 1.17 - NC 5 5.2 0.1 0.79 5.1 1.66 " C 6+ 266.6 1.0 7.93 265.6 86.29 " « 2 0 NEGL. NEGL. NEGL. TOTAL 320.4 320.4 12.6 320.4 307.8 MLB/DAY 36.8 0.5 36.3 TEMPERATURE 67.3 75 75 PRESSURE PSIG 30 0 0 TABLE 6 Columns 17 - 19 Part II STREAM 17D 18D 19D Description CONDENSATE CONDENSATE CONDENSATE TO TANK TANK VAPOR ENTHALPY -0.2266 0.0852 -0.0983 MMBTU/DAY PHASE LIQUID VAPOR LIQUID VAPOR MSCF/DAY 4.8 MACP/DAY 4.8 LB/CP T f P f 0.106 HEATING VALUE 2287 BTU/SCF LIQUID GAL/DAY 60 # P. 5938.1 5810.4 GAL/DAY T f P f 5962.2 5861.7 SP GR. T f P f 0.739 0.741 API 60 F. 57.4

Claims: C L A I M S 1. An apparatus for improving the volumetric yield of well head gas from a natural gas well by the use of multiple stages of gas-liquid separation and gas and vapor compression comprising: heating means for heating the well head gas to a predetermined temperature; valve means associated with said heating means for reducing the pressure of the well head gases in said heating means to a predetermined reduced pressure to pro¬ duce reduced pressure well head gases; mixing means for * mixing the reduced pressure well head gases with compressed gases and vapors which have been subjected to multiple stages of compression; high pressure gas-liquid separation means for separating gases and vapors from liquids in the heated, reduced pressure well head gases and vapors that have been mixed with compressed gases; second gas-liquid separation means for further separation of gases and vapors from the liquid separated by the high pressure gas-liquid separation means to pro¬ duce flashed gases, vapors and liquid components; and gas compression means for compressing the gases and vaporized components recovered from said second gas-liquid separation means and introducing said compressed gases and vaporized components into the reduced pressure well head gases in said mixing means. 2. The apparatus of claim 1, wherein heat exchanging means are provided between the compressed gases and vapors exhausted from the second gas-liquid separation means and the liquids exhausted from the high pressure gas-liquid separation means. 3. The apparatus of claim 1, wherein conduit means are provided between the high pressure gas liquid separation means and the compression means. 4. The apparatus of claim 2, wherein said compression means comprises multiple stages of compression with inter- O cooling between the stages of compression. 5. An apparatus for improving the volumetric yield of a stream of well head gas by the use of multiple stages of gas-liquid separation with subsequent compression comprising: indirect heating means for heating a stream of well head gas to a predetermined temperature; choke valve means in the stream for reducing the pressure of the stream of well head gas to provide a lower temperature than the predetermined temperature imparted to the stream by the indirect heating means; mixing means for mixing the compressed gases and vapors subsequently recovered from the liquids separated from the well head gas into the reduced pressure well head gas stream; high pressure gas separation means for receiving and separating the mixed well head and compressed gases and vapors from a liquid condensate at a predetermined temperature and pressure from the heating means after mixing; .. staging separator means for receiving the separated liquid condensates from the high pressure gas separation means at a predetermined lower pressure than said high pressure gas separation means to further separate dissolved gases and vapors and water from a liquid condensate; compression means for compressing the gases and vapors separated by said staging separator means for intro¬ duction thereof into said mixing means. 6. The apparatus of claim 5, including heat exchanging means in the staging separator means for receiving the com¬ pressed gases and vapors and capable of removing a predeter¬ mined amount of heat for operation of the staging separator before introducing the compressed gases and vapors to the mixing means. 7. An apparatus for increasing the volume and enhancing the hydrocarbon composition of a stream of well head gas by the use of multiple stages of gas-liquid separation with sub¬ sequent compression comprising: _ O P indirect heating means for heating a stream of well head gas to a predetermined temperature; choke valve means in the well head gas stream for reducing the pressure of the stream of well head gas to produce a lower temperature than the temperature imparted to the stream by the indirect heating means; mixing means for mixing high temperature high pressure compressed gases and vapors into the reduced pressure well head gas stream; high pressure gas separation means for receiving the mixed well head gas stream at a predetermined temperature and pressure from the heating means after mixing, and capable of separating gas and vapor from liquid condensates; stripping means for receiving the liquid condensates from the high pressure gas separation means at a predeter¬ mined lower pressure than said high pressure gas separation means to further separate gases and vapors from the liquid condensate; compression means for compressing the gases and vapors separated by said stripping means for introduction thereof into said mixing means. 8. The apparatus of claim 7, wherein said stripping means comprises trayed stripping column means and reboiler means. 9. The apparatus of claim 8, wherein a portion of the compressed gases and vapors from said compression means is introduced into the stripping means. 10. A method of separating absorbed gases and high vapor pressure hydrocarbon components from condensed liquids in a natural gas well head gases stream comprising the steps of: heating the well head gas stream to a predetermined .temperature; reducing the pressure of the well head gas stream; mixing the well head gas stream with compressed gases and vapors recovered from condensed liquids subsequently separated from the well head gas stream; OMPI mechanically separating the liquids condensed from the well head gas stream at a predetermined pressure; recovering the condensed liquids and flashing the volatile components from the condensed liquids at a pre¬ determined temperature and a pressure lower than the pressure employed during mechanical separation of the liquids; recovering the flashed components; compressing the flashed components to a predeter¬ mined pressure; and introducing the compressed components into the well head gas stream. 11. An apparatus for improving- the yield of well head gas and liquid condensates from a natural gas well by the use of multiple stages of gas-liquid separation and gas and vapor compression comprising: heating means for heating the well head gas to a predetermined temperature; valve means associated with said heating means for reducing the pressure and the temperature of the well head gases in said heating means to a predetermined reduced pressure and temperature, to produce reduced pressure well head gases; mixing means for mixing the reduced pressure and temperature well head gases with compressed gases and vapors which have been subjected to multiple stages of compression; high pressure gas-liquid separation means for separating gases from liquids in the heated, reduced pressure well head gases that have been mixed with com¬ pressed gases and vapors; second gas-liquid separation means for further separation of gases and vapors from the liquid separated by the high pressure gas-liquid separation means to produce flashed gases and vapors and liquid components; and gas compression means for compressing and liquifying the gas and vapor components recovered from said second gas-liquid separation means and introducing said com¬ pressed gases and vapors into the reduced pressure and temperature well head gases in said mixing means to condense liquid condensate separatable by said high pressure gas-liquid separation means from the gases and vapors. 12 The apparatus of claim 11, wherein heat exhanging means are provided between the flashed gases and vapors exhausted from the second gas-liquid separation means and the liquids exhausted from the high pressure gas-liquid separation means. 13. The apparatus of claim 12, wherein said compression means comprises multiple stages of compression with inter- cooling between the stages of compression. 14. An apparatus for improving the yield of gases and liquid condensate from a stream of well head gas by the use of multiple stages of gas-liquid separation with subsequent compression, omprising: indirect heating means for heating a stream of well head gas to a predetermined temperature; choke valve means in the stream for reducing the pressure and temperature of the stream of well head gas to a predetermined lower temperature than the predeter¬ mined temperature imparted to the stream by the indirect heating means; mixing means for mixing relatively high temperature, high pressure compressed gases and vapors into the reduced pressure well head gas stream; high pressure gas separation means for receiving the mixed well head and compressed gases, vapors and liquid condensates at a predetermined temperature and pressure from the heating means after mixing, said separation means being capable of separating gases and vapor from liquid condensates; staging separator means for receiving the liquid condensates from the high pressure gas separation means - TJR at a predetermined lower pressure than said high pressure gas separation means to further separate dissolved and high vapor pressure gases and vapors and water from the liquid condensate; compression means for compressing the gases and vapors separated by said staging separator means for introduction thereof into said mixing means. 15. An apparatus for increasing the volume and B.T.U. content of a stream of well head gas and for increasing the yield of liquid hydrocarbon condensate by the use of multiple stages of gas-liquid separation with subsequent compression comprising: indirect heating means for heating a stream of well head gas to a predetermined temperature; choke valve means in the stream for reducing the pressure and temperature of the stream of well head gas to a predetermined lower temperature than the predeter¬ mined temperature imparted to the stream by the indirect heating .means; mixing means for mixing compressed gases and vapors into the reduced pressure well head gas stream; high pressure gas separation means for receiving the mixed well head and compressed gases, vapors and liquid condensate at a predetermined temperature and pressure from the heating means after mixing, and for separating the gas and vapor from the liquid condensates; stripping means for receiving the liquid condensates from the high pressure gas separation means at a predeter¬ mined lower pressure than said high pressure gas separation means to further separate dissolved and high vapor pressure gases and vapors and water from the liquid condensate; compression means for compressing the gases separated by said stripping means for introduction thereof into said mixing means. 16. The apparatus of claim 15, wherein said stripping means comprises trayed stripping column means and reboiler OMPI eans . 17. The apparatus of claim 16, wherein a portion of the compressed gases and vapors from said compression means is introduced into the stripping means. 18. A method of separating absorbed gases, vapor and liquid hydrocarbon components from the liquids separated from natural gas well head gases comprising the steps of: heating the well head gas to a predetermined temperature; reducing the pressure and temperature of the well head gas; mixing the well head gas with gases and vapors recovered from the liquids subsequently separated from the wellhead gas stream; mechanically separating the liquids from the well¬ head gases at a predetermined pressure and temperature; recovering the liquids and flashing the volatile components from the liquids at a predetermined temperature' and lower pressure than the pressure employed during mechanical separation of the liquids; recovering the flashed components; compressing the flashed components to a predeter¬ mined pressure; and introducing the compressed gases and vapors from the flashed components into the well head gases. 19. The apparatus of claim 15, wherein said compression means includes intercoolers, and condensate from said inter- coolers is returned to said stripping means.

Inventors: HEATH RODNEY THOMAS, HEATH, RODNEY, THOMAS
Applicants: HEATH RODNEY THOMAS, HEATH, RODNEY, THOMAS
Application year: 1984
Main classification: B01D19
IPC codes: B01D19, C10G5, E21B43