10, while in another embodiment a longer stage or a different pump requiring higher pressure may require the use of a three-stage compressor or a package with multiple compressors in parallel. Where more than one compressor 22 is desired, the compressors may be linked in series or in parallel.

It will be understood that the compressor 22 is powered by a driver 24, such as an engine or electric motor. Single cylinder engines are common in oilfields and are sufficient to power the compressor 22, although it will be understood that drivers 24 comprising multi-cylinder engines and multiple engines or motors may be employed in the system 10, depending on conditions at the well 12. The driver 24 may be powered by gasoline, diesel, or natural gas taken from the system 10. The power requirements for the system 10 are variable and depend upon the conditions at the wellhead 14, including operating volumes and pressures of the gas being moved through the system 10 and pressures at the wellhead 14 and the size of the compressor 22 employed in the system 10. In one embodiment of the invention, the power produced by the driver 24 may range in capacity from about 5 hp to about 25 hp, depending upon requirements and conditions at the well 12 and the size of the compressor 22.

The compressed gas from the compression system 20 enter the discharge scrubber 44. The discharge scrubber 44 again filters particulates, liquids and unwanted gases, such as carbon dioxide or hydrogen sulfide, from the gas entering the system 10 from the well 12. Various types of scrubbers are suitable for use as the discharge scrubber 44 in the system for deploying and capturing natural gas 10, including spray towers, cyclone spray chambers, venturi scrubbers, orifice scrubbers, impingement scrubbers, packed bed scrubbers, and dry scrubbers. In one embodiment of the invention, the discharge scrubber 44 is a stationary impingement scrubber having a vertical orientation wherein the scrubber liquid and the gas flow in the same direction. It will be appreciated that alternative orientations of the discharge scrubber 44 may also be suitable in the system 10, including horizontal flow, in which the scrubber liquid flows perpendicular to the gas flow, or counter-current flow, in which the scrubber liquid flows opposite the gas flow. Flow orientation can affect collection efficiency, size, pressure drop, and gas velocity. The selection of a discharge scrubber 44 for use in the system for deploying and capturing natural gas 10 will depend upon a variety of factors, including desired gas flow rates through the scrubber, the intended liquid flow rate of the scrubber liquid in the system, minimum particle size of the filtered indicates particulate matter, and the capture rate

The discharge scrubber 44 is in fluid communication with the discharge side 40 of the system 10 and with the discharge pressure regulator 42, which maintains operating pressures at the desired levels on the discharge side 40 of the system and allows excess gas to be released into a flow line 72 for delivery to another system for containing or selling natural gas coming from the well 12. As used herein, the “discharge pressure regulator” 42 means and includes evaporating pressure regulators, condensing pressure regulators, crankcase pressure regulators, capacity regulators, hot-gas bypass regulators, back pressure regulators, vacuum pressure regulators, differential regulators, pressure control valves, pneumatic control valves, electric control valves, or pressure reducing regulators.

One of the primary functions of the discharge pressure regulator 42 is to maintain the desire operating pressure on the pump 60 in the well 12. In one embodiment of the invention, the discharge pressure regulator 42 maintains an operating pressure ranging from about 120 psi to 150 psi, based on conditions at the well 12 and the requirements of the pump 60. The pressure may be lower or higher, based on the amount of lift required to move fluids 13 from the well 12. In one embodiment of the invention, the discharge pressure regulator 42 is primarily responsible for controlling the pressure at the well 12, and the suction pressure regulator 32 supports and works in tandem with the discharge pressure regulator 42 to achieve desired pressures at the well 12. By way of example, but without limitation, the suction pressure regulator 32 may be set to open at about 1 psi (about 0.007 MPa) and to turn off when the pressure on the well 12 reaches zero so that a vacuum is not pulled on the well. The operating pressures of the discharge pressure regulator 42 are based on conditions at the well 12 and preferably are sufficient to hold back pressure needed for the pump 60.

The system 10 may comprise a bypass pressure regulator 48, which opens to allow the bypass of natural gas from the discharge side 40 to the suction side 30 of system 10 when there is insufficient gas available from the wellhead 12 to selectively pressurize the pump 60 or the system 10 overall. After gas is delivered to the compression system 20 from the suction side 30 of the system 10, the compressor 22 compresses gas flowing from the wellhead 14 until the operating pressure set by the discharge pressure regulator 42 is achieved and the pump 60 is activated. If necessary, the bypass pressure regulator 48 will allow gas to circulate from the discharge side 40 of the system 10 to the suction side 30 of the system until a sufficient volume is achieved to fully charge the system at an appropriate operating pressure for the pump 60. At that point, the pump 60 will start delivering fluid from the well bore into the flow line 70, which then goes to a separator/tank facility for normal processing. The bypass pressure regulator 48 circulates gas from the discharge side 40 of the compression system 20 to the suction side 30 of the system 10. As used herein, the “bypass pressure regulator” 48 means and includes evaporating pressure regulators, condensing pressure regulators, crankcase pressure regulators, capacity regulators, hot-gas bypass regulators, back pressure regulators, vacuum pressure regulators, differential regulators, pressure control valves, pneumatic control valves, electric control valves, or pressure reducing regulators. One such bypass pressure regulator 48 employs a spring and piston design, and these are suitable for use in the natural gas capturing and deployment system 10 of the present invention, although it will be appreciated that alternative bypass pressure regulators may be employed in the system.

The bypass pressure regulator 48 maintains constant flow within the closed-loop natural gas capturing and deployment system 10. The bypass pressure regulator 48 allows gas to enter the suction side 30 from the discharge side 40 until the system 10 is fully charged and reaches the desired operating pressure to run the pump 60. When the compressor 22 does not yet have enough volume entering from the well 12 (both annulus and pump exhaust) to operate and continue to build pressure, the bypass pressure regulator 48 will open, when the pressure at the suction side 30 goes below a set pressure, and allow gas to circulate from the discharge side 40 to the suction side 30.

The bypass pressure regulator 48 also provides a back-up to the suction pressure regulator 34. When the pressure on the suction side 30 of the system 10 drops below a certain pressure, the bypass pressure regulator 48 will open to allow gas to enter the suction side 30 from the discharge side 40. If the suction pressure regulator 32 closes to avoid a vacuum on the annulus 19 of the well 12, then the bypass pressure regulator 48 will open to allow gas to circulate until such time as the pressure increases on the annulus 19 and the suction pressure regulator 32 opens to again allow gas to flow from the well 10.

It now will be appreciated that the pump 60 comprises a downhole mechanism that employs gas pressure to lift fluids 13 from the well 12 within a closed-loop, independently from the annular space 19 in the well. The pump 60 additionally may return gas either to the annular space 19 or to the wellhead 14 through a designated line 66 as shown in FIGS. 4C, 5A and 5B. Suitable pumps 60 for use in the gas capturing and deployment system 10 include a gas lift pump or a bubble pump. Alternatives to the pump 60 include a pressure valve and a downhole regulator to lift fluids from the well 12 and which may permit venting into the annulus 19.

It will be appreciated that operation of the pump 60 is isolated from production operations in the annulus 19 of the well 12. Fluids produced from the producing formation of the well 12 are pumped to the surface through a separate tubing string or poly line and are not delivered to the compressor 22. Only gas from the annulus 19 or from the discharge of the pump 60 will be delivered to the suction side 30 of the system 10. Fluids present in the natural gas capturing and deployment system 10 will be from moisture or natural gas condensate dropping out of the gas flow from the well 12 as it is processed through the suction scrubber 34 or through the discharge scrubber 44.

The operation of the pump 60 in connection with the system for capturing and deploying natural gas 10 is now described. Turning now to FIGS. 4A, 4B and 4C and FIGS. 5A, 5B and 5C, a pump 60 having a pump chamber 62 is installed into the well 12 inside the casing (not shown). In one embodiment of the invention, multiple pumps 60 may be installed in the well and are spaced in a manner necessary to produce fluid from multiple desired depths in the well. When multiple pumps 60 are installed, each pump 60 defines a pump stage, wherein each pump is connected to the other pumps. The pump 60 is connected to the wellhead 14 with three tubing strings, or flow lines. A first tubing string 64 delivers compressed gas from the surface 14 at pressure to the pump 60, or to each of the multiple pumps 60 when more than one stage is installed, in the direction s in order to provide the necessary energy to lift fluid 13 from the well 12. A second tubing string 66 is utilized to deliver vented or exhaust gas from the pump 60, or multiple pumps 60, in direction v to the wellhead 14 after each pump cycle, where this gas is combined with annulus gas and delivered to the compression system 20. Each pump 60 vents gas after a pump cycle to release pressure and allow more fluid 13 to enter the pump chamber 62 of the pump 60. A third tubing string 68 is utilized to deliver fluid from the pump 60 to the wellhead 14.

Turning now to FIGS. 4A, 4B and 4C, the filling cycle is described. As shown in FIG. 4A, the pump chamber 62 begins to fill with fluid 13 from the bottom of the pump 60 in direction r. Fluid 13 enters the pump chamber 62 from the annulus 19 or is being lifted by the preceding pump stage. As fluid enters the pump chamber 62, any remaining gas from the preceding cycle is vented through the second tubing string 66 and moves up the second tubing string 66 until it reaches the wellhead 14 at the surface. As shown in FIG. 4B, as the pump cycle progresses, fluid 13 continues to fill the pump chamber 62 from direction r. As fluid 13 fills the pump chamber 62, any remaining gas is vented in direction v through tubing string 66 in order to avoid a build-up of pressure.

As shown in FIGS. 4C and 5A after the pump chamber 62 has filled, a float switch 67 of a pump float 69 is activated which allows compressed gas to enter the pump chamber 62 through tubing string 64 in the direction s in order to displace fluid in the pump 60. With continuing reference to FIG. 4C, as the float switch 67 of the pump float 69 activates the gas pressure, tubing string 66 is closed to keep gas from exiting the pump chamber 62. With continuing reference to FIGS. 4C and 5A, as compressed gas enters the pump chamber 62, it displaces the fluid 13 which has entered the pump 60 and lifts the fluid 13 in the direction u from the pump 60 through the tubing string 68 to the next pump stage, or eventually to the surface.

Turning now to FIGS. 5A, 5B and 5C, the pumping cycle is described. As shown in FIG. 5A, compressed gas continues to displace fluid 13 from the pump chamber 62 up through the tubing string 68 in direction u. As shown in FIG. 5B, fluid 13 continues to be lifted as it is displaced, through the tubing string 68 up to the next pump chamber, in the case of multiple pumps 60, or to the wellhead 14. As shown in FIG. 5C, after the fluid 13 is sufficiently displaced out of the pump chamber 62 by compressed gas, the float switch 67 of the pump float 69 disengages, stopping the flow of gas into the pump 60. At the same time, the float switch 67 deactivates the gas pressure, and the tubing string 66 is opened again to vent gas to from the pump chamber in direction v. Fluid 13 then begins to enter the pump chamber 62 to start another pump cycle.

The desirable operating pressures to charge the natural gas capturing and deployment system 10 depend on the depth and operating conditions at the well 12. For example, if the well is 300 feet deep, only a single-stage pump 60 may be necessary to overcome pressure of the hydrostatic fluid 13 to pump the fluid to the wellhead 14. As used herein, a “stage” means a length of one or more strings of tubing between the pump 60 and the wellhead 14. If the well 12 is 2000 feet deep, eight stages with spacing of 250 feet each may be required. Operating pressures may range from about 50 psi (about 0.34 MPa) to about 200 psi (about 1.4 MPa). Conditions at the well 12 determine operating pressures, the length of the stages and the number of stages. The system 10 of the present invention can operate with multiple stages of tubing and pumps in series and, thus, can operate at lower pressures. When high density polyethylene (HDPE) pipe is used inside the well