Abstract: A gas compressor system is provided to operate at a well site and to inject a compressible fluid into a wellbore in support of a gas-lift operation. Methods and systems are provided that allow for the automated individual control of discharge temperatures from coolers for gas injection, in real time, wherein the temperature control points of the first and/or second stage cooler discharges are automatically controlled by a process controller in order to push heat produced by adiabatic compression to a third or final compression stage. In this way, discharge temperatures at the final stage are elevated to maintain injection gaseous mixtures in vapor phase.

Abstract: A controlled production fluids separator. The separator is configured to be placed in fluid communication with a production fluids flow line coming off of a well head. The separator includes an inlet configured to receive fluids from the flow line. The separator has a water dump valve and an oil dump valve. The separator further has a gas outlet residing along the upper surface of the vessel. The gas outlet comprises a valve configured to open and close in response to control signals. In this way, the valve serves as a back-pressure regulator valve for the separator. The separator also includes a controller. The controller is configured to periodically receive data indicative of fluid flow through the flow line, and adjust a back-pressure setpoint in real time by sending signals to the back-pressure regulator valve for opening and closing. A method of operating a three-phase production fluids separator is also provided.

Abstract: A gas compressor system is provided to operate at a well site and to inject a compressible fluid into a wellbore in support of a gas-lift operation. Methods and systems are provided that allow for the automated individual control of discharge temperatures from coolers for gas injection, in real time, wherein the temperature control points of the first and/or second stage cooler discharges are automatically controlled by a process controller in order to push heat produced by adiabatic compression to a third or final compression stage. In this way, discharge temperatures at the final stage are elevated to maintain injection gaseous mixtures in vapor phase.

Abstract: A gas injection optimization system is provided. The optimization system is designed to control a volume of gas injected into a wellbore in connection with an intermittent gas-lift system. The system includes a gas storage vessel residing at the surface, and a series of pressure transducers. The system additionally includes a controller configured to receive pressure value signals from the transducers, and in response, send control signals that cyclically open and close a well flow control valve at the surface. When the well flow control valve is closed, compressible fluid is injected into the gas storage vessel to load the vessel. When the well flow control valve is opened, a volume of injection gas (VR) is released from the vessel and is injected into a wellbore annular region to push a volume of fluids (VS) residing in the tubing string to the surface. A method for optimizing gas injection into a wellbore in support of an intermittent gas-lift operation is also provided herein.

Abstract: A gas emissions recovery system. The recovery system is designed to receive fugitive gas emissions from a compressor, and pressurize those emissions using a double-acting liquid piston compressor system. The pressurized fugitive gas emissions may be returned to the compressor, or may be injected into a wellbore. The system includes a first liquid piston chamber and a second liquid piston chamber. Each chamber holds an incompressible fluid that is used to force a gas into a fluid reservoir in response to a piston motion of the incompressible fluid. A pump is provided, with the pump being configured to pump the incompressible fluid between the first and second liquid piston chambers and, thereby, induce piston action of the incompressible fluid in the liquid piston chambers. The system includes a processor that controls the cycling of the incompressible fluid in response to signals indicative of liquid levels in the chambers. A method for reclaiming fugitive gas emissions from a compressor is also provided.

Abstract: A gas compressor system is provided to operate at a well site and to inject a compressible fluid into a wellbore in support of a gas-lift operation. Methods and systems are provided that allow for the automated individual control of discharge temperatures from coolers for gas injection, in real time, wherein the temperature control points of the first and/or second stage cooler discharges are automatically controlled by a process controller in order to push heat produced by adiabatic compression to a third or final compression stage. In this way, discharge temperatures at the final stage are elevated to maintain injection gaseous mixtures in vapor phase.

Abstract: A closed loop pneumatic pumping system is provided. The system uses a gas compressor and a high pressure gas tank to exert pneumatic pressure against a reciprocating piston over a wellbore. The piston is connected to a rod string and downhole pump for pumping formation fluids from a wellbore. The system includes an electronic controller that controls movement, including pump speed of the piston as it cycles between upstrokes and downstrokes within a cylinder over the wellbore. In one aspect, speed is controlled by adjusting a speed of the compressor. In another aspect, speed is controlled by adjusting the position of an upstroke control valve and a downstroke control valve. In one aspect, the pump stroke controller is configured to adjust a speed of the upstroke and a speed of the downstroke in response to signals indicative of pump fillage. A method for optimizing pneumatic pumping speed at a wellbore is also provided herein.

Abstract: A controlled production fluids separator. The separator is configured to be placed in fluid communication with a production fluids flow line coming off of a well head. The separator includes an inlet configured to receive fluids from the flow line. The separator has a water dump valve and an oil dump valve. The separator further has a gas outlet residing along the upper surface of the vessel. The gas outlet comprises a valve configured to open and close in response to control signals. In this way, the valve serves as a back-pressure regulator valve for the separator. The separator also includes a controller. The controller is configured to periodically receive data indicative of fluid flow through the flow line, and adjust a back-pressure setpoint in real time by sending signals to the back-pressure regulator valve for opening and closing. A method of operating a three-phase production fluids separator is also provided.

Abstract: A gas compression optimization system and a method for optimizing gas injection rate in support of a gas lift operation. The optimization system is designed to control a rate of gas injection in connection with a gas lift system in a wellbore. The system includes a string of production tubing, and an annular region around the production tubing. The system also comprises a production line at the surface. The system further includes a pressure transducer that is configured to determine a differential pressure across an orifice plate placed along the production line. The system additionally includes a gas injection line. The gas injection line is at the surface, and is configured to inject a compressible fluid into the annular region. The system additionally includes a controller which is configured to control the injection of the compressible fluid into the annular region in response to differential pressure signals.

Abstract: A gas injection optimization system is provided. The optimization system is designed to control a volume of gas injected into a wellbore in connection with an intermittent gas-lift system. The system includes a gas storage vessel residing at the surface, and a series of pressure transducers. The system additionally includes a controller configured to receive pressure value signals from the transducers, and in response, send control signals that cyclically open and close a well flow control valve at the surface. When the well flow control valve is closed, compressible fluid is injected into the gas storage vessel to load the vessel. When the well flow control valve is opened, a volume of injection gas (VR) is released from the vessel and is injected into a wellbore annular region to push a volume of fluids (VS) residing in the tubing string to the surface. A method for optimizing gas injection into a wellbore in support of an intermittent gas-lift operation is also provided herein.

Abstract: A gas emissions recovery system is provided. The recovery system is designed to receive fugitive gas emissions from a compressor, and pressurize those emissions using a double-acting liquid piston compressor system. The pressurized fugitive gas emissions may be returned to the compressor, or may be injected into a wellbore. The system includes a first liquid piston chamber and a second liquid piston chamber. Each chamber hold an incompressible fluid that is used to force a gas into a fluid reservoir in response to a piston motion of the incompressible fluid. A pump is provided, with the pump being configured to pump the incompressible fluid between the first and second liquid piston chambers and, thereby, induce piston action of the incompressible fluid in the liquid piston chambers. The system includes a processor that controls the cycling of the incompressible fluid in response to signals indicative of liquid levels in the chambers.

Abstract: A gas compressor system is provided to operate at a well site and to inject a compressible fluid into a wellbore in support of a gas-lift operation. Methods and systems are provided that allow for the automated individual control of discharge temperatures from coolers for gas injection, in real time, wherein the temperature control points of the first and/or second stage cooler discharges are automatically controlled by a process controller in order to push heat produced by adiabatic compression to a third or final compression stage. In this way, discharge temperatures at the final stage are elevated to maintain injection gaseous mixtures in vapor phase.

Abstract: A closed loop pneumatic pumping system is provided. The system uses a gas compressor and a high pressure gas tank to exert pneumatic pressure against a reciprocating piston over a wellbore. The piston is connected to a rod string and downhole pump for pumping formation fluids from a wellbore. The system includes an electronic controller that controls movement, including pump speed of the piston as it cycles between upstrokes and downstrokes within a cylinder over the wellbore. In one aspect, speed is controlled by adjusting a speed of the compressor. In another aspect, speed is controlled by adjusting the position of an upstroke control valve and a downstroke control valve. In one aspect, the pump stroke controller is configured to adjust a speed of the upstroke and a speed of the downstroke in response to signals indicative of pump fillage. A method for optimizing pneumatic pumping speed at a wellbore is also provided herein.

Abstract: A gas compression optimization system is provided. The optimization system is designed to control a rate of gas injection in connection with a gas lift system in a wellbore. The system includes a string of production tubing, and an annular region around the production tubing. The system also comprises a production line at the surface. The system also includes a pressure transducer that is configured to determine a differential pressure across an orifice plate placed along the production line. The system additionally includes a gas injection line. The gas injection line is at the surface, and is configured to inject a compressible fluid into the annular region. The system additionally includes a controller. The controller is configured to control the injection of the compressible fluid into the annular region in response to the differential pressure signals. A method for optimizing gas injection rate into a wellbore in support of a gas lift operation also provided herein.

Abstract: An oil well pumping system having stroke optimization is provided. The system includes a downhole pump residing within a wellbore, and a rod string extending down into the wellbore and connected to the pump. The system also includes a well head having an actuator configured to reciprocate the rod string and connected downhole pump as upstrokes and as downstrokes, and a pump stroke controller. The pump stroke controller is configured to adjust a speed of the upstroke and a speed of the downstroke in response to signals indicative of pump fillage. In one aspect, the pump stroke controller tunes the pumping speed to match an average in-flow of production fluids into the pump over a multiple hour period to provide an optimum speed. A method for optimizing pumping speed at a wellbore is also provided herein.

Abstract: A system and method for capturing lift gas in wells with small formation gas production. The system includes a separator for separating gases from wellbore fluid and a vessel for accumulating the separated gas. The system also includes a switch that directs fluid from the vessel to a wellbore upon attainment of a condition, such as a certain pressure in the vessel. The method includes the steps of separating gas from a wellbore fluid, directing the gas to an accumulation vessel, and directing the gas from the vessel to a wellbore upon attainment of a condition, such as a certain pressure in the vessel.

Abstract: Gas in association with liquids is produced from a wellbore by disposing a first tubing string having a first fluid communication path into the wellbore to near or below the bottom of a producing zone, disposing within the annulus between the first tubing string and the outer surface of the wellbore a second fluid communication path from near or below the bottom of the producing zone to an offtake line at the surface, disposing a choke means in at least one of the fluid communication paths, and producing gas while controlling the choke means to establish sufficient gas flow up the first fluid communication path so as to unload liquids from near or below the bottom of the producing zone and produce the liquids up the first tubing string in association with gas flow. In accordance with a preferred embodiment, the first tubing string has a sufficiently small diameter that liquids can be unloaded from the well over life of the production.