53 results about "Artificial lift" patented technology

An artificial lift apparatus includes an ESP sub-assembly, shut-in valve (SIV) subassembly, and a pressure sensor, each operatively connected to a common electrical line. The ESP sub-assembly includes a pump and an ESP motor configured to receive electrical current from the common electrical line thereby drive the pump to pump fluids from the intake in an uphole direction through the production tubing string. The SIV sub-assembly includes a sliding sleeve connected to a linear actuator driven by an electric valve motor which receives electrical current from the common electrical line and drives the actuator translate the sliding sleeve to modulate fluid flow. The system is configured such that pressure data from the pressure sensor can be received at the surface via the common electrical line.

Described herein are embodiments of an improved bypass lubricator. The lubricator may include a body having a bore, where the bore may include at least an upper exit bore and a lower exit bore. The lubricator may also include an exit flow path that also has a bore, wherein the bore of the exit flow path is in fluid communication with the upper exit bore, the lower exit bore, and an exit valve. The upper exit bore and the lower exit bore may be sized relative to one another to create a pressure differential between the upper and lower exit bores to assist in maintaining an artificial lift device in the lubricator's body. Shutting the exit valve shuts in the well.

A method of lubricating a fluid production pump may include mixing a polarized lubricant with water to produce a diluted lubricant. The method may additionally include creating a flowpath within the fluid production pump. An initial volume of the diluted lubricant may be circulated within the flowpath to allow the diluted lubricant to react with components of the fluid production pump and form a protective barrier on the components of the fluid production pump. The method may further comprise repeatedly introducing a periodic volume of diluted lubricant into the fluid production pump according to a predefined lubrication schedule.

A method of lubricating a fluid production pump may include mixing a polarized lubricant with water to produce a diluted lubricant. The method may additionally include creating a flowpath within the fluid production pump. An initial volume of the diluted lubricant may be circulated within the flowpath to allow the diluted lubricant to react with components of the fluid production pump and form a protective barrier on the components of the fluid production pump. The method may further comprise repeatedly introducing a periodic volume of diluted lubricant into the fluid production pump according to a predefined lubrication schedule.

A system for oil and gas production includes a drilling, pipeline, or power quality device, a sensor, and a storage device. The storage device has instructions stored thereon that, when executed by one or more processors, cause the one or more processors to perform operations. The operations include receiving first data from the sensor. The operations include determining whether the device is experiencing an event condition based on the first data The operations include generating one or more potential corrective actions responsive to a determination that the device is experiencing the event condition. The operations include calculating a reward value for each of the one or more potential corrective actions. The operations include identifying a first corrective action of the one or more potential corrective actions with a largest or most positive reward value The operations include controlling the device according to the first corrective action.

Various examples are provided related to airlift pumping of downhole geothermal fluids. In one example, an airlift system includes a compressor; a gas sparger head in a wellbore of a geothermal well, and a pressure head recycle assembly. The sparger head produces artificial lift of the geothermal fluids by injecting a gas resulting in a difference in density downhole. The entrained gas can be extracted by the pressure head recycle assembly, compressed, and reinjected downhole. The geothermal fluid at the well head can be used in direct use applications or in a thermodynamic cycle to make shaft power. The gas sparger head can include a venturi shaped passage extending through the gas sparger head and a bubble orifice including gas orifices radially spaced about a narrow portion of the venturi shaped passage. The gas orifices can have a corresponding resonant chamber through which the gas (e.g., air) is provided.

A method of lubricating a fluid production pump may include mixing a polarized lubricant with water to produce a diluted lubricant. The method may additionally include creating a flowpath within the fluid production pump. An initial volume of the diluted lubricant may be circulated within the flowpath to allow the diluted lubricant to react with components of the fluid production pump and form a protective barrier on the components of the fluid production pump. The method may further comprise repeatedly introducing a periodic volume of diluted lubricant into the fluid production pump according to a predefined lubrication schedule.

The invention discloses a method for determining optimal flow pressure and discharge and mining time of a gas well based on numerical reservoir simulation, which belongs to the technical field of oil and gas exploitation, and is characterized by comprising the following steps: a, in the numerical reservoir simulation process, calculating a gas phase flow capability index GFI representing near-well gas phase flow efficiency; b, calculating the ratio R (liquid-carrying coefficient) of the current actual gas production rate to the critical liquid-carrying gas production rate; c, analyzing the change trend of the GFI and the absolute value of the R value; and d, outputting a decision instruction for flow pressure control or manual lifting intervention of the gas well based on a collaborative analysis result of the GFI trend and the R value. According to the method, the gas phase flow efficiency of the near wellbore zone is quantified by defining the gas phase flow capacity index (GFI), a dual-signal collaborative decision-making mechanism is constructed in combination with the wellbore liquid carrying coefficient (R), and flow pressure optimization and prospective judgment of drainage and mining opportunities are achieved.

An improved apparatus and methods of use for rotating a reciprocating rod string used in artificial lift pumping equipment is provided, the apparatus having a modified worm wheel for receiving a mechanical interlock formed between the worm wheel at the rod clamps secured to, and operative to rotate, the rod string.

An artificial lift apparatus includes an ESP sub-assembly, shut-in valve (SIV) subassembly, and a pressure sensor, each operatively connected to a common electrical line. The ESP sub-assembly includes a pump and an ESP motor configured to receive electrical current from the common electrical line thereby drive the pump to pump fluids from the intake in an uphole direction through the production tubing string. The SIV sub-assembly includes a sliding sleeve connected to a linear actuator driven by an electric valve motor which receives electrical current from the common electrical line and drives the actuator translate the sliding sleeve to modulate fluid flow. The system is configured such that pressure data from the pressure sensor can be received at the surface via the common electrical line.

A pump comprising a plurality of impellers stacked on top of each other via a pump shaft, a diffuser corresponding to each impeller, a body housing the impellers, the diffusers, and the pump shaft, and a protector thrust bearing at one end of the pump shaft.

Embodiments are directed towards a lift system for extracting a fluid from a well. The system may include a production tube and at least one bladder located inside a pump barrel which is connected to the production tube. The bladder may include a top connector configured to receive a concentric tubing. The lift system may further include a compression system connected to the concentric tubing. The compression system may be configured to provide a compressed gas through the concentric tubing to the at least one bladder.

A sand separator system is utilized in an artificial lift pumping system, where the sand separator system includes a perforated inlet, a separator casing coupled to the perforated inlet, a pump inlet tubing disposed through a central bore of the perforated inlet and forming an annulus with the separator casing, a helical auger component disposed at a distal end of the pump inlet tubing, and a spigot disposed downhole from the helical auger component. The spigot includes a head, a stem extending from the head, and a body portion coupled to a distal end of the stem and having fluid flow passages extending therethrough. The sand separator system is capable of removing at least 55% of the sand particles from a produced hydrocarbon fluid.

The invention discloses an anti-airlock fracturing production integrated tubular column of a throwing and fishing electric pump and an operation method. The device comprises an outer sleeve; the tie-back barrel, the drilling liner hanger and the lower inner sleeve are sequentially connected from top to bottom; a differential pressure sliding sleeve is arranged at the toe end of the lower inner sleeve; the upper inner casing pipe is sequentially provided with a large-drift-diameter hydraulic control sliding sleeve, a deep well large-drift-diameter subsurface safety valve, a large-drift-diameter hydraulic control stratum isolation valve, a tie-back casing pipe anchor and an insertion seal from top to bottom. A plurality of bridge plugs are pumped into the lower inner casing pipe in batches through the upper inner casing pipe and used for conducting clustering perforation fracturing operation; the electric pump pipe column is sequentially provided with a composite pipe cable, a production packer and an electric pump unit from top to bottom; the electric pump pipe column is arranged in the inner upper casing pipe through the composite pipe cable, and the production packer is located above the large-drift-diameter hydraulic control sliding sleeve. The device has the beneficial effects that multi-layer-section separate layer fracturing of one pipe column can be achieved, after fracturing, the pipe column is immovable, manual lifting is rapidly conducted, and the phenomenon that a well killing fluid pollutes a reservoir is prevented.

A method of designing an artificial lift system for producing fluid from a wellbore includes receiving wellbore data indicating configuration specifications and production specifications for the wellbore and identifying a plurality of candidate electrical submersible pump (ESP) designs for implementing in the wellbore based on the wellbore data. The method further includes determining a design score for each of the plurality of candidate ESP designs, the candidate ESP designs each indicating a collection of downhole components defining an ESP system. The design score is based on inventory data for an inventory of available downhole components and historical wellbore data, the historical wellbore data indicating historical conditions for the wellbore and historical production performance for the wellbore. The method further includes selecting an ESP design from the plurality of candidate ESP designs based on an associated design score best fulfilling one or more criteria.

A sand separator system is utilized in an artificial lift pumping system, where the sand separator system includes a perforated inlet, a separator casing coupled to the perforated inlet, a pump inlet tubing disposed through a central bore of the perforated inlet and forming an annulus with the separator casing, a helical auger component disposed at a distal end of the pump inlet tubing, and a spigot disposed downhole from the helical auger component. The spigot includes a head, a stem extending from the head, and a body portion coupled to a distal end of the stem and having fluid flow passages extending therethrough. The sand separator system is capable of removing at least 55% of the sand particles from a produced hydrocarbon fluid.

A method of operating an artificial lift system producing fluid from a wellbore is provided. The artificial lift system comprises a reciprocating downhole pump. The method comprises monitoring one or more properties indicative of a fluid level characteristic of the wellbore. A set of operational parameters for the pump may be selected at least partly based on the monitored one or more properties. The set of operational parameters comprises pump operation setpoints and rules for automatically adjusting one or more of the pump operation setpoints. The pump operation setpoints comprise a respective upper pumping speed limit; a respective lower pumping speed limit; and a respective pumping speed rate of change. The method further comprises controlling operation of the pump as a function of the set of operational parameters.

Embodiments are directed towards a lift system for extracting a fluid from a well. The system may include a production tube and at least one bladder located inside a pump barrel which is connected to the production tube. The bladder may include a top connector configured to receive a concentric tubing. The lift system may further include a compression system connected to the concentric tubing. The compression system may be configured to provide a compressed gas through the concentric tubing to the at least one bladder.

A spool assembly alternately lowers an oleophilic absorbent material into a hydrocarbon-bearing fluid column in a wellbore and winds the material onto the spool, releasing the hydrocarbon-bearing fluid into a tank at the surface.

Processing device-based systems and methods for controlling an electric motor of an electric submersible pump system in a balanced current condition using a variable speed drive despite an impedance imbalance of an electric cable connecting the electric motor to the variable speed drive. The systems and methods can utilize estimated motor shaft angular position and speed values, as well as values of three-phase motor currents measured at an output of an inverter of the variable speed drive as input information. Positive-sequence and negative-sequence current components may be extracted from measured current values and compared to reference values. The system provides an overall voltage command in the abc reference frame to a pulse width modulation controller, which generates an inverter switching pattern that will control the electric motor of the electric submersible pump system in a balanced current condition.

An apparatus (36) for use in performing an artificial lift operation in a fluid conduit system (14) comprises a flexible hose (38), an injector arrangement (40) for deploying the flexible hose (38) into the fluid conduit system (14), and a hanger arrangement (42) configured to support the flexible hose (38) in the fluid conduit system (14). The flexible hose (38) has a smaller outer diameter than the inner diameter of the fluid conduit system (14) so as to facilitate deployment of the flexible hose (38) into the fluid conduit system (38), the flexible hose (38) reducing the flow area in the fluid conduit system (14) such that a flow velocity of the fluid in the fluid conduit system (14) or the flexible hose (38) increases, thereby facilitating artificial lift of fluid from the fluid conduit system (14).

A fluid recovery system is configured to assist with the recovery of hydrocarbons or other fluids from a well. The fluid recovery system includes an electric submersible pumping system, a chemical injection system and an integrated control system. The electric submersible pumping system includes an electric motor, a pump driven by the electric motor and a motor drive configured to control the operation of the electric motor. The electric submersible pumping system includes a signal processing module that is configured to detect a sand slugging event by identifying a sand slugging signature in frequency spectrums derived from the current drawn by the motor from the motor drive. The integrated control system is configured to automatically cause the chemical injection system to increase the injection of treatment chemicals into the well if a sand slugging event is detected.

Processing device-based systems and methods for controlling an electric motor of an electric submersible pump system in a balanced current condition using a variable speed drive despite an impedance imbalance of an electric cable connecting the electric motor to the variable speed drive. The systems and methods can utilize estimated motor shaft angular position and speed values, as well as values of three-phase motor currents measured at an output of an inverter of the variable speed drive as input information. Positive-sequence and negative-sequence current components may be extracted from measured current values and compared to reference values. The system provides an overall voltage command in the abc reference frame to a pulse width modulation controller, which generates an inverter switching pattern that will control the electric motor of the electric submersible pump system in a balanced current condition.

Some implementations include a method for controlling a computer system configured to detect scaling and / or plugging of an electric submersible pump (ESP) deployed in a wellbore. The method may include determining, based on a measurement of pressure in the wellbore, a required total dynamic head (RTDH) for the ESP while the ESP is operating in the wellbore. The method also may include determining, based on information from one or more sensors in the ESP, a produced total dynamic head (PTDH) for the ESP while the ESP is operating in the wellbore. The method also may include detecting scaling status or plugging status of the ESP based on the RTDH and the PTDH.

A system for oil and gas production includes a drilling, pipeline, or power quality equipment, a sensor, and a storage device having instructions stored thereon that, when executed by one or more processors, cause the one or more processors to perform operations. The operations include receiving first data from the sensor, determining whether the drilling, pipeline, or power quality equipment is experiencing an event condition based on the first data, generating one or more potential corrective actions, identifying a first corrective action of the one or more potential corrective actions, and controlling a fluid transfer device to implement the first corrective action. The first corrective action includes at least one of increasing a drive frequency of the fluid transfer device, adjusting a choke position of the fluid transfer device, or reversing a rotational direction of an impeller of the fluid transfer device.

A fluid end is coupled to and configured to be driven by an electric motor. A shear interconnect is at an uphole end of the electric submersible pump. The shear interconnect is configured to shear a cable line between the electric submersible pump and a topside facility. The shear interconnect is configured to shear the cable at the electric submersible pump. A safety valve is arranged to cease flow within a wellbore, in which the electric submersible pump is installed, when the safety valve is in a closed position.

Various examples are provided related to airlift pumping of downhole geothermal fluids. In one example, an airlift system includes a compressor; a gas sparger head in a wellbore of a geothermal well, and a pressure head recycle assembly. The sparger head produces artificial lift of the geothermal fluids by injecting a gas resulting in a difference in density downhole. The entrained gas can be extracted by the pressure head recycle assembly, compressed, and reinjected downhole. The geothermal fluid at the well head can be used in direct use applications or in a thermodynamic cycle to make shaft power. The gas sparger head can include a venturi shaped passage extending through the gas sparger head and a bubble orifice including gas orifices radially spaced about a narrow portion of the venturi shaped passage. The gas orifices can have a corresponding resonant chamber through which the gas (e.g., air) is provided.

The present disclosure relates to a wellhead tree configuration comprising a tubing head fluidly connected to a first studded tee through a tubing head adaptor; the first studded tee fluidly connected to a tree cap; a studded cross fluidly connected to the first studded tee through a first spacer spool; a second studded tee fluidly connected to the studded cross through a first gate valve; a third studded tee fluidly connected to the second studded tee through a second spacer tool; a fourth studded tee fluidly connected to: the third studded tree through a second gate valve; and the studded cross through a third gate valve and a fourth gate valve, wherein the third gate valve extends outward from the fourth studded tee, and wherein the fourth gate valve extends outward from the studded cross; and the tubing head through a fifth gate valve.

Gravity assisted reservoir drainage systems and methods, which improve preexisting reservoir drainage systems and artificial lift methods using the interwell hydraulic communication that exists between closely spaced horizontal wells in certain fully developed leases completed with large multi-stage hydraulic fracture treatments in batch fashion.

An apparatus 36 for use in performing an artificial lift operation in a fluid conduit system 14 comprises a flexible hose 38, an injector arrangement 40 for deploying the flexible hose into the fluid