20 results about "Artificial lift" patented technology

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 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.

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.

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 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.

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.

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.

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.

The application discloses a kind of to industrial dangerous waste is carried out incineration processing equipment, including base, the left end upper side wall of the base is fixedly connected with screening box, the inner wall of the screening box is fixedly installed with sieve plate, the upper top wall of the screening box is fixedly inserted with feed pipe, the upper side wall of the sieve plate is fixedly connected with the flow splitter located just below feed pipe, the outer side wall of the screening box is fixedly connected with mounting plate symmetrically, the lower side wall of two The mounting plate is fixedly connected with vertical plate.The device in the screening box makes the industrial solid dangerous waste be subdivided into particles, so that the industrial solid dangerous waste can be synchronized in the combustion of particles of the same size, so that it can be fully combusted, reduce the use of fuel, and then reduce the cost, and the upward movement of lifting plate, so as to facilitate manual addition of industrial solid dangerous waste to incineration box, reduce the labor of manual lifting, thereby effectively improving work efficiency.

A gas avoiding device for use in downhole fluid flow systems is disclosed. The device includes an inner tube with inlet ports that draw well fluid from an annular space surrounding the tube for conveyance towards an artificial lift system. A baffle greater than two feet in length surrounds the inner tube to define an annular flow space, the baffle having at least one intake port through which well fluid enters, a closed base preventing entry from below, and vent ports arranged axially above the intake port to discharge gas from the annular space into the surrounding well annulus. Upper and lower centralizers maintain clearance between the baffle and the well bore wall. The baffle is mounted to rotate freely about the inner tube, thereby orienting the intake port preferentially to draw liquid-rich fluid and minimize gas ingestion.

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.

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.

The invention belongs to the technical field of oil and gas exploitation and pressurized transportation, and discloses a lead screw nut driving structure of an electric submersible pump and a vibration signal extraction method. According to the structure, a lead screw end piston capable of freely moving up and down is arranged in a pump cylinder, and the lead screw end piston is connected with a polished rod; the polish rod is connected to the upper end of the lead screw and forms a plunger structure with the pump cylinder and the lead screw end piston; the lead screw penetrates through and is in threaded connection with the interior of the nut sleeve; a motor shaft is connected with the nut sleeve through a coupler; when the motor drives the nut sleeve to rotate, the lead screw and the polish rod are driven to move in the axial direction, and vibration sensors are arranged in the pump cylinder and the nut sleeve and used for collecting vibration signals and extracting fault features. The thrust performance, the abrasion resistance and the sealing performance are effectively improved, and a more reliable and efficient technical solution is provided for manual lifting of a deep well and a high-load oil well. According to the vibration fault feature extraction method, the accuracy and the real-time performance of fault diagnosis are improved.

The utility model relates to the technical field of oil gas manual lifting, in particular to a plug-in type connecting rod. The plug-in type connecting rod comprises the first end, the rod body, the abutting part and the second end which are sequentially connected, the plug-in type connecting rod is matched with the coupling detachably arranged on the rod body in a sleeving mode, the convenience of installation and maintenance is greatly improved, meanwhile, the complex step that in the traditional sucker rod production process, the rod body is sleeved with the coupling, and then follow-up machining is conducted is avoided, and the production efficiency is improved. Independent machining of all the components can be completed firstly, then assembling is conducted, and the working procedure is effectively simplified.

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.