HYBRID HYDROCARBON LIFT SYSTEM AND METHOD

Abstract

A system for hybrid gas lifting may include a gas-lift completion arranged to inject high-pressure gas into production tubing of a well. The system may include a downhole annular jet pump. The downhole annular jet pump may include an annular nozzle arranged to receive the injected high-pressure gas. The injected high-pressure gas exits the annular nozzle as an annular high-velocity gas jet. The downhole annular jet pump may include a throat section arranged to receive the annular high-velocity gas jet, and to mix the annular high-velocity gas jet with a low-pressure production fluid. The downhole annular jet pump may include a diffuser section arranged to facilitate conversion of kinetic energy into pressure energy in a mixture of the annular high-velocity gas jet and the low-pressure production fluid, and to produce the mixture to a surface via the production tubing.

Description

BACKGROUND

In the petroleum industry, the gas lift mechanism is used to increase the flow of fluids, such as crude oil, from a production well. Initially, hydrocarbons flow to the surface unaided when the reservoir energy is sufficient. As the water cut in the produced fluid increases over time, the reservoir energy drops and may not be sufficient to overcome the hydrostatic pressure of the fluid column. The hydrocarbon flow to the surface ceases at this point.

The injection of high-pressure gas from the surface into the downhole tubing reduces the density of the fluid column which, in turn, reduces the hydrostatic pressure. As a result, the fluid flow to the surface is restored. Conventionally, this process is known as “gas lift.” However, even in the presence of injected gas, the well production still depends on reservoir energy or pressure. As the reservoir energy or pressure is depleted in the later part of the life of an oil field, the gas lift mechanism is no longer effective. When the gas lift mechanism ceases to work, other forms of artificial lift technologies, such as sucker rod pumps or electric submersible pumps (ESP), may be used to replace gas lift. These other forms of artificial lift methods could add energy to the production fluids and allow the wells to produce to field abandonment pressures.

Accordingly, there is a need for a system that provides improvements over the conventional gas lift systems by providing a way to increase the energy of the production fluids where using solely gas lift is no longer effective to increase the flow of the production fluids to the surface.

SUMMARY

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

In general, in one aspect, embodiments disclosed herein relate to a system for hybrid gas lifting. The system includes a gas-lift completion arranged to inject high-pressure gas into production tubing of a well. The system includes a downhole annular jet pump. The downhole annular jet pump includes an annular nozzle arranged to receive the injected high-pressure gas. The injected high-pressure gas exits the annular nozzle as an annular high-velocity gas jet. The downhole annular jet pump includes a throat section arranged to receive the annular high-velocity gas jet, and to mix the annular high-velocity gas jet with a low-pressure production fluid. The downhole annular jet pump includes a diffuser section arranged to facilitate conversion of kinetic energy into pressure energy in a mixture of the annular high-velocity gas jet and the low-pressure production fluid, and to produce the mixture to a surface via the production tubing.

In general, in one aspect, embodiments disclosed herein relate to a method for hybrid gas lifting. The method includes injecting, by a gas-lift completion, high-pressure gas into production tubing of a well. The method includes receiving, by an annular nozzle included in a downhole annular jet pump, the injected high-pressure gas. The injected high-pressure gas exits the annular nozzle as an annular high-velocity gas jet. The method includes receiving, by a throat section included in the downhole annular jet pump, the annular high-velocity gas jet. The method includes mixing, by the throat section included in the downhole annular jet pump, the annular high-velocity gas jet with a low-pressure production fluid. The method includes facilitating conversion, by a diffuser section included in the downhole annular jet pump, of kinetic energy into pressure energy in a mixture of the annular high-velocity gas jet and the low-pressure production fluid. The method includes producing, by the diffuser section included in the downhole annular jet pump, the mixture to a surface via the production tubing.

Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

Some embodiments are illustrated by way of example and not limitation in the figures of the accompanying drawings.

FIG. 1 is a schematic illustration of a well environment, according to one or more example embodiments.

FIG. 2 is a schematic illustration of a hybrid lift system, according to one or more example embodiments.

FIG. 3 is a schematic illustration of the hybrid lift system, according to one or more example embodiments.

FIG. 4 is a flowchart illustrating operations of the hybrid lift system in performing a method for increasing the energy of the production fluids to cause the flow of the production fluids to the surface, according to one or more example embodiments.

FIGS. 5A and 5B illustrate a computing system, according to one or more example embodiments.

DETAILED DESCRIPTION

Example systems and methods for increasing the energy of the production fluids to cause the flow of the production fluids to the surface are described. Unless explicitly stated otherwise, components and functions are optional and may be combined or subdivided. Similarly, operations may be combined or subdivided, and their sequence may vary.

In the following detailed description of embodiments of the disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the disclosure. However, it will be apparent to one of ordinary skill in the art that the disclosure may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.

Throughout the application, ordinal numbers (e.g., first, second, or third) may be used as an adjective for an element (that is, any noun in the application). The use of ordinal numbers is not to imply or create any particular ordering of the elements nor to limit any element to being only a single element unless expressly disclosed, such as using the terms “before,” “after,” “single,” and other such terminology. Rather, the use of ordinal numbers is to distinguish between the elements. By way of an example, a first element is distinct from a second element, and the first element may encompass more than one element and succeed (or precede) the second element in an ordering of elements.

The gas lift mechanism utilizes gas injected from the surface to aerate and reduce the wellbore fluid density and the weight of the fluid column acting upon the sandface of a reservoir. This reduces the well bottomhole pressure below the reservoir static pressure, which allows the well to sustain or increase production. Because the reservoir pressure (i.e., the native energy of the well) is still the source of energy required to lift reservoir fluids to the surface, if the reservoir pressure is too low, gas lift may not be effective to assist bringing the reservoir fluids to the surface.

In some instances, the gas is injected continuously. In other instances, the gas is injected intermittently, when the well can no longer produce enough hydrocarbons to sustain continuous flow to the surface. According to some example embodiments, when using a continuous gas lift completion, a plurality of valves may be installed in the tubing-casing annulus of the well, along the production tubing. The deepest installed valve may be an operating valve. Above it, there may be several unloading valves spread out along the production tubing. The unloading valves are used to reduce the gas injection pressure and meet a compression requirement. Once heavy fluids, such as a completion or workover fluid, in the portion of the wellbore above the injection point of an upper unloading valve is aerated and lifted to the surface, the upper unloading valve is shut off, and the injected gas is delivered to the next, lower unloading valve. This process continues until all the unloading valves are closed off and the injected gas is delivered to the operating valve to sustain well production. These valves can be deployed either via tubing or wireline (e.g., side-pocket mandrels) deployable and retrievable. In the case of tubing-deployable valves, a workover rig may be used to pull out the valve that requires changing or replacement. With respect to wireline-deployable valves, valve replacement can be done without the rig (“riglessly”), using a wireline conveyance system.

The unloading valves may include Injection Pressure Operated (IPO) valves. They open and close based on the injection pressure and nitrogen (N2) charged dome set pressure. The types of valves used as operating valves may include square-edge office valves and Venturi valves. The operating valve remains open. A check valve may be combined with the operating valve to prevent back flow from the tubing into the tubing-casing annulus. The Venturi valves allow critical flow to occur earlier with small pressure differential across the valve. At critical flow, the injection rate is a function of the injection pressure and the venturi size, independent of the tubing pressure so that tubing pressure fluctuation does not affect the gas injection rate. Venturi valves can be operated in critical flow or subcritical flow, depending on the pressure ratio (i.e., the pressure at the venturi throat divided by the venturi inlet pressure). If the pressure ratio is greater than the critical pressure ratio, critical flow will occur where the gas injection rate is no longer depending on tubing pressure.

The jet pump is a type of hydraulic lift technique. A jet pump mechanism utilizes a primary high-pressure power fluid flow and a secondary low-pressure process (or well) fluid flow to generate an intermediate-pressure power combined fluid flow at the exit of the jet pump mechanism. The components of a jet pump include a nozzle section, a throat (or a mixing tube) section, and a diffuser section. The power fluid is directed through the nozzle section and exits the nozzle section at a high velocity. As the power fluid exits the nozzle section, it enters the throat section. In the throat section, the high-pressure power fluid mixes with the low-pressure well fluid, and, as a result, the power fluid pressure changes from high pressure to lower pressure. As the pressure of the power fluid decreases, the velocity of the power fluid increases. The high velocity of the power fluid jet produces a dragging action on the well fluid, resulting in the transfer of momentum and energy between the two streams of fluids and forcing the well fluid to accelerate. The two streams of fluids achieve full mixing at the exit of the throat. The resulting mixture then enters the diffuser section where the kinetic energy is converted to pressure. This pressure is lower than the power fluid pressure, but higher than the well fluid pressure before the well fluid enters the jet pump. This higher pressure allows the mixture to produce to the surface.

In general, embodiments disclosed herein relate to a new, more efficient approach for increasing the energy of production fluids to force them to reach the surface. According to some example embodiments, a hybrid gas lift system includes a gas-lift completion arranged to inject high-pressure gas into the production tubing of a well. The hybrid gas lift system also includes a through-tubing straddle mechanism that is deployed into and retrieved from the tubing of the well riglessly with a wireline, an e-line, or coiled tubing. In some example embodiments, an existing gas lift completion is converted into a system that combines the existing gas lift mechanism with a jet pump mechanism to result in a hybrid artificial lift system that uses the injected gas as a power fluid for the jet pump.

The through-tubing straddle mechanism receives the high-pressure injected gas from the gas-lift completion and introduces the gas into an annular nozzle of the through-tubing straddle mechanism. As the gas exits the annular nozzle, the gas creates an annular, high velocity jet which acts as a jet pump to add energy to the production fluids. Specifically, the high velocity gas jet flows into a throat section of the through-tubing straddle mechanism, where the high velocity gas mixes with the low-pressure production fluids, resulting in an exchange of energy. The mixture of injected gas and production fluids then flows through a diffuser section of the through-tubing straddle mechanism, where the kinetic energy is converted into pressure energy. The mixture flows upward via the tubing and produces to the surface.

The injected gas helps reduce the wellbore hydrostatic pressure. Because the injected gas can reduce the density of the fluid in the wellbore, the injected gas has an effect similar to a gas lifting operation. The combination of the gas lift effect and the jet pump effect results in a hybrid artificial gas lift system. The hybrid artificial gas lift system is more efficient as compared to conventional gas lift systems because the hybrid gas lift system adds energy to the well fluids while reducing hydrostatic pressure loss in the tubing. Another benefit of the hybrid artificial gas lift system is the extension of the life of a well by extending well production toward field abandonment pressures without the need to switch to other artificial lift methods.

Turning to FIG. 1. FIG. 1 shows a schematic diagram in accordance with one or more embodiments. As shown in FIG. 1, FIG. 1 illustrates a well environment 100 that may include a well 102 having a wellbore 104 extending into a formation 106. The wellbore 104 may include a bored hole that extends from the surface into a target zone of the formation 106, such as a reservoir. The formation 106 may include various formation characteristics of interest, such as formation porosity, formation permeability, resistivity, density, water saturation, and the like. Porosity may indicate how much space exists in a rock within an area of interest in the formation 106, where oil, gas, water, or a combination thereof may be trapped. Permeability may indicate the ability of liquids and gases to flow through the rock within the area of interest. Resistivity may indicate how strongly rock or fluid within the formation 106 opposes the flow of electrical current.

Keeping with FIG. 1, the well environment 100 may include a drilling system 110, a logging system 112, and a control system 114. The drilling system 110 may include a drill string, drill bit, a mud circulation system or the like for use in boring the wellbore 104 into the formation 106. The control system 114 may include hardware, software, or both, for managing drilling operations and maintenance operations. For example, the control system 114 may include one or more programmable logic controllers (PLCs) that include hardware, software, or both, with functionality to control one or more processes performed by the drilling system 110. A PLC may be a ruggedized computer system with functionality to withstand vibrations, extreme temperatures, wet conditions, and dusty conditions, for example, around a drilling rig. The PLC may control valve states, fluid levels, pipe pressures, warning alarms, and pressure releases throughout a drilling rig. Without loss of generality, the term “control system” may refer to a drilling operation control system that is used to operate and control the equipment, a drilling data acquisition and monitoring system that is used to acquire drilling process and equipment data and to monitor the operation of the drilling process, or a drilling interpretation software system that is used to analyze and understand drilling events and progress. A logging system may have similar functionality as a control system with a specific focus on managing one or more logging tools.

The logging system 112 may include one or more logging tools 113, such as a nuclear magnetic resonance (NMR) logging tool or a resistivity logging tool, for use in generating well logs 140 of the formation 106. For example, a logging tool may be lowered into the wellbore 104 to acquire measurements as the tool traverses a depth interval 130 (e.g., a targeted reservoir section) of the wellbore 104. The plot of the logging measurements versus depth may be referred to as a “log” or a “well log”. Well logs 104 may provide depth measurements of the well 102 that describe such reservoir characteristics as formation porosity, formation permeability, resistivity, density, water saturation, and the like. The resulting logging measurements may be stored or processed, for example, by the control system 114, to generate corresponding well logs 140 for the well 102. A well log may include, for example, a plot of a logging response time versus true vertical depth (TVD) across the depth interval 130 of the wellbore 104. The well logs 140 may be stored in a data repository 150.

In some embodiments, the control system 114 or the logging system 112 may include a computer system that is similar to the computer systems 500 and 514 described below with regard to FIGS. 5A and 5B, respectively, and the accompanying descriptions.

FIG. 2 is a schematic illustration of a hybrid lift system 200, according to one or more example embodiments. As shown in FIG. 2, a gas 210 may be injected from the surface into the annulus (hereinafter also “tubing-casing annulus”) 206 between the well casing (hereinafter also “casing”) 202 and the production tubing (hereinafter also “tubing” or “wellbore”) 204. A valve 212 may be used to regulate the flow of the injected gas 210 into the annulus 206. The injected gas 210 enters the tubing 204 via an operating gas lift valve 208 placed on a side of the tubing 204.

Also shown in FIG. 2 is a through-tubing straddle mechanism 234. The through-tubing straddle mechanism 234 is placed within the tubing 204 such that a reservoir fluid (hereinafter also “a mix of reservoir fluids” or “reservoir fluids”) 214 flowing from a reservoir 230, through the tubing 204, is received at the bottom end of the through-tubing straddle mechanism 234.

In some example embodiments, the through-tubing straddle mechanism 234 includes an annular jet pump 226, a lower packer 228 placed below a gas injection point 232 within the production tubing 204, at the bottom-end of the annular jet pump 226, and an upper packer 224 placed above the gas injection point 232, at the top-end of the annular jet pump 226. In various example embodiments, the through-tubing straddle mechanism 234 includes the annular jet pump 226 and the lower packer 228 placed below the gas injection point 232 within the production tubing 204, at the bottom-end of the annular jet pump 226.

As a result, the high pressure injected gas 210 received via the operating gas lift valve 208 is forced through an annular nozzle 216 of the annular jet pump 226. The annular nozzle 216 has an annular shape that, when receiving the injected gas 210, produces an annular power fluid jet. As a result, the high pressure injected gas 210 exits the annular nozzle 216 with high velocity and lower pressure. This lower pressure allows the reservoir fluid 214 to be drawn into the annular jet pump 226. The high pressure injected gas 210 drags, accelerates, and mixes with the reservoir fluid 214 in a throat section 218 of the annular jet pump 226. The fully mixed injection gas 210 and reservoir fluid 214 (i.e., mixture 222) flow through a diffuser section 220 of the annular jet pump 226, where the velocity of the mixture 222 is reduced and the kinetic energy of the mixture 222 is converted into a pressure gain. The mixture 222 exits the annular jet pump 226 and flows into the tubing 204 to be produced to the surface.

The injected gas 210 helps aerate the reservoir fluid 214, lightens the wellbore fluid density, and reduces the weight of the fluid column acting upon the sandface of the reservoir 230. Compared to gas lift alone, the hybrid jet-pump gas-lift system allows the well to produce to even lower reservoir pressure, eliminating the need to switch the gas lift mechanism to other energy-adding artificial lift systems in the later part of the life of a well. In other words, as the reservoir pressure is depleted, a rigless installation of an annular jet pump across the existing gas lift injection point can be performed to extend the production of the well until the field is abandoned.

In some example embodiments, the lower packer 228 is installed separately, with a wireline, below the gas injection point 232 within the production tubing 204. The lower packer 228 can be set hydraulically, electrically, or in combination. Then, the through-tubing straddle mechanism 234 including the annulus jet pump 226, the upper packer 224, and a bottom stinger is lowered into the tubing 204 and stabbed into a polished bore receptacle of the lower packer 228. After that, the upper packer 224 is set at the top end of the through-tubing straddle mechanism 234. The two packers 228 and 228 force the injected gas 210 to flow through the annular j et pump 226, providing artificial lift for the reservoir fluid 214.

FIG. 3 is a schematic illustration of the hybrid lift system 300, according to one or more example embodiments. Similarly to the hybrid lift system 200 shown in FIG. 2, the hybrid lift system 300 includes a through-tubing straddle mechanism 328. The through-tubing straddle mechanism 328 is placed within the tubing 304 such that a reservoir fluid 316 flowing through the tubing 304 is received at the bottom end of the through-tubing straddle mechanism 328. A high-pressure gas 314 is injected from the surface into the annulus between the casing 302 and the tubing 304. The injected gas 314 enters the tubing 304 via an operating gas lift valve 306 placed on a side of the tubing 304.

In some example embodiments, the through-tubing straddle mechanism 328 includes an annular jet pump 322, a lower packer 320 placed below a gas injection point within the production tubing 304, at the bottom-end of the annular jet pump 322, and an upper packer 324 placed above the gas injection point, at the top-end of the annular jet pump 322. In various example embodiments, the through-tubing straddle mechanism 328 includes the annular jet pump 322 and the lower packer 320 placed below the gas injection point within the production tubing 304, at the bottom-end of the annular jet pump 322. An additional packer 330 may be placed within the tubing-casing annulus to help control the flow of the injected gas 314.

As a result, the high pressure injected gas 314 received via the operating gas lift valve 306 is forced through an annular nozzle 308 of the annular jet pump 322. The annular nozzle 308 has an annular shape that, when receiving the injected gas 314, produces an annular power fluid jet. As a result, the high pressure injected gas 314 exits the annular nozzle 308 with high velocity and lower pressure. This lower pressure allows the reservoir fluid 316 to be drawn into the annular jet pump 322. The high pressure injected gas 314 drags, accelerates, and mixes with the reservoir fluid 316 in a throat section 310 of the annular jet pump 322. The fully mixed injection gas 314 and reservoir fluid 316 (i.e., mixture 326) flow through a diffuser section 312 of the annular jet pump 322, where the velocity of the mixture 326 is reduced and the kinetic energy of the mixture 326 is converted into a pressure gain. The mixture 326 exits the annular jet pump 322 and flows into the tubing 304 to be produced to the surface.

In some example embodiments, a well may exhibit liquid-loading problems resulting from insufficient velocity of the liquids in the wellbore. In time, these liquids accumulate and impair production. Installing a velocity string in the wellbore reduces the flow area and increases the flow velocity to enable liquids to be carried from the wellbore.

As shown in FIG. 3, a tail pipe 318 allowing the reservoir fluids 316 to flow into the annular jet pump 322 can be extended as a velocity string. The velocity string may be a small-diameter tubing string run inside the production tubing 304 as a remedial treatment to resolve existing liquid-loading problems. In other words, the annular jet pump 322 may include the tail pipe 318 which could extend all the way to a horizontal section of the wellbore, enabling the reservoir fluids 316 to produce at a higher velocity and to prevent slugging and loading in the wellbore below the annular jet pump 322.

FIG. 4 is a flowchart illustrating operations of the hybrid lift system in performing a method for increasing the energy of the production fluids to cause the flow of the production fluids to the surface, according to one or more example embodiments. Steps of the method 400 may be performed using the components described above with respect to FIGS. 2 and 3. In some example embodiments, one or more steps of the method 400 may be performed by a computing system such as that shown and described below in FIGS. 5A and 5B. While the various blocks in FIG. 4 are presented and described sequentially, one of ordinary skill in the art will appreciate that some or all of the blocks may be executed in different orders, may be combined or omitted, and some or all of the blocks may be executed in parallel. Furthermore, the blocks may be performed actively or passively.

As shown in FIG. 4, at Step 402, a gas-lift completion injects high-pressure gas into production tubing of a well. The high-pressure gas is injected into the production tubing of the well via a gas-lift valve arranged at a gas injection point within the production tubing.

At Step 404, an annular nozzle included in a downhole annular jet pump receives the injected high-pressure gas. The injected high-pressure gas exits the annular nozzle as an annular high-velocity gas jet.

In some example embodiments, the annular nozzle has an annular shape that, when receiving the injected gas, produces an annular power fluid jet.

In some example embodiments, the annular nozzle is of an annular shape that, when receiving the injected gas, produces the annular high-velocity gas jet. The low-pressure production fluid flows into the annular nozzle from the center of a wellbore of the well.

In various example embodiments, the downhole annular jet pump is included in a through-tubing straddle system located within a wellbore of the well. The through-tubing straddle system further includes a lower packer placed below a gas injection point within the production tubing, at a bottom-end of the annular jet pump. In some example embodiments, the through-tubing straddle system, in addition to the lower packer placed below the gas injection point within the production tubing, at the bottom-end of the annular jet pump, includes an upper packer placed above the gas injection point within the production tubing, at a top-end of the annular jet pump.

In some example embodiments, the through-tubing straddle system is deployed riglessly with coiled tubing. In certain example embodiments, the through-tubing straddle system is deployed riglessly with wireline. In various example embodiments, wherein the through-tubing straddle system is deployed riglessly with e-line.

At Step 406, a throat section included in the downhole annular jet pump receives the annular high-velocity gas jet.

At Step 408, the throat section included in the downhole annular jet pump mixes the annular high-velocity gas jet with a low-pressure production fluid.

At Step 410, a diffuser section included in the downhole annular jet pump facilitates conversion of kinetic energy into pressure energy in a mixture of the annular high-velocity gas jet and the low-pressure production fluid.

At Step 412, the diffuser section included in the downhole annular jet pump produces the mixture to a surface via the production tubing.

Example embodiments may be implemented on a computing system. Any combination of mobile, desktop, server, router, switch, embedded device, or other types of hardware may be used. For example, as shown in FIG. 5A, the computing system 500 may include one or more computer processors 502, non-persistent storage 504 (e.g., volatile memory, such as random access memory (RAM) or cache memory), persistent storage 506 (e.g., a hard disk, an optical drive such as a compact disk (CD) drive or digital versatile disk (DVD) drive, or a flash memory), a communication interface 512 (e.g., Bluetooth interface, infrared interface, network interface, or optical interface), and numerous other elements and functionalities.

The computer processor(s) 502 may be an integrated circuit for processing instructions. For example, the computer processor(s) 502 may be one or more cores or micro-cores of a processor. The computing system 500 may also include one or more input devices 510, such as a touchscreen, keyboard, mouse, microphone, touchpad, or electronic pen.

The communication interface 512 may include an integrated circuit for connecting the computing system 500 to a network (not shown) (e.g., a local area network (LAN), a wide area network (WAN), such as the Internet, mobile network, or any other type of network) or to another device, such as another computing device.

Further, the computing system 500 may include one or more output devices 508, such as a screen (e.g., a liquid crystal display (LCD), a plasma display, touchscreen, cathode ray tube (CRT) monitor, or projector), a printer, external storage, or any other output device. One or more of the output devices may be the same or different from the input device(s). The input and output device(s) may be locally or remotely connected to the computer processor(s) 502, non-persistent storage 504, and persistent storage 506. Many different types of computing systems exist, and the afore-mentioned input and output device(s) may take other forms.

Software instructions in the form of computer readable program code to perform embodiments of the disclosure may be stored, in whole or in part, temporarily or permanently, on a non-transitory computer readable medium such as a CD, DVD, storage device, a diskette, a tape, flash memory, physical memory, or any other computer readable storage medium. Specifically, the software instructions may correspond to computer readable program code that when executed by a processor(s) is configured to perform one or more embodiments of the disclosure.

The computing system 500 in FIG. 5A may be connected to or be a part of a network. For example, as shown in FIG. 5B, the network 516 may include multiple nodes (e.g., node X 518 or node Y 520). Each node may correspond to a computing system, such as the computing system shown in FIG. 5B, or a group of nodes combined may correspond to the computing system shown in FIG. 5B. By way of an example, embodiments of the disclosure may be implemented on a node of a distributed system that is connected to other nodes. By way of another example, embodiments of the disclosure may be implemented on a distributed computing system having multiple nodes, where each portion of the disclosure may be located on a different node within the distributed computing system. Further, one or more elements of the afore-mentioned computing system 514 may be located at a remote location and connected to the other elements over a network.

Although not shown in FIG. 5B, the node may correspond to a blade in a server chassis that is connected to other nodes via a backplane. By way of another example, the node may correspond to a server in a data center. By way of another example, the node may correspond to a computer processor or micro-core of a computer processor with shared memory or resources.

The nodes (e.g., node X 518 or node Y 520) in the network 516 may be configured to provide services for a client device 522. For example, the nodes may be part of a cloud computing system. The nodes may include functionality to receive requests from the client device 522 and transmit responses to the client device 522. The client device 522 may be a computing system, such as the computing system shown in FIG. 5B. Further, the client device 522 may include or perform all or a portion of one or more embodiments of the disclosure.

The previous description of functions presents only a few examples of functions performed by the computing system of FIG. 5A and the nodes or client device in FIG. 5B. Other functions may be performed using one or more embodiments of the disclosure.

While the disclosure has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the disclosure as disclosed. Accordingly, the scope of the disclosure should be limited only by the attached claims.

Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. § 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.

Claims

1. A system for hybrid gas lifting, the system comprising:

a gas-lift completion arranged to inject high-pressure gas into production tubing of a well; and

a downhole annular jet pump including: an annular nozzle arranged to receive the injected high-pressure gas, the injected high-pressure gas exiting the annular nozzle as an annular high-velocity gas jet; a throat section arranged to: receive the annular high-velocity gas jet, and mix the annular high-velocity gas jet with a low-pressure production fluid; and a diffuser section arranged to: facilitate conversion of kinetic energy into pressure energy in a mixture of the annular high-velocity gas jet and the low-pressure production fluid, and produce the mixture to a surface via the production tubing.

2. The system of claim 1, wherein the downhole annular jet pump is included in a through-tubing straddle system located within a wellbore of the well, the through-tubing straddle system further including a lower packer placed below a gas injection point within the production tubing, at a bottom-end of the annular jet pump, and an upper packer placed above the gas injection point within the production tubing, at a top-end of the annular jet pump.

3. The system of claim 1, wherein the downhole annular jet pump is included in a through-tubing straddle system located within a wellbore of the well, the through-tubing straddle system further including a lower packer placed below a gas injection point within the production tubing, at a bottom-end of the annular jet pump.

4. The system of claim 2, wherein the through-tubing straddle system is deployed riglessly with coiled tubing.

5. The system of claim 2, wherein the through-tubing straddle system is deployed riglessly with wireline.

6. The system of claim 2, wherein the through-tubing straddle system is deployed riglessly with e-line.

7. The system of claim 1, wherein the high-pressure gas is injected into the production tubing of the well via a gas-lift valve arranged at a gas injection point within the production tubing.

8. The system of claim 1, wherein the annular nozzle is of an annular shape that, when receiving the injected gas, produces the annular high-velocity gas jet.

9. The system of claim 1, wherein the low-pressure production fluid flows into the annular nozzle from a center of a wellbore of the well.

10. The system of claim 1, further comprising:

a tube arranged to receive the low-pressure production fluid through a wellbore of the well and to carry the low-pressure production fluid to the throat section of the downhole annular jet pump, the tube extending to a particular depth within the wellbore that causes a reduction of liquid loading in the low-pressure production fluid.

11. A method for hybrid gas lifting, the method comprising:

injecting, by a gas-lift completion, high-pressure gas into production tubing of a well;

receiving, by an annular nozzle included in a downhole annular jet pump, the injected high-pressure gas, the injected high-pressure gas exiting the annular nozzle as an annular high-velocity gas jet;

receiving, by a throat section included in the downhole annular jet pump, the annular high-velocity gas jet;

mixing, by the throat section included in the downhole annular jet pump, the annular high-velocity gas jet with a low-pressure production fluid;

facilitating conversion, by a diffuser section included in the downhole annular jet pump, of kinetic energy into pressure energy in a mixture of the annular high-velocity gas jet and the low-pressure production fluid; and

producing, by the diffuser section included in the downhole annular jet pump, the mixture to a surface via the production tubing.

12. The method of claim 11, wherein the downhole annular jet pump is included in a through-tubing straddle system located within a wellbore of the well, the through-tubing straddle system further including a lower packer placed below a gas injection point within the production tubing, at a bottom-end of the annular jet pump, and an upper packer placed above the gas injection point within the production tubing, at a top-end of the annular jet pump.

13. The method of claim 11, wherein the downhole annular jet pump is included in a through-tubing straddle system located within a wellbore of the well, the through-tubing straddle system further including a lower packer placed below a gas injection point within the production tubing, at a bottom-end of the annular jet pump.

14. The method of claim 12, wherein the through-tubing straddle system is deployed riglessly with coiled tubing.

15. The method of claim 12, wherein the through-tubing straddle system is deployed riglessly with wireline.

16. The method of claim 12, wherein the through-tubing straddle system is deployed riglessly with e-line.

17. The method of claim 11, wherein the high-pressure gas is injected into the production tubing of the well via a gas-lift valve arranged at a gas injection point within the production tubing.

18. The method of claim 11, wherein the annular nozzle is of an annular shape that, when receiving the injected gas, produces the annular high-velocity gas jet.

19. The method of claim 11, wherein the low-pressure production fluid flows into the annular nozzle from a center of a wellbore of the well.

20. The method of claim 11, further comprising:

a tube arranged to receive the low-pressure production fluid through a wellbore of the well and to carry the low-pressure production fluid to the throat section of the downhole annular jet pump, the tube extending to a particular depth within the wellbore that causes a reduction of liquid loading in the low-pressure production fluid.