WO2025184264A1 - Rigless high-speed helicoaxial pump system - Google Patents

Abstract

A wellbore production system includes a production tubing positioned within a wellbore and an electrical submersible pump (ESP) assembly positioned within the production tubing. The ESP assembly is a rigless ESP assembly that is conveyable within the production tubing by a conveyance line. The ESP assembly includes a high-speed helicoaxial pump a motor for driving the helicoaxial pump. A power transmission line extends from a surface of the wellbore outside of the production tubing and connects through the production tubing to the motor. The wellbore production system includes a gravity-assisted gas separator connected to the production tubing and connected to an intake of the ESP assembly.

Description

RIGLESS HIGH-SPEED HELICOAXIAL PUMP SYSTEM

CROSS REFERENCE TO RELATED APPLICATIONS

[0001] This application claims priority to and the benefit of United States Provisional Patent Application No. 63/558,267, filed February 27, 2024, and United States Provisional Patent Application No. 63/678,763, filed August 2, 2024, which are all hereby incorporated by reference in their entirety.

BACKGROUND OF THE DISCLOSURE

[0001] Wellbores may be drilled into a surface location or seabed for a variety of exploratory or extraction purposes. For example, a wellbore may be drilled to access fluids, such as liquid and gaseous hydrocarbons, stored in subterranean formations and to extract the fluids from the formations. Wellbores used to produce or extract fluids may be formed in earthen formations using earth-boring tools such as drill bits for drilling wellbores and reamers for enlarging the diameters of wellbores. Some wellbores may implement electrical submersible pumps (ESPs) for facilitating flowing production fluids to the surface of the wellbore.

BRIEF DESCRIPTION OF THE DRAWINGS

[0002] In order to describe the manner in which the above-recited and other features of the disclosure can be obtained, a more particular description will be rendered by reference to specific embodiments thereof which are illustrated in the appended drawings. For better understanding, the like elements have been designated by like reference numbers throughout the various accompanying figures. While some of the drawings may be schematic or exaggerated representations of concepts, at least some of the drawings may be drawn to scale. Understanding that the drawings depict some example embodiments, the embodiments will be described and explained with additional specificity and detail through the use of the accompanying drawings in which:

[0003] FIG. 1-1 shows an example of a wellbore system for drilling an earth formation to form a wellbore, according to at least one embodiment of the present disclosure; [0004] FIG. 2-1 illustrates an example of a production system which may be implemented to produce one or more underground resources, according to at least one embodiment of the present disclosure;

[0005] FIG. 2-2 illustrates a zoomed in view of a gas separator of the production system of FIG. 2-1, illustrating the flow of a production fluid therethrough, according to at least one embodiment of the present disclosure;

[0006] FIG. 2-3 illustrates a zoomed in view of an electrical submersible pump assembly of the production system of FIG. 2-1, according to at least one embodiment of the present disclosure;

[0007] FIG. 3-1 illustrates a helicoaxial pump, according to at least one embodiment of the present disclosure;

[0008] FIG. 3-2 illustrates an example of an electrical submersible pump that does not have helicoaxial blades, according to at least one embodiment of the present disclosure;

[0009] FIG. 4 illustrates a flow diagram for a method or a series of acts for producing a gas at a surface of a wellbore as described herein, according to at least one embodiment of the present disclosure; and

[0010] FIG. 5 illustrates a flow diagram for a method or a series of acts for producing a methane from a wellbore as described herein, according to at least one embodiment of the present disclosure.

DETAILED DESCRIPTION

[0011] This disclosure generally relates to electrical submersible pump (ESP) assemblies for use in wellbore applications to generate artificial lift. The ESP assemblies described herein are retrievable, conveyable, and/or rigless ESP assemblies that can be positioned within a (e.g., already installed) production tubing, and retrieved/conveyed therethrough. Power transmission to the ESP assembly may be achieved through a power transmission line that is positioned outside of the production tubing, and a receptacle may facilitate connecting the ESP assembly to the power transmission line. In this way, the ESP assembly may be rigless, which may facilitate simpler, faster, easier, more cost effective, and for flexible deployment, retrieval, maintenance, and/or replacement of the ESP assembly in a wellbore completion. [0012] The ESP assembly may be equipped with a pump which may specifically be a helicoaxial pump. For instance, the helicoaxial pump may have impeller sections of each stage which have helical or spiraling impeller blade for imparting motion to a production fluid in a generally axial direction. This may facilitate producing pressure or head for the production fluid without causing phase changes and/or gas separation of the production fluid, thus preventing gas locking. Additionally, the helicoaxial pump may provide a smaller overall form factor which may facilitate the production-tubing-conveyable nature of the ESP assembly, especially for smaller-diameter production tubings.

[0013] The helicoaxial pump may also be a high-speed helicoaxial pump which may operate at higher frequencies than conventional ESP assemblies. For example, the highspeed helicoaxial pump may operate at speeds of greater than 70 Hz, such as up to 120 Hz. These higher speeds may facilitate generating much more head than is typically the case with helicoaxial pumps such that the ESP assembly may be configured with only helicoaxial pump stages, and no other types or stages of pumps. For instance, the helicoaxial pumps may not be implemented as a charge stage only of the ESP system, but rather the helicoaxial pumps may be implemented to generate all of the head of the ESP assembly. The high-speed nature of the helicoaxial pumps may facilitate generating sufficient artificial lift for producing the production fluid at the surface, while maintaining a smaller overall axial length of the pump.

[0014] The production systems described herein may also include a gravity-assisted gas separator. For example, the gas separator may be a passive gas separator which may operate based on the differences in specific gravity of gas and liquid phases of a production fluid to separate out the gas phase. As the production fluid flows over an inverted shroud assembly, the gas phase may separate, dissociate, or otherwise escape the liquid phase and may flow up an annulus of the wellbore. In a particular example, the gravity-assisted gas separator may facilitate separating and producing methane gas from a methane hydrate formation, which may be produced at the surface through the annulus.

[0015] Additional details will now be provided regarding systems described herein in relation to illustrative figures portraying example implementations. For example, FIG. 1-1 shows one example of a wellbore system 100 for drilling an earth formation 101 to form a wellbore 102. The wellbore system 100 includes a drill rig 103 used to turn a drilling tool assembly 104 which extends downward into the wellbore 102. The drilling tool assembly 104 may include a drill string 105, a bottomhole assembly (“BHA”) 106, and a bit 110 attached to the downhole end of the drill string 105.

[0016] The drill string 105 may include several j oints of drill pipe 108 connected end- to-end through tool joints 109. The drill string 105 transmits drilling fluid through a central bore and transmits rotational power from the drill rig 103 to the BHA 106. In some embodiments, the drill string 105 further includes additional downhole drilling tools and/or components such as subs, pup joints, etc. The drill pipe 108 provides a hydraulic passage through which drilling fluid is pumped from the surface. The drilling fluid discharges through selected-size nozzles, jets, or other orifices in the bit 110 for the purposes of cooling the bit 110 and cutting structures thereon, and for lifting cuttings out of the wellbore 102 as it is being drilled.

[0017] The BHA 106 may include the bit 110, other downhole drilling tools, or other components. An example BHA 106 may include additional or other downhole drilling tools or components (e.g., coupled between the drill string 105 and the bit 110). Examples of additional BHA components include drill collars, stabilizers, measurement-while-drilling (“MWD”) tools, logging-while-drilling (“LWD”) tools, downhole motors, underreamers, section mills, hydraulic disconnects, jars, vibration or dampening tools, other components, or combinations of the foregoing.

[0018] In general, the wellbore system 100 may include other downhole drilling tools, components, and accessories such as special valves (e.g., kelly cocks, blowout preventers, and safety valves). Additional components included in the wellbore system 100 may be considered a part of the drilling tool assembly 104, the drill string 105, or a part of the BHA 106, depending on their locations in the wellbore system 100.

[0019] The bit 110 in the BHA 106 may be any type of bit suitable for degrading downhole materials. For instance, the bit 110 may be a drill bit suitable for drilling the earth formation 101. Example types of drill bits used for drilling earth formations are fixed- cutter or drag bits. In other embodiments, the bit 110 may be a mill used for removing metal, composite, elastomer, other materials downhole, or combinations thereof. For instance, the bit 110 may be used with a whipstock to mill into casing 107 lining the wellbore 102. The bit 110 may also be a junk mill used to mill away tools, plugs, cement, other materials within the wellbore 102, or combinations thereof. Swarf or other cuttings formed by use of a mill may be lifted to the surface or may be allowed to fall downhole. The bit 110 may include one or more cutting elements for degrading the earth formation 101.

[0020] The BHA 106 may further include a rotary steerable system (RSS). The RSS may include directional drilling tools that change a direction of the bit 110, and thereby the trajectory of the wellbore. At least a portion of the RSS may maintain a geostationary position relative to an absolute reference frame, such as one or more of gravity, magnetic north, or true north. Using measurements obtained with the geostationary position, the RSS may locate the bit 110, change the course of the bit 110, and direct the directional drilling tools on a projected trajectory. The RSS may steer the bit 110 in accordance with or based on a trajectory for the bit 110. For example, a trajectory may be determined for directing the bit 110 toward one or more subterranean targets such as an oil or gas reservoir.

[0021] The wellbore system 100 may be implemented as shown and described as part of a drilling and/or wellbore forming configuration of the wellbore system 100. In some cases, the wellbore system 100 may be implemented as a completion and/or production configuration having a different configuration of downhole components. For instance, the production system 111 is representative of an alternate or later implementation of at least a portion of the wellbore system 100 having a combination of downhole components for a production phase of the wellbore system 100. In some cases, after the wellbore 102 has been formed, one or more production or completion components may be installed or implemented in the wellbore 102 for facilitating the production and removal of a production fluid 144 from a reservoir 142. For instance, in some cases an electrical submersible pump (ESP) 140 and associated assembly may be implemented in the wellbore 102 for providing supplemental pressure and/or flow to the production fluid 144, for example, above that which the reservoir 142 provides. In this way the ESP 140 may facilitate the production fluid 144 flowing to the surface.

[0022] In some cases, the reservoir 142 may be representative of a methane hydrate formation. For example, in some formations (e.g., subsea formations), methane gas is found in a solidified or crystalized form in combination with solid water (other aqueous substance), based on a pressure and/or a temperature of the formation. The production fluid 144 may represent an aqueous fluid (e.g., water) which may be pumped or removed from the reservoir 142, which in turn may lower the pressure of the reservoir, releasing methane in the form of gas. For instance, methane hydrates are crystalline ice-like structures in which methane molecules are trapped within water lattices under high-pressure and low- temperature conditions, such as in deep-sea sediments or permafrost regions. Reducing the pressure of the methane hydrate formation causes the methane hydrate to dissociate, releasing methane gas and water. Accordingly, the production fluid 144 may include an aqueous fluid having methane gas dispersed therein or flowing therethrough. By flowing and separating the aqueous fluid from the methane gas, the methane gas can be produced at the surface.

[0023] FIG. 2-1 illustrates an example of a production system 211 which may be implemented to produce one or more underground resources, according to at least one embodiment of the present disclosure. The production system 211 may be a wellbore production system implemented in a wellbore formed in an earth formation, such as that described in connection with FIG. 1-1. For instance, one or more components of the production system 211 may be implemented in conjunction with, or in place of, one or more of the components of the wellbore system 100 as shown in FIG. 1-1, after some or all of the wellbore 202 has been formed. For instance, the production system 211 may include a collection of components for controlling and/or lifting a production fluid from a reservoir, formation, or other underground reserve where resources are found. The production system 111 may be implemented with fewer and/or additional components to those shown and described herein in order to facilitate the producing one or more resources at the surface of the wellbore 202.

[0024] In some embodiments, the production system 211 includes various surface components 220. The surface components 220 may include wellhead equipment for controlling and directing the flow of the production fluid at the surface. For instance, the surface components 220 may include electrical components such as a variable speed drive, set up transformer, etc., for providing electrical power to one or more downhole components of the production system 211. The surface equipment may include flow control devices such as various valves, blow-out preventers, and others. In some cases, the surface components 220 may include a Christmas tree, for example, with sufficient throughbore for passing or conveying one or more components (e.g., the ESP assembly as described herein) therethrough as a rigless deployment.

[0025] In some cases, one or more layers of casing may be implemented in the wellbore and connected thereto. For instance, the wellbore 202 as shown in FIG. 2-1 may be representative of an open wellbore, or else may be representative of a cased wellbore having one or more strings or casings connected thereto for supporting the wellbore, isolating formations, etc. In some cases, a production casing 222 may be positioned within the wellbore 202. Additionally, a production tubing 223 may be positioned within the production casing 222. The production tubing 223 may be a tubular for circulating fluid and/or producing a production fluid (e.g., a formation fluid) via the production system 211. For instance, the production tubing 223 may extend from the surface of the wellbore 202 down to a production zone 229, such as at or near an underground reservoir.

[0026] In some cases, the production casing 221 may be fixed (e.g., permanently or semi-permanently) within the wellbore 202 via a production packer 224. The production packer 224 may facilitate isolating a reservoir zone and/or may provide access to the production zone 229 by the production tubing 223. The production tubing 223 may be positioned and/fixed (e.g., permanently or semi-permanently) within the production casing 221 with a production tubing packer 225.

[0027] Based on the configuration of the production casing 221 and the production tubing 223, production fluids may be made to flow into the production tubing 223, for example, for producing the production fluids at the surface. In some cases, the production tubing 223 may include a reservoir isolation valve 226 and/or a deep-set subsurface safety valve 227. One or more of these valves may facilitate controlling the pressure and/or the flow rate of the production fluid from the production zone 229.

[0028] The production system 211 includes an ESP assembly 250. As will be discussed in detail below, the ESP assembly 250 includes a high-speed helicoaxial pump for pumping the production fluid up through the production tubing 223. For example, the production fluid 244 may be made to flow from the production zone 229 to the surface at least partially based on an artificial lift, or head, generated by the ESP assembly 250.

[0029] The production tubing 223 may be equipped with a gas separator 230. The gas separator 230 may be a passive gas-separator, such as a gravity-assisted gas separator. For instance, the gas separator 230 may not include any moving parts, and may not actively perform any actions, movements, or processes for separating gas. To elaborate, the gas separator 230 may rely on gravity and the natural flow of various constituent parts or phases of a fluid to facilitate gas naturally rising or escaping a (e.g., downward) flow of the fluid. [0030] FIG. 2-2 illustrates a zoomed in view of the gas separator 230, illustrating the flow of a production fluid 244 therethrough, according to at least one embodiment of the present disclosure. The production fluid 244 may be produced via the production system 211 from a reservoir or other production zone of a formation. The production fluid 244 may flow into the production tubing 223 (e.g., via the production casing 221) based on a natural pressure or flow of the reservoir and/or based on artificial lift provided by the ESP assembly 250.

[0031] In some cases, the production fluid 244 includes a gas dispersed, dissolved, or mixed therein. For example, hydrocarbon gasses, CO2 gasses, hydrogen gases, nitrogen gasses, or other gasses may be included in a flow of the production fluid 244 from the reservoir. As mentioned above, in some cases, methane gasses may be released from a solid clathrate hydrate structure with water and can flow upwards with and/or through a flow of the water.

[0032] The production fluid 244 may initially flow (e.g., upward or uphole) through the production tubing 223, and may flow out of the production tubing 223 at a perforated pup joint 231. From there, the production fluid 244 may flow through an annulus 228 between the production tubing 223 and the production casing 221. The gas separator 230 may be configured with an inverted shroud 232 which may facilitate separating gas from the production fluid 244. For example, from the annulus 228, the production fluid 244 may spill over, flow into, or otherwise pass through the inverted shroud 232, which may change a direction of the flow of the production fluid 244. For example, the production fluid 244 may tend to follow the direction of gravity, which may cause the production fluid 244 to flow downward into the inverted shroud 232.

[0033] Based on the production fluid 244 flowing over and into the inverted shroud 232, a gas phase 244-1 of the production fluid 244 may separate or escape from the production fluid 244. For example, based on a difference in the density and/or specific gravity of a liquid component compared to a gas component of the production fluid 244, the gas phase 244-1 may tend to escape and/or continue to flow upwards past the inverted shroud 232, while a liquid phase 244-2 flows down and into the inverted shroud 232. The liquid phase 244-2 may flow back into the production tubing 223 at a perforated pup join 233 positioned within the inverted shroud 232, and ultimately to and through the ESP assembly 250 as described herein. Thus, by leveraging the natural properties of the constituent liquid and gaseous components of the production fluid 244, the gas separator 230 may passively facilitate the separation of the gas phase 244-1 from the liquid phase 244-2 based on gravity.

[0034] In some cases, the gas phase 244-1 may be a hydrocarbon gas, CO2 gas, or other gas which may escape from a flow of a hydrocarbon production fluid. In accordance with a particular example, the gas phase 244-1 may be a methane gas which escapes from a flow of an aqueous production fluid or water. As mentioned above, the production zone or reservoir may be a methane hydrate formation, and methane gas may be trapped in a solid form in connection with a solid form of the aqueous fluid (ice). By pumping and removing some of the aqueous fluid from the methane hydrate formation, the methane gas may be release from its solid state into a gaseous state. The now gaseous methane gas may flow upwards with and/or through the aqueous fluid and accordingly may flow up the production tubing 223 and to the gas separator 230 as described.

[0035] In this way, methane gas (or other gas) may be produced and separated from the methane hydrate formation, and produced at the surface. For example, the gas phase 244-1 may flow through the annulus 228, outside of the production tubing 223 wherein it may remain separated and isolated from the liquid phase 244-2. For example, the production tubing 223 may not include any additional packers uphole of the gas separator 230 such that the gas phase 244-1 may flow to the surface through the annulus. For instance, the production system 211 may not include any crossover device to facilitate flowing the gas phase 244-1 from the annulus 228 to the production tubing at any point, as may be the case in some conventional approaches. Rather, the gas phase 244-1 may flow through the annulus 228 and produced at the surface via the annulus 228. The gas phase 244-1 may then be captured at the surface from the annulus 228.

[0036] In some cases, such as for production zones including a methane hydrate formation as described, substantially all of the gas phase 244-1 may be separated from the liquid phase 244-2 at the gas separator 230. For example, the natural rising of gas and the natural falling of liquid due to gravity at the inverted shroud 232 may operate to remove substantially all of the gas phase 244-1. For instance, the production fluid 244 may be made to flow at a given flow rate such that all of the gas phase 244-1 is allowed to escape at the inverted shroud 232, and the liquid phase 244-2 may include substantially only liquid, with no gas mixed therein. This may be especially true with respect to methane gas released from a methane hydrate formation. For example, methane may not be soluble in water — or methane and water may be immiscible — such that the methane gas may not dissolve in the aqueous fluid (e.g., at the temperatures and/or pressures of the reservoir, wellbore, production system, etc., where the methane gas flows). Rather, methane gas, when released from its solid structure with water, may flow upward with or through the aqueous fluid being pumped through the production tubing 223. Accordingly, the (methane) gas phase 244-1 and the liquid phase 244-2 may readily separate at the inverted shroud 232 such that substantially all of the gas phase 244-1 flows upward through the annulus 228, rather than into the inverted shroud 232 with the liquid phase 244-2. Accordingly, the gas phase 244- 1 can be produced and collected at the surface through the annulus 228.

[0037] Turning back to FIG. 2-1, in some cases the production system 211 does not include any other gas separators or gas-separating components in addition to the gas separator 230 just described. For instance, the production system 211 does not include an additional gas separator positioned above the ESP assembly. In this way, the production system 211 may rely entirely on the natural and/or passive gas-separation functionality of the gas separator 230, and may not employ additional gas separators. Additionally, the production system 211 may not include any active or mechanical gas separators which may perform gas-separation functionality based on performing mechanical movements, actions, or functions. In this way, the production system 211 may maintain a high level of reliability by implementing fewer gas separators and additionally by utilizing a passive gas separator with no moving parts or active gas-separation mechanism, to limit the potential for failure or malfunction of the production system 211.

[0038] As mentioned above, the production system 211 includes an ESP assembly 250. FIG. 2-3 illustrates a zoomed in view of the ESP assembly 250 of the production system 211, according to at least one embodiment of the present disclosure. The ESP assembly 250 may be configured to pump the production fluid 244 upward through the production tubing. For example, based on a pressure or head generated by the ESP assembly 250, and in some cases in connection with a natural pressure of a reservoir, the production fluid 244 may be made to flow to the surface through the production tubing 223.

[0039] In some embodiments, the ESP assembly 250 includes a pump 251 and a motor

252. The motor 252 may be an electric motor which may drive the operation of the pump 251. For example, the motor 252 may be connected to a power transmission line 259, which may provide an electrical power to the motor 252 from the surface of the wellbore 202. As described herein, the power transmission line 259 may be positioned outside of the production tubing 223, in the annulus 228. The motor 252 may be a submersible electric motor which may be configured to operate when submerged or exposed to a flow of the production fluid 244. The motor 252 may be connected to the pump 251 via a shaft for driving various stages of the pump 251.

[0040] In some embodiments, the pump 251 receives or takes in a flow of the production fluid 244 through a pump intake 253. For example, the production fluid 244 may flow between the ESP assembly 250 and the production tubing 223 to the pump intake

253, wherein it may flow into the pump 251. The pump intake 253 may be a perforated component for permitting the production fluid 244 to flow therethrough.

[0041] As described in detail below, the pump 251 may be a high-speed helicoaxial pump which may include various pump stages. Thus, the pump 251 represented in FIG. 2- 3 in some cases may include many stages and may span a considerable axial length. The pump 251 may pump the production fluid 244, which may flow out of the pump 251 at a discharge head 254, and a valve assembly 255 may direct and/or control the flow of the production fluid 244 into the production tubing 223. The ESP assembly 250 may be sealed on an upper end against the production tubing 223 with a sealing assembly 256. In some cases, the sealing assembly 256 may include a thermal expansion joint.

[0042] As shown in FIG. 2-3, the ESP assembly 250 may be positioned entirely within the production tubing 223. For example, the ESP assembly 250 may be conveyable and/or retrievable within the production tubing 223. To elaborate, the ESP assembly 250 may be conveyed via a conveyance line such as a wireline (WL), coiled tubing (CT), or other conveyance line. In some cases, a diameter of the production tubing may be considerably smaller than a diameter of the production casing, or the wellbore. For example, the production tubing 223 may have a diameter that is 4.5 inches or less. In some cases, the production tubing 223 is 6 inches or less. Accordingly, a production tubing-deployable (e.g., rigless) ESP assembly such as the ESP assembly 250 may be considerably smaller and different than, for example, ESP assemblies which are configured as part of a (e.g., connected to) a production tubing and accordingly only need to be able to fit within the larger, production casing.

[0043] In this way, the ESP assembly 250 may be a rigless ESP assembly 250, and may be conveyable with and/or retrievable from the wellbore 202 without relying on a downhole rig, drilling rig, block, mast, derrick, or other complex and/or heavy-duty rig components typically utilized for conveying tubulars (e.g., drill pipe, tubing, casing, etc.) Rather, the ESP assembly 250 may be conveyed via conveyance system for WL, CT, and the like, such as those conventionally used in intervention, servicing, monitoring, or stimulating operations of a wellbore. These conveyance systems may typically be much smaller, faster, simpler, and more cost-effective. In this way, the production tubing 223 may be installed in the wellbore 202 in a permanent or semi-permanent manner, and the ESP assembly 250 may be conveyed and positioned within the production tubing 223 at a later time.

[0044] To facilitate implementing the ESP assembly 250 within the production tubing 223, the production system 211 may include a motor connector assembly 257. The motor connector assembly 257 may be implemented as one or more components of the production tubing 223 and one or more components of the ESP assembly 250 which may mate and/or connect to provide a secure, stable connection of the ESP assembly 250. For instance, the ESP assembly 250 may be equipped with a shuttle component at a bottom end, which may mate with a corresponding component of the production tubing 223, and which may facilitate aligning, positioning, and securing the ESP assembly 250 with respect to the production tubing 223.

[0045] In some cases, the motor connector assembly 257 includes a receptacle 258, such as a wetmate receptacle. The receptacle 258 may connect to the ESP assembly 250 to provide electrical connectivity to the ESP assembly 250 (e g., to the motor 252). For instance, as mentioned above, a power transmission line 259 may be positioned outside of the production tubing 223, and may extend from the surface of the wellbore 202. In some cases, the power transmission line 259 is installed on the production tubing 223, and is conveyed and positioned in the wellbore 202 in connection with the production tubing. The power transmission line 259 may connect to the receptacle such that the power transmission line 259 is electrically connected to an interior of the production tubing 223.

[0046] When deploying the ESP assembly 250, the ESP assembly 250 may be conveyed down the production tubing 223 by a conveyance line until the ESP assembly 250 reaches the motor connector assembly 257. The ESP assembly 250 may be lowered, inserted, or otherwise connected with the motor connector assembly 257 such that the ESP assembly 250 is electrically connected to the power transmission line 259. For instance, the ESP assembly 250 may include a pin or plug which may mate with the receptacle 258 to establish an electrical connection between the ESP assembly 250 and the power transmission line 259. In this way, the ESP assembly 250 (e.g., the pump 251) may be powered and/or controlled from the surface through the power transmission line 259, which may be positioned outside of the production tubing 223.

[0047] The rigless and convey able nature of the ESP assembly 250 may be in contrast to conventional ESP systems. For example, some ESP systems may typically be implemented as an assembly connected to, or part of, a production tubing. To elaborate, in some conventional approaches, ESP assemblies may be made up with and/or connected to a production tubing, and may be conveyed into a wellbore with the production tubing. Accordingly, such ESP assemblies may be more permanently installed fixtured in the wellbore, as opposed to the ESP assembly 250, which is retrievable from within the production tubing 223. For example, in some conventional solutions, in order to remove the ESP assembly, such as to repair, maintain, or replace the ESP assembly, the entire completion must be tripped from the wellbore. Thus, removing the ESP assembly requires the use of a workover rig, which are expensive and slow to operate, complex costly, and dangerous. Additionally, removing completion components leads to downtime of the wellbore, and in some cases, may not even be possible for live wells without killing the well with kill fluids which can have many detrimental effects, such as causing formation damage or wellbore collapse, especially on highly deplete reservoirs. [0048] In contrast, the ESP assembly 250 may be more readily removed from the wellbore from within the production tubing 223, and offers significant advantages over a conventional ESP assembly. For example, the ESP assembly 250 be conveyable within the production tubing 223 eliminates the need for a workover rig, but rather, the ESP assembly 250 is conveyable via a WL or CT conveyance system which are faster, simpler, more costefficient, and safer than heavy-duty drill rigs. This provides flexibility for accessing and/or replacing the ESP assembly 250 more efficiently, by reducing downtime, minimizing production loss, avoiding operational costs of expensive rig mobilizations, and improving safety. Additionally, because the completion components are not removed, the ESP assembly can be retrieved from a live wellbore while avoiding damage to the formation, wellbore, etc.

[0049] Turning now to FIG. 3-1, this figure illustrates a helicoaxial pump 351, according to at least one embodiment of the present disclosure. The helicoaxial pump 351 may be an example of the pump 251 of FIG. 2-3. The helicoaxial pump 351 may be implemented as various pump stages, however, FIG. 3-1 is illustrative of a single stage of the helicoaxial pump 351. Each pump stage includes an impeller 361 and a diffuser 362. The impeller 361 may operate to accelerate and/or to impart kinetic energy to the fluid, after which the fluid may flow to the diffuser 362. The diffuser 362 may be a stationary component and may interact with the moving fluid to convert the fluid’s movement, or kinetic energy, into potential energy in the form of a pressure increase, or head, of the fluid. In many cases, the helicoaxial pump 351 may consist of many pump stages, with each stage operating to increase, or build additional pressure (e.g., head) sufficient to lift the fluid to the surface.

[0050] The helicoaxial pump 351 may be helicoaxial based on the impeller 361 having one or more helical blades or vanes 363. For example, the vanes 363 may be positioned around the impeller 361 in a helical manner, such that the vanes 363 may at least partially form a spiral or helix about the impeller 361. This may be in contrast to, for example, other styles of pump stages, which may utilize impellers and blades that have a more vertical or axial orientation. For example, FIG. 3-2 illustrates an example of an ESP pump 346 that does not have helicoaxial blades. Rather, as shown, the ESP pump 346 has blades 347 of an impeller 348 which are much more upright, vertical, or axial. [0051] Turning back to FIG. 3-1, as the impeller 361 spins, the vanes 363 create a combination of axial and rotational motion of a fluid flowing through the helicoaxial pump 351. For instance, the rotating helical impeller 361 imparts both axial and tangential velocity to the fluid, creating a swirling motion that transfers energy to the fluid, which swirling motion is directed in a generally axial direction. This may be in contrast to, for example, other pumps (e.g., centrifugal or multiphase pumps) having non-helicoaxial blades, which may rely on radial acceleration and/or which may accelerate the fluid having an outward, radial, or centrifugal component.

[0052] The impeller 361 in this way advantageously accelerates the fluid without causing phase separation. For example, the helical impeller 361 operates to move the fluid along the pump axis, reducing turbulence and maintaining a homogeneous flow. In conventional pump stages, abrupt energy transfer to the fluid tends to separate and/or collect free gas along the blades of the impeller, which can lead to gas locking of the pump stage. In contrast, the impeller 361 allows for gradual energy transfer, ensuring that both gas and liquid receive uniform acceleration and minimizing the potential for gas separation and gas lock of the pump stage.

[0053] In this way, the helicoaxial pump 351 may significantly reduce the risk of gas lock, allowing for stable and efficient operation in environments with elevated gas fractions. For example, conventional pump stages may tend to experience gas lock at gas volume fractions (GVF) of 30%-40%, while the helicoaxial pump 351 may operate at up to 75% GVF or higher without experiencing gas lock. For example, in some cases, the helicoaxial pump 351 may operate effectively at GVF levels of up to 85% or 90%. In some cases, the helicoaxial pump 351 can even operate at a GVF of 100% without experiencing gas lock. Thus, the helicoaxial pump 351 may effectively operate for pumping liquid-gas multiphase fluid flows having elevated GVF levels, providing significant benefits over other and/or conventional types of pump stages.

[0054] Furthermore, the helicoaxial pump 351 may provide adaptability advantages as well. For instance, as wells mature and gas content increases, conventional ESP pumps often require frequent adjustments, replacements, or costly gas-handling upgrades. The helicoaxial pump 351, however, may naturally adjust or compensate to evolving flow conditions, reducing the need for interventions and extending well productivity. By ensuring continuous operations in gas-rich environments, the helicoaxial pump 351 may maintain higher production rates and improve overall field economics.

[0055] In this way, the ESP assemblies described herein may benefit from implementing the helicoaxial pump 351 over that of other, conventional pump types. For example, as described above, the ESP assemblies may be equipped with a gas separator which may operate to remove gasses from a flow of production fluid. In some cases, gasses may remain in the production fluid notwithstanding the gas separation efforts. For example, in some cases, less than all of a gas is removed from the production fluid. In other cases, some types of gasses are removed while others remain. For instance, in the case of methane hydrate formations, methane gasses may be substantially or entirely removed from the production fluid, while other gasses may nevertheless be present in the production fluid flowing to and through the pump. In this way, it may be advantageous to implement the helicoaxial pump 351 as described.

[0056] Another advantage is that the helicoaxial pump 351 may have a smaller form factor and/or a smaller diameter than other types of pump stages. For example, because the mode of operation of the helicoaxial pump 351 accelerates the fluid in an axial direction, it may not be necessary to leverage a large diameter of the heli coaxial pump for generating pressure. For example, other pumps which may accelerate fluid centrifugally in a radial direction may rely on larger radii in order to effectively generate pressure in the fluid. Accordingly, it may be advantageous to implement such pump stages with a larger diameter. In contrast, the operating principle of the helicoaxial pump 351 may be independent of a radial dimension, facilitating an overall smaller form factor.

[0057] This smaller form may be beneficial for implementation of the helicoaxial pump 351 in a rigless ESP assembly in which the ESP assembly is implemented within a production tubing. For example, radial space may be limited within the production tubing as compared to an ESP assembly implemented as part of the production tubing, which may afford more space within a larger, production casing. Accordingly, the helicoaxial pump 351 may facilitate the rigless and/or conveyable nature of the ESP assemblies as described herein.

[0058] While helicoaxial pumps may provide for smaller form factors and gas handling capabilities, in some cases helicoaxial pumps may generate less head than other, conventional pump types. For instance, in some cases, (e g., standard and/or non-high- speed) helicoaxial pumps may generate up to about 15 feet of head per pump stage, which may accordingly require many pump stages to generate sufficient head for artificial lift purposes. Helicoaxial pumps, and other pump types as well, may operate at frequencies of about 50 Hz to about 60 Hz, or from about 3000 rpm to about 3600 rpm. In some cases, these pumps may operate at less than 70 Hz.

[0059] In some cases, the helicoaxial pump 351 may be a high-speed helicoaxial pump. The helicoaxial pump 351 operating at higher speeds may facilitate generating considerably more pressure and/or head. For example, in some cases, the helicoaxial pump 351 may operate at frequencies of up to 70 Hz or greater (4200 rpm). In some cases, the helicoaxial pump 351 operates at 100 Hz or greater (6000 rpm). In some cases, the helicoaxial pump 351 operates at up to 120 Hz (7200 rpm). The helicoaxial pump 351 may be configured to operate at these higher speeds based on an associated motor of a corresponding ESP assembly. For example, the motor for driving the stages of the helicoaxial pump 351 may be configured to operate with sufficient power and speed to achieve these higher frequencies of the helicoaxial pump 351.

[0060] Based on the helicoaxial pump being a high-speed implementation, helicoaxial pump may generate head of more than 15 feet. For example, the high-speed helicoaxial pump may generate 40 feet or more of head. In another example, the high-speed helicoaxial pump generates up to 100 feet of head. Increasing the speed in this way may facilitate generating more head based on the principle that the head or pressure is proportional to the square of the shaft speed. Thus, by the helicoaxial pump 351 being a high-speed helicoaxial pump that operates at twice the speed of a conventional (e.g., helicoaxial) implementation, 4 times as much pressure may be generated. 3 times the shaft speed may generate 8 times as much pressure, and so on.

[0061] In this way, the helicoaxial pump 351 may provide gas-handling and spacesaving benefits, and may additionally provide sufficient head for lifting the production fluid to the surface. For example, conventional ESPs may employ up to 150, up to 200, or even up to 500 pump stages in order to generate sufficient lift. The helicoaxial pump 351, however, may be implemented with as few as 50 pump stages, or less than 50 pump stages. Additionally, the pump stages of the helicoaxial pump 351 may result in an overall axial length of the pump of 35 feet or less. In contrast, other conventional ESP assemblies may have pumps that are upwards of 50, 100, or 150 feet in axial length. This reduced length may facilitate implementing the ESP assemblies described herein as rigless and/or conveyable ESP assemblies, among other benefits.

[0062] Further, the helicoaxial pump 351 may be implemented (e.g., via multiple pump stages) without any other types of pumps and/or pump stages in addition to the helicoaxial pump 351. For example, in some cases, helicoaxial pumps are implemented in ESP assemblies for leveraging their gas-handling capabilities as a charge phase of the ESP assembly, and one or more other (e.g., conventional) types of pumps may be implemented downstream (e.g., uphole) of the helicoaxial charge stage for generating the pressure and/or lift. As described herein, the helicoaxial pump 351 may be operated as a high-speed helicoaxial pump for generating sufficient lift such that no other phase or pumps may be needed for supplementing the head generating by the helicoaxial pump 351.

[0063] FIG. 4 illustrates a flow diagram for a method 400 or a series of acts for producing a gas at a surface of a wellbore as described herein, according to at least one embodiment of the present disclosure. While FIG. 4 illustrates acts according to one embodiment, alternative embodiments may add to, omit, reorder, or modify any of the acts of FIG. 4.

[0064] In some embodiments, the method 400 includes an act 410 of driving a highspeed helicoaxial pump positioned inside of a production tubing with a motor positioned inside of the production tubing, wherein the high-speed helicoaxial pump and the motor are part of a rigless electrical submersible pump (ESP) assembly that is conveyable within the production tubing.

[0065] In some embodiments, the method 400 includes an act 420 of pumping a flow of a production fluid from an underground reserve based on generating, with the highspeed helicoaxial pump, a head of the production fluid to lift the production fluid to the surface.

[0066] In some embodiments, the method 400 includes an act 430 of flowing the production fluid through the production tubing. [0067] In some embodiments, the method 400 includes an act 440 of separating, with a gravity-assisted gas separator positioned downhole from the helicoaxial pump, a gas phase and a liquid phase from the production fluid.

[0068] In some embodiments, the method 400 includes an act 450 producing the gas phase at the surface based on flowing the gas phase through an annulus between the wellbore and the production tubing.

[0069] In some embodiments, the method 400 further includes operating the highspeed helicoaxial pump at 70 Hz or greater, and producing, in the liquid phase, more than 15 feet of head per pump stage.

[0070] In some embodiments, operating the high-speed helicoaxial pump includes operating no more than 50 pump stages.

[0071] FIG. 5 illustrates a method 500 or a series of acts for producing methane gas from a wellbore as described herein, according to at least one embodiment of the present disclosure. While FIG. 5 illustrates acts according to one embodiment, alternative embodiments may add to, omit, reorder, or modify any of the acts of FIG. 5.

[0072] In some embodiments, the method 500 includes an act 510 of positioning an electrical submersible pump (ESP) assembly within a production tubing located in the wellbore based on conveying the ESP assembly through the production tubing with a conveyance line.

[0073] In some embodiments, the method 500 includes an act 520 of forming an electrical connection with the ESP assembly at a receptacle of the production tubing to connect the ESP assembly through the production tubing to a power transmission line positioned outside of the production tubing and extending from a surface of the wellbore.

[0074] In some embodiments, the method 500 includes an act 530 of transmitting electrical power to a downhole motor of the ESP assembly with the power transmission line to drive a high-speed helicoaxial pump of the ESP assembly at at least 70 Hz.

[0075] In some embodiments, the method 500 includes an act 540 of with the highspeed helicoaxial pump, pumping a flow of an aqueous production fluid from a methane hydrate formation to release methane gas from a solid state, wherein pumping the aqueous production fluid includes generating at least 15 feet of head of the aqueous production fluid per pump stage of the high-speed helicoaxial pump, in some embodiments, pumping the flow of the aqueous production fluid includes utilizing no more than 50 pump stages of the high-speed helicoaxial pump.

[0076] In some embodiments, the method 500 includes an act 550 of separating methane gas from a water phase of the aqueous production fluid at a gravity-assisted gas separator positioned downhole from the ESP assembly.

[0077] In some embodiments, the method 500 includes an act 560 of producing the methane gas at the surface based on flowing the methane gas through an annulus between the wellbore and the production tubing.

INDUSTRIAL APPLICABILITY

[0078] The following description from section A1-C2 includes various embodiments that, where feasible, may be combined in any permutation. For example, the embodiment of section Al may be combined with any or all embodiments of the following paragraphs. Embodiments that describe acts of a method may be combined with embodiments that describe, for example, systems and/or devices. Any permutation of the following paragraphs is considered to be hereby disclosed for the purposes of providing “unambiguously derivable support” for any claim amendment based on the following paragraphs. Furthermore, the following paragraphs provide support such that any combination of the following paragraphs would not create an “intermediate generalization.”

Al . A wellbore production system, comprising: a production tubing positioned within a wellbore; an electrical submersible pump (ESP) assembly positioned within the production tubing, the ESP assembly being a rigless ESP assembly conveyable within the production tubing by a conveyance line, the ESP assembly including: a high-speed helicoaxial pump; and a motor for driving the helicoaxial pump; a power transmission line extending from a surface of the wellbore outside of the production tubing, and connecting through the production tubing to the motor; and a gravity-assisted gas separator connected to the production tubing and connected to an intake of the ESP assembly.

A2. The wellbore production system of Al, wherein the motor and the high-speed helicoaxial pump are configured to operate at 70 Hz or greater.

A3. The wellbore production system of Al or A2, wherein the motor and the highspeed helicoaxial pump are configured to operate at 100 Hz or greater.

A4. The wellbore production system of any of A1-A3, wherein the motor and the high-speed helicoaxial pump are configured to operate at up to 120 Hz.

A5. The wellbore production system of any of A1-A4, wherein the high-speed helicoaxial pump includes less than 50 pump stages.

A6. The wellbore production system of any of A1-A5, wherein each stage of the highspeed helicoaxial pump is configured to produce more than 15 feet of head.

A7. The wellbore production system of any of A1-A6, wherein the high-speed helicoaxial pump has an axial length of 35 feet or less.

A8. The wellbore production system of any of A1-A7, wherein the ESP assembly does not include a pump in addition to the high-speed helicoaxial pump.

A9. The wellbore production system of any of A1-A8, wherein the conveyance line is a wireline (WL) or a coiled tubing (CT).

A10. The wellbore production system of any of A1-A9, wherein the production tubing is positioned in the wellbore to access a methane hydrate formation, and the gravity-assisted gas separator separates methane gas from water. Al l . The wellbore production system of Al 0, wherein the separated methane gas is configured to flow to the surface in an annulus between the wellbore and the production tubing.

A12. The wellbore production system of any of Al-Al 1, the gravity-assisted gas separator is a passive gas separator and does not include an active gas-separation mechanism.

A13. The wellbore production system of any of A1-A12, wherein the system does not include a gas separator in addition to the gravity-assisted gas separator.

A14. The wellbore production system of any of A1-A13, wherein the production tubing does not included a packer positioned uphole of the ESP assembly.

A15. The wellbore production system of any of A1-A14, wherein the high-speed helicoaxial pump is configured to operate at up to 75% gas volume fraction (GVF) without experiencing gas lock.

Al 6. The wellbore production system of any of Al-Al 5, wherein the production tubing is 6 inches or less in diameter.

Bl. A method of producing a gas at a surface of a wellbore, comprising: driving a high-speed helicoaxial pump positioned inside of a production tubing with a motor positioned inside of the production tubing, wherein the high-speed helicoaxial pump and the motor are part of a rigless electrical submersible pump (ESP) assembly that is conveyable within the production tubing; pumping a flow of a production fluid from an underground reserve based on generating, with the high-speed helicoaxial pump, a head of the production fluid to lift the production fluid to the surface; flowing the production fluid through the production tubing; separating, with a gravity-assisted gas separator positioned downhole from the high-speed helicoaxial pump, a gas phase and a liquid phase from the production fluid; and producing the gas phase at the surface based on flowing the gas phase through an annulus between the wellbore and the production tubing.

B2. The method of Bl, further comprising operating the high-speed helicoaxial pump at 70 Hz or greater, and producing, in the liquid phase, more than 15 feet of head per pump stage.

B3. The method of Bl or B2, wherein operating the high-speed helicoaxial pump includes operating no more than 50 pump stages.

Cl . A method of producing methane gas from a wellbore, comprising: positioning an electrical submersible pump (ESP) assembly within a production tubing located in the wellbore based on conveying the ESP assembly through the production tubing with a conveyance line; forming an electrical connection with the ESP assembly at a receptacle of the production tubing to connect the ESP assembly through the production tubing to a power transmission line positioned outside of the production tubing and extending from a surface of the wellbore; transmitting electrical power to a downhole motor of the ESP assembly with the power transmission line to drive a high-speed helicoaxial pump of the ESP assembly at at least 70 Hz; with the high-speed helicoaxial pump, pumping a flow of an aqueous production fluid from a methane hydrate formation to release methane gas from a solid state, wherein pumping the aqueous production fluid includes generating at least 15 feet of head of the aqueous production fluid per pump stage of the high-speed helicoaxial pump; separating methane gas from a water phase of the aqueous production fluid at a gravity-assisted gas separator positioned downhole from the ESP assembly; and producing the methane gas at the surface based on flowing the methane gas through an annulus between the wellbore and the production tubing.

C2. The method of Cl, wherein pumping the flow of the aqueous production fluid includes utilizing no more than 50 pump stages of the high-speed helicoaxial pump. [0079] The embodiments of the production systems herein have been primarily described with reference to wellbore drilling operations; the production systems described herein may be used in applications other than the drilling of a wellbore. In other embodiments, the production systems according to the present disclosure may be used outside a wellbore or other downhole environment used for the exploration or production of natural resources. For instance, the production systems of the present disclosure may be used in a borehole used for placement of utility lines. Accordingly, the terms “wellbore,” “borehole” and the like should not be interpreted to limit tools, systems, assemblies, or methods of the present disclosure to any particular industry, field, or environment.

[0080] One or more specific embodiments of the present disclosure are described herein. These described embodiments are examples of the presently disclosed techniques. Additionally, in an effort to provide a concise description of these embodiments, not all features of an actual embodiment may be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous embodiment-specific decisions will be made to achieve the developers’ specific goals, such as compliance with system-related and business-related constraints, which may vary from one embodiment to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.

[0081] Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. For example, any element described in relation to an embodiment herein may be combinable with any element of any other embodiment described herein. Numbers, percentages, ratios, or other values stated herein are intended to include that value, and also other values that are “about” or “approximately” the stated value, as would be appreciated by one of ordinary skill in the art encompassed by embodiments of the present disclosure. A stated value should therefore be interpreted broadly enough to encompass values that are at least close enough to the stated value to perform a desired function or achieve a desired result. The stated values include at least the variation to be expected in a suitable manufacturing or production process, and may include values that are within 5%, within 1%, within 0.1%, or within 0.01% of a stated value.

[0082] A person having ordinary skill in the art should realize in view of the present disclosure that equivalent constructions do not depart from the spirit and scope of the present disclosure, and that various changes, substitutions, and alterations may be made to embodiments disclosed herein without departing from the spirit and scope of the present disclosure. Equivalent constructions, including functional “means-plus-function” clauses are intended to cover the structures described herein as performing the recited function, including both structural equivalents that operate in the same manner, and equivalent structures that provide the same function. It is the express intention of the applicant not to invoke means-plus-function or other functional claiming for any claim except for those in which the words ‘means for’ appear together with an associated function. Each addition, deletion, and modification to the embodiments that falls within the meaning and scope of the claims is to be embraced by the claims.

[0083] The terms “approximately,” “about,” and “substantially” as used herein represent an amount close to the stated amount that is within standard manufacturing or process tolerances, or which still performs a desired function or achieves a desired result. For example, the terms “approximately,” “about,” and “substantially” may refer to an amount that is within less than 5% of, within less than 1% of, within less than 0.1% of, and within less than 0.01% of a stated amount. Further, it should be understood that any directions or reference frames in the preceding description are merely relative directions or movements. For example, any references to “up” and “down” or “above” or “below” are merely descriptive of the relative position or movement of the related elements. Additionally, as used herein, the term “and/or” includes any and all combinations of one or more of the associated listed items.

[0084] The present disclosure may be embodied in other specific forms without departing from its spirit or characteristics. The described embodiments are to be considered as illustrative and not restrictive. The scope of the disclosure is, therefore, indicated by the appended claims rather than by the foregoing description. Changes that come within the meaning and range of equivalency of the claims are to be embraced within their scope.

Claims

CLAIMS What is claimed is:

1. A wellbore production system, comprising: a production tubing positioned within a wellbore; an electrical submersible pump (ESP) assembly positioned within the production tubing, the ESP assembly being a rigless ESP assembly conveyable within the production tubing by a conveyance line, the ESP assembly including: a high-speed helicoaxial pump; and a motor for driving the helicoaxial pump; a power transmission line extending from a surface of the wellbore outside of the production tubing, and connecting through the production tubing to the motor; and a gravity-assisted gas separator connected to the production tubing and connected to an intake of the ESP assembly.

2. The wellbore production system of claim 1, wherein the motor and the high-speed helicoaxial pump are configured to operate at 70 Hz or greater.

3. The wellbore production system of claim 1, wherein the motor and the high-speed helicoaxial pump are configured to operate at 100 Hz or greater.

4. The wellbore production system of claim 1, wherein the motor and the high-speed helicoaxial pump are configured to operate at up to 120 Hz.

5. The wellbore production system of claim 1, wherein the high-speed helicoaxial pump includes less than 50 pump stages.

6. The wellbore production system of claim 1, wherein each stage of the high-speed helicoaxial pump is configured to produce more than 15 feet of head.

7. The wellbore production system of claim 1, wherein the high-speed helicoaxial pump has an axial length of 35 feet or less.

8. The wellbore production system of claim 1, wherein the ESP assembly does not include a pump in addition to the high-speed helicoaxial pump.

9. The wellbore production system of claim 1, wherein the conveyance line is a wireline (WL) or a coiled tubing (CT).

10. The wellbore production system of claim 1, wherein the production tubing is positioned in the wellbore to access a methane hydrate formation, and the gravity- assisted gas separator separates methane gas from water.

11. The wellbore production system of claim 10, wherein the separated methane gas is configured to flow to the surface in an annulus between the wellbore and the production tubing.

12. The wellbore production system of claim 1, the gravity-assisted gas separator is a passive gas separator and does not include an active gas-separation mechanism.

13. The wellbore production system of claim 1, wherein the system does not include a gas separator in addition to the gravity-assisted gas separator.

14. The wellbore production system of claim 1, wherein the production tubing does not included a packer positioned uphole of the ESP assembly.

15. The wellbore production system of claim 1, wherein the high-speed helicoaxial pump is configured to operate at up to 75% gas volume fraction (GVF) without experiencing gas lock.

16. The wellbore production system of claim 1, wherein the production tubing is 6 inches or less in diameter.

17. A method of producing a gas at a surface of a wellbore, comprising: driving a high-speed helicoaxial pump positioned inside of a production tubing with a motor positioned inside of the production tubing, wherein the high-speed helicoaxial pump and the motor are part of a rigless electrical submersible pump (ESP) assembly that is conveyable within the production tubing; pumping a flow of a production fluid from an underground reserve based on generating, with the high-speed helicoaxial pump, a head of the production fluid to lift the production fluid to the surface; flowing the production fluid through the production tubing; separating, with a gravity-assisted gas separator positioned downhole from the high-speed helicoaxial pump, a gas phase and a liquid phase from the production fluid; and producing the gas phase at the surface based on flowing the gas phase through an annulus between the wellbore and the production tubing.

18. The method of claim 17, further comprising operating the high-speed helicoaxial pump at 70 Hz or greater, and producing, in the liquid phase, more than 15 feet of head per pump stage.

19. The method of claim 17, wherein operating the high-speed helicoaxial pump includes operating no more than 50 pump stages.

20. A method of producing methane gas from a wellbore, comprising: positioning an electrical submersible pump (ESP) assembly within a production tubing located in the wellbore based on conveying the ESP assembly through the production tubing; forming an electrical connection with the ESP assembly at a receptacle of the production tubing to connect the ESP assembly through the production tubing to a power transmission line positioned outside of the production tubing and extending from a surface of the wellbore; transmitting electrical power to a downhole motor of the ESP assembly with the power transmission line to drive a high-speed helicoaxial pump of the ESP assembly at at least 70 Hz; with the high-speed helicoaxial pump, pumping a flow of an aqueous production fluid from a methane hydrate formation to release methane gas from a solid state, wherein pumping the aqueous production fluid includes generating at least 15 feet of head of the aqueous production fluid per pump stage of the high-speed helicoaxial pump; separating methane gas from a water phase of the aqueous production fluid at a gravity-assisted gas separator positioned downhole from the ESP assembly; and producing the methane gas at the surface based on flowing the methane gas through an annulus between the wellbore and the production tubing.