High-speed screw axial flow pump system without drilling rig

Abstract

A wellbore production system includes a production tubing located within a wellbore and an electric submersible pump (ESP) assembly located within the production tubing. The ESP assembly is a rigless ESP assembly that can be conveyed within the production tubing by a conveyance line. The ESP assembly includes a high-speed helico-axial pump and a motor for driving the helico-axial pump. A power transmission line extends from the surface of the wellbore outside the production tubing and connects to the motor through the production tubing. The wellbore production system includes a gravity-assisted gas separator connected to the production tubing and to a suction inlet of the ESP assembly.

Description

Cross-reference to related applications

[0001] This application claims priority and interest in U.S. Provisional Patent Application No. 63 / 558,267, filed February 27, 2024, and U.S. Provisional Patent Application No. 63 / 678,763, filed August 2, 2024, the entire contents of which are incorporated herein by reference. Background Technology

[0002] Wellbores can be drilled into surface locations or the seabed for various exploration or extraction purposes. For example, wellbores can be drilled to access fluids (such as liquid and gaseous hydrocarbons) stored in underground formations and to extract fluids from the formations. Wellbores used for producing or extracting fluids can be formed in the formation using drilling tools such as drill bits for drilling wellbores and reamers for enlarging the wellbore diameter. Some wellbores can be equipped with electric submersible pumps (ESPs) to facilitate the flow of producing fluids to the surface of the wellbore. Attached Figure Description

[0003] To describe how the above and other features of this disclosure are obtained, a more specific description will be presented by reference to the specific embodiments shown in the accompanying drawings. For better understanding, the same elements have been denoted by the same reference numerals throughout the drawings. While some in the drawings may be schematic or exaggerated representations of concepts, at least some in the drawings may be drawn to scale. It should be understood that the drawings depict some exemplary embodiments, which will be described and explained in more specific and detailed manner by means of the drawings, in which: Figure 1-1 An example of a wellbore system for drilling a surface formation to form a wellbore, according to at least one embodiment of the present disclosure, is shown; Figure 2-1 Examples of production systems that can be implemented to produce one or more underground resources according to at least one embodiment of the present disclosure are shown; Figure 2-2 At least one embodiment according to this disclosure is shown. Figure 2-1 An enlarged view of the gas separator in the production system, showing the flow of production fluid through the separator; Figure 2-3 At least one embodiment according to this disclosure is shown. Figure 2-1 An enlarged view of the electric submersible pump assembly of the production system; Figure 3-1 A helical axial flow pump according to at least one embodiment of the present disclosure is shown; Figure 3-2 An example of an electric submersible pump without helical axial flow blades according to at least one embodiment of the present disclosure is shown; Figure 4 A flowchart illustrating a method or series of steps for surface gas production in a wellbore described herein, according to at least one embodiment of the present disclosure; and Figure 5 A flowchart is shown of a method or series of steps for producing methane from a wellbore described herein, according to at least one embodiment of the present disclosure. Detailed Implementation

[0004] This disclosure generally relates to electric submersible pump (ESP) assemblies for use in wellbore applications to generate artificial lift. The ESP assemblies described herein are retrievable, transportable, and / or drill-free ESP assemblies that can be located within (e.g., installed) production tubing and recovered / transported through said production tubing. Power transmission to the ESP assembly is achieved via a power transmission line located outside the production tubing, and a socket facilitates connection of the ESP assembly to the power transmission line. In this way, the ESP assembly can be drill-free, thereby enabling simpler, faster, easier, more cost-effective, and more flexible deployment, recovery, maintenance, and / or replacement of ESP assemblies in wellbore completions.

[0005] The ESP assembly can be equipped with a pump, specifically a helical axial flow pump. For example, the helical axial flow pump can have an impeller section in each stage, with helical or spiral impeller blades to impart movement of the production fluid in a generally axial direction. This facilitates the generation of pressure or head on the production fluid without causing phase change and / or gas separation, thus preventing gas lock-in. Furthermore, the helical axial flow pump can provide a smaller overall form factor, which can benefit the delivery characteristics of the production tubing in the ESP assembly, particularly for small-diameter production tubing.

[0006] Helical axial flow pumps can also be high-speed helical axial flow pumps, which can operate at higher frequencies than conventional ESP components. For example, high-speed helical axial flow pumps can operate at speeds greater than 70 Hz (such as up to 120 Hz). These higher speeds can facilitate the generation of a larger head than typically achieved with helical axial flow pumps, allowing ESP components to be configured with only a helical axial flow pump stage, without other types or stages of pumps. For example, a helical axial flow pump can be implemented not only as a booster stage in an ESP system, but also as the sole head generating the entire ESP component. The high-speed characteristics of helical axial flow pumps can facilitate sufficient artificial lift to produce the production fluid on the ground while maintaining a small overall axial length of the pump.

[0007] The production system described herein may also include a gravity-assisted gas separator. For example, the gas separator may be a passive gas separator that operates based on the density difference between the gas and liquid phases of the production fluid to separate the gas phase. As the production fluid flows through the inverted shroud assembly, the gas phase may separate from, dissociate from, or otherwise escape from the liquid phase and may flow upwards along the annulus of the wellbore. In a particular example, a gravity-assisted gas separator may facilitate the separation and production of methane gas from methane hydrate formations, which can be produced at the surface via the annulus.

[0008] Additional details about the system described herein will now be provided with reference to the illustrative drawings illustrating exemplary embodiments. For example, Figure 1-1 An example of a wellbore system 100 for drilling into surface formation 101 to form a wellbore 102 is shown. The wellbore system 100 includes a drilling rig 103 for rotating a drill string assembly 104 that extends downward into the wellbore 102. The drill string assembly 104 may include a drill string 105, a bottom hole assembly (“BHA”) 106, and a drill bit 110 attached to the downhole end of the drill string 105.

[0009] The drill string 105 may include several joints of the drill pipe 108 connected end-to-end via a tool joint 109. The drill string 105 transmits drilling fluid through a center bore and transmits rotational power from the drilling rig 103 to the BHA 106. In some embodiments, the drill string 105 may also include additional downhole tools and / or components, such as subs, shorts, etc. The drill pipe 108 provides a hydraulic passage through which drilling fluid is pumped from the surface. The drilling fluid exits through nozzles, orifices, or other orifices of selected size in the drill bit 110 to cool the drill bit 110 and its cutting structures, and to lift cuttings out of the wellbore when the wellbore 102 is drilled.

[0010] BHA 106 may include drill bit 110, other downhole tools, or other components. Example BHA 106 may include additional or other downhole tools or components (e.g., connected between drill string 105 and drill bit 110). Examples of additional BHA components include drill collars, stabilizers, measurement-while-drilling (“MWD”) tools, logging-while-drilling (“LWD”) tools, downhole motors, downhole reamers, casing shoes, hydraulic disconnect joints, slappers, vibration or damping tools, other components, or combinations thereof.

[0011] Generally, wellbore system 100 may include other downhole drilling tools, components, and accessories, such as specialized valves (e.g., crisscross plugs, blowout preventers, and safety valves). Additional components included in wellbore system 100 may be considered part of drill string assembly 104, drill string 105, or BHA 106, depending on their location within wellbore system 100.

[0012] Drill bit 110 in BHA 106 can be any type of drill bit suitable for eroding downhole materials. For example, drill bit 110 can be a drill bit suitable for drilling into surface formation 101. Example drill bit types for drilling into surface formations are fixed-cutting or scraper bits. In other embodiments, drill bit 110 can be a milling shoe for removing metal, composite materials, elastomers, other downhole materials, or combinations thereof. For example, drill bit 110 can be used with a directional drilling tool to mill into casing 107 fitted onto wellbore 102. Drill bit 110 can also be a flat-end milling shoe for milling away tools, plugs, cement, other materials, or combinations thereof within wellbore 102. Drill cuttings or other rock cuttings generated by using the milling shoe can be lifted to the surface or allowed to fall downhole. Drill bit 110 may include one or more cutting elements for degrading surface formation 101.

[0013] BHA 106 may also include a rotary steerable system (RSS). The RSS may include a directional drilling tool that changes the orientation of the drill bit 110, and thereby alters 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 gravity, magnetic north, or true north, or one or more). Using measurements obtained from the geostationary position, the RSS can position the drill bit 110, change the path of the drill bit 110, and guide the directional drilling tool along a predetermined trajectory. The RSS can guide the drill bit 110 based on or according to its trajectory. For example, a trajectory for guiding the drill bit 110 toward one or more subsurface targets (such as oil or gas reservoirs) can be determined.

[0014] Wellbore system 100 can be implemented as part of a drilling and / or wellbore forming configuration, as shown and described. In some cases, wellbore system 100 can be implemented as a completion and / or production configuration with different downhole component configurations. For example, production system 111 represents an alternative or subsequent implementation of at least a portion of wellbore system 100, having a combination of downhole components for the production phase of wellbore system 100. In some cases, after wellbore 102 is formed, one or more production or completion components can be installed or implemented in wellbore 102 to facilitate the production and removal of production fluid 144 from reservoir 142. For example, in some cases, an electric submersible pump (ESP) 140 and associated components can be implemented in wellbore 102 to provide production fluid 144 with, for example, a supplemental pressure and / or flow rate higher than that provided by reservoir 142. In this way, ESP 140 can facilitate the flow of production fluid 144 to the surface.

[0015] In some cases, reservoir 142 may represent a methane hydrate formation. For example, in some formations (e.g., subsea formations), methane gas exists in solid or crystalline form bound to solid water (other aqueous substances) based on formation pressure and / or temperature. Production fluid 144 may represent an aqueous fluid (e.g., water) that can be pumped or removed from reservoir 142, which in turn reduces the pressure of the reservoir, thereby releasing methane in gaseous form. For example, methane hydrates are crystalline, ice-like structures in which methane molecules are trapped in a lattice of water molecules 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. Therefore, production fluid 144 may include an aqueous fluid in which methane gas is dispersed or through which methane gas flows. By allowing the aqueous fluid to flow and separate from the methane gas, methane gas can be produced on the surface.

[0016] Figure 2-1 An example of a production system 211, which can be implemented to produce one or more underground resources according to at least one embodiment of the present disclosure, is shown. The production system 211 may be a wellbore production system implemented in a wellbore formed in the formation, such as combined with... Figure 1-1 The system described above. For example, after part or all of the wellbore 202 has been formed, one or more components of the production system 211 may be combined or replaced. Figure 1-1 One or more of the components of the wellbore system 100 shown may be used to implement this system. For example, production system 211 may include a collection of components for controlling and / or lifting production fluids from a reservoir, formation, or other subsurface reservoir where resources exist. Production system 111 may be implemented with fewer and / or more components than those shown and described herein in order to produce one or more resources at the surface of wellbore 202.

[0017] In some embodiments, production system 211 includes various surface components 220. Surface components 220 may include wellhead equipment for controlling and directing the flow of production fluids on the surface. For example, surface components 220 may include electrical components such as variable speed drives and step-up transformers for supplying power to one or more downhole components of production system 211. Surface equipment may include flow control devices such as various valves, blowout preventers, etc. In some cases, surface components 220 may include a tree, for example, having sufficient through-holes for one or more components (such as the ESP assembly described herein) to pass through or deliver as a rig-free deployment.

[0018] In some cases, one or more layers of casing can be installed in the wellbore and connected to it. For example, Figure 2-1The wellbore 202 shown may represent an open-hole wellbore, or a casing wellbore with one or more tubing strings or casings connected thereto for supporting the wellbore, isolating the formation, etc. In some cases, production casing 222 may be located within the wellbore 202. Furthermore, production tubing 223 may be located within production casing 222. Production tubing 223 may be a tubular component for circulating fluids and / or producing production fluids (e.g., formation fluids) via production system 211. For example, production tubing 223 may extend downwards from the surface of wellbore 202 to production area 229, such as at or near an underground reservoir.

[0019] In some cases, the production casing 221 may be secured (e.g., permanently or semi-permanently) within the wellbore 202 via a production packer 224. The production packer 224 may conveniently isolate the reservoir area and / or provide access for the production tubing 223 to the production zone 229. The production tubing 223 may be positioned and / or secured (e.g., permanently or semi-permanently) within the production casing 221 via a production tubing packer 225.

[0020] Based on the configuration of the production casing 221 and the production tubing 223, production fluid can flow into the production tubing 223, for example, for surface production. In some cases, the production tubing 223 may include a reservoir isolation valve 226 and / or a deep well downhole safety valve 227. One or more of these valves can facilitate control of the pressure and / or flow rate of the production fluid from the production zone 229.

[0021] Production system 211 includes ESP assembly 250. As will be discussed in detail below, ESP assembly 250 includes a high-speed helical axial flow pump for pumping production fluid upward through production line 223. For example, production fluid 244 may flow from production area 229 to the ground based at least in part on the artificial lift or head generated by ESP assembly 250.

[0022] 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 example, the gas separator 230 may not include any moving parts, and the device may not actively perform any actions, movements, or processes for separating the gas. Specifically, the gas separator 230 may rely on gravity and the natural flow of various components or phases of the fluid to facilitate the natural rise of gas or its escape from the (e.g., downward) flow of the fluid.

[0023] Figure 2-2An enlarged view of a gas separator 230 according to at least one embodiment of the present disclosure is shown, illustrating the flow of production fluid 244 through the separator. Production fluid 244 can be produced from a reservoir or other production zone of the formation via production system 211. Production fluid 244 can flow into production tubing 223 (e.g., via production casing 221) based on the reservoir's natural pressure or flow and / or based on artificial lift provided by ESP component 250.

[0024] In some cases, the production fluid 244 includes gases dispersed, dissolved, or mixed therein. For example, hydrocarbon gases, carbon dioxide gases, hydrogen, nitrogen, or other gases may be included in the flow of production fluid 244 from the reservoir. As mentioned above, in some cases, methane gas may be released from the solid cage-like hydrate structure along with water and may flow upward with and / or through the water flow.

[0025] Production fluid 244 may initially flow through production tubing 223 (e.g., upwards or toward the wellhead) and may exit production tubing 223 at perforated sub 231. From there, production fluid 244 may flow through the annulus 228 between production tubing 223 and production casing 221. Gas separator 230 may be configured with an inverted shroud 232, which facilitates the separation of gas from production fluid 244. For example, starting from annulus 228, production fluid 244 may overflow, flow into, or otherwise pass through the inverted shroud 232, which may alter the flow direction of production fluid 244. For example, production fluid 244 may tend to flow in the direction of gravity, which may cause production fluid 244 to flow downwards into the inverted shroud 232.

[0026] Based on the flow of production fluid 244 through and into inverted shroud 232, the gas phase 244-1 of production fluid 244 can be separated from or escape from production fluid 244. For example, based on the density and / or specific gravity difference between the liquid and gas components of production fluid 244, gas phase 244-1 may tend to escape and / or continue to flow upward through inverted shroud 232, while liquid phase 244-2 flows downward into inverted shroud 232. Liquid phase 244-2 can flow back to production line 223 at perforated section 233 located within inverted shroud 232 and eventually reach and pass through ESP assembly 250 as described herein. Thus, by utilizing the natural properties of the liquid and gas components of production fluid 244, gas separator 230 can passively facilitate the separation of gas phase 244-1 and liquid phase 244-2 based on gravity.

[0027] In some cases, gas phase 244-1 can be hydrocarbon gas, carbon dioxide gas, or other gases that can escape from the hydrocarbon production fluid stream. According to a specific example, gas phase 244-1 can be methane gas escaping from an aqueous fluid or water stream. As mentioned above, the production area or reservoir can be a methane hydrate formation, and the methane gas can be trapped in solid form by combining with the solid form of the aqueous fluid (ice). By pumping out and removing some of the aqueous fluid from the methane hydrate formation, the methane gas can be released from the solid state to a gaseous state. The now gaseous methane gas can flow upwards with and / or through the aqueous fluid, and thus can flow upwards along production line 223 to gas separator 230 as described.

[0028] In this way, methane gas (or other gases) can be produced and separated from the methane hydrate formation and produced at the surface. For example, gas phase 244-1 can flow through annulus 228, outside production tubing 223, where it can remain separated and isolated from liquid phase 244-2. For example, production tubing 223 may not include any additional packers in the uphole direction of gas separator 230, allowing gas phase 244-1 to flow through the annulus to the surface. For example, production system 211 may not include any switching devices to facilitate the flow of gas phase 244-1 from annulus 228 to production tubing at any point, which might be present in some conventional methods. Instead, gas phase 244-1 can flow through annulus 228 and be produced at the surface via annulus 228. Gas phase 244-1 can then be captured at the surface from annulus 228.

[0029] In some cases, such as for production zones comprising methane hydrate formations as described above, substantially all of the gas phase 244-1 can be separated from the liquid phase 244-2 at gas separator 230. For example, the natural rise of the gas and the natural fall of the liquid due to gravity at inverted shield 232 can be operated to remove substantially all of the gas phase 244-1. For example, production fluid 244 can be made to flow at a given flow rate such that all of the gas phase 244-1 is allowed to escape at inverted shield 232, while the liquid phase 244-2 may consist substantially only of liquid, with no gas mixture. This may be particularly true for methane gas released from methane hydrate formations. For example, methane may be insoluble in water—or methane and water may be immiscible—making it unlikely that the methane gas will dissolve in the aqueous fluid (e.g., at the temperature and / or pressure of the reservoir, wellbore, production system, etc., where the methane gas flows). Conversely, as methane gas is released from its solid structure along with water, it can flow upwards with or through the aqueous fluid pumped through production line 223. Therefore, the (methane) gas phase 244-1 and liquid phase 244-2 can be readily separated at the inverted shield 232, such that substantially all of the gas phase 244-1 flows upwards through the annulus 228, rather than flowing into the inverted shield 232 along with the liquid phase 244-2. Thus, the gas phase 244-1 can be produced and collected at ground level through the annulus 228.

[0030] Back Figure 2-1 In some cases, the production system 211 does not include any other gas separators or gas separation components besides the gas separator 230 just described. For example, the production system 211 does not include an additional gas separator located above the ESP assembly. In this way, the production system 211 can rely entirely on the natural and / or passive gas separation function of the gas separator 230 and may not employ additional gas separators. Furthermore, the production system 211 may not include any active or mechanical gas separators that can perform gas separation functions based on the execution of mechanical movement, action, or function. In this way, the production system 211 can maintain a high level of reliability by implementing fewer gas separators and, additionally, by utilizing passive gas separators without moving parts or active gas separation mechanisms, thus limiting the possibility of the production system 211 failing or malfunctioning.

[0031] As described above, the production system 211 includes an ESP component 250. Figure 2-3An enlarged view of the ESP assembly 250 of a production system 211 according to at least one embodiment of the present disclosure is shown. The ESP assembly 250 can be configured to pump production fluid 244 upward through a production line. For example, based on the pressure or head generated by the ESP assembly 250, and in some cases in combination with the natural pressure of the reservoir, the production fluid 244 can be made to flow to the surface through a production line 223.

[0032] In some implementations, the ESP assembly 250 includes a pump 251 and a motor 252. The motor 252 may be an electric motor capable of driving the operation of the pump 251. For example, the motor 252 may be connected to a power transmission line 259 that can supply power to the motor 252 from the ground of the wellbore 202. As described herein, the power transmission line 259 may be located outside the production tubing 223, i.e., within the annulus 228. The motor 252 may be a submersible electric motor, which may be configured to operate when immersed in or exposed to a flow of production fluid 244. The motor 252 may be connected via a shaft to the pump 251 for driving each stage of the pump 251.

[0033] In some embodiments, pump 251 receives or draws in a flow of production fluid 244 through pump inlet 253. For example, production fluid 244 may flow between ESP assembly 250 and production line 223 to pump inlet 253, where it may flow into pump 251. Pump inlet 253 may be a perforated component that allows production fluid 244 to flow through it.

[0034] As described in detail below, pump 251 can be a high-speed helical axial flow pump, which may include various pump stages. Therefore, Figure 2-3 Pump 251, as indicated, may include multiple stages and span a considerable axial length in some cases. Pump 251 can pump production fluid 244, which may exit pump 251 at discharge head 254, and valve assembly 255 can direct and / or control the flow of production fluid 244 into production tubing 223. ESP assembly 250 may be sealed at its upper end against production tubing 223 by sealing assembly 256. In some cases, sealing assembly 256 may include a thermal expansion joint.

[0035] like Figure 2-3As shown, ESP assembly 250 can be fully positioned within production tubing 223. For example, ESP assembly 250 can be delivered and / or retrieved within production tubing 223. Specifically, ESP assembly 250 can be delivered via a delivery line such as a wireline (WL), coiled tubing (CT), or other delivery line. In some cases, the diameter of the production tubing can be much smaller than the diameter of the production casing or wellbore. For example, the diameter of production tubing 223 can be 4.5 inches or less. In some cases, production tubing 223 is 6 inches or less. Therefore, a production tubing-deployable (e.g., rig-free) ESP assembly (e.g., ESP assembly 250) can be much smaller and different from an ESP assembly configured as part of the production tubing (e.g., connected to the production tubing) and therefore only needs to be able to fit within a larger production casing.

[0036] In this way, the ESP assembly 250 can be a drillless ESP assembly 250, and can be transported with and / or retrieved from the wellbore 202 without relying on downhole drilling rigs, drilling rigs, traveling blocks, derricks, hangars, or other complex and / or heavy drilling rig components typically used for transporting tubular components (e.g., drill pipe, tubing, casing, etc.). Instead, the ESP assembly 250 can be transported via a delivery system for WL, CT, etc., such as those conventionally used for wellbore intervention, maintenance, monitoring, or production enhancement operations. These delivery systems are typically much smaller, faster, simpler, and more cost-effective. In this way, the production tubing 223 can be permanently or semi-permanently installed in the wellbore 202, and the ESP assembly 250 can be transported and positioned within the production tubing 223 at a later time.

[0037] To facilitate the implementation of 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 robust and stable connection to the ESP assembly 250. For example, the ESP assembly 250 may be equipped with a shuttle component at its bottom end, which may mate with a corresponding component of the production tubing 223 and facilitate alignment, positioning, and securing of the ESP assembly 250 relative to the production tubing 223.

[0038] In some cases, the motor connector assembly 257 includes a socket 258, such as a wet socket. The socket 258 can be connected to the ESP assembly 250 to provide an electrical connection to the ESP assembly 250 (e.g., to the motor 252). For example, as described above, the power transmission line 259 can be positioned outside the production tubing 223 and can extend from the surface of the wellbore 202. In some cases, the power transmission line 259 is mounted on the production tubing 223 and is delivered and positioned within the wellbore 202 along with the production tubing. The power transmission line 259 can be connected to a socket such that the power transmission line 259 is electrically connected to the interior of the production tubing 223.

[0039] When deploying the ESP assembly 250, it can be conveyed down the production tubing 223 via a delivery line until it reaches the motor connector assembly 257. The ESP assembly 250 can be lowered, inserted, or otherwise connected to the motor connector assembly 257, thereby electrically connecting the ESP assembly 250 to the power transmission line 259. For example, the ESP assembly 250 may include pins or plugs that can mate with a socket 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., pump 251) can be powered and / or controlled from the ground via the power transmission line 259, which can be positioned outside the production tubing 223.

[0040] The rig-free and transportable nature of ESP component 250 contrasts with conventional ESP systems. For example, some ESP systems are typically implemented as components connected to or part of the production tubing. Specifically, in some conventional approaches, ESP components can be assembled and / or connected to the production tubing and transported into the wellbore along with it. Therefore, such ESP components may be more permanently fixed in the wellbore, unlike ESP component 250, which can be recovered from within the production tubing 223. For example, in some conventional solutions, removing the ESP component, such as for repair, maintenance, or replacement, requires retrieval of the entire completion string from the wellbore. Therefore, removing the ESP component requires a workover rig, which is expensive, slow, complex, costly, and dangerous. Furthermore, removing the completion component leads to wellbore shutdown and, in some cases, may not even be feasible for wells under kill unless kill fluid is used, which can have many harmful effects, such as causing formation damage or wellbore collapse, especially in highly depleted reservoirs.

[0041] In contrast, the ESP assembly 250 can be more easily removed from the wellbore from inside the production tubing 223 and offers significant advantages over conventional ESP assemblies. For example, the ESP assembly 250 can be delivered within the production tubing 223, eliminating the need for a workover rig. Instead, the ESP assembly 250 can be delivered via a WL or CT delivery system, which is faster, simpler, more cost-effective, and safer than heavy-duty drilling rigs. This provides flexibility for more efficient maintenance and / or replacement of the ESP assembly 250 by reducing downtime, minimizing production losses, avoiding costly rig relocation operations, and improving safety. Furthermore, since the completion components are not removed, the ESP assembly can be recovered from the pressurized wellbore while avoiding damage to the formation, wellbore, etc.

[0042] Now go to Figure 3-1 The figure illustrates a helical axial flow pump 351 according to at least one embodiment of the present disclosure. The helical axial flow pump 351 may be... Figure 2-3 Example of pump 251. The helical axial flow pump 351 can be implemented as multiple pump stages; however, Figure 3-1 A single stage of a helical axial flow pump 351 is shown. Each pump stage includes an impeller 361 and guide vanes 362. The impeller 361 can operate to accelerate the fluid and / or transfer kinetic energy to the fluid, after which the fluid can flow to the guide vanes 362. The guide vanes 362 can be stationary components and can interact with the moving fluid to convert the fluid's movement or kinetic energy into potential energy in the form of increased fluid pressure or head. In many cases, the helical axial flow pump 351 can consist of multiple pump stages, each operating to increase or build up additional pressure (e.g., head) sufficient to lift the fluid to the ground.

[0043] The helical axial flow pump 351 can be helical axial flow type based on an impeller 361 having one or more helical blades or vanes 363. For example, the vanes 363 can be positioned helically around the impeller 361, such that the vanes 363 can form a spiral or helix around the impeller 361 at least partially. This can be contrasted with, for example, other types of pump stages that may utilize impellers and blades with a more vertical or axial orientation. For example, Figure 3-2 An example of an ESP pump 346 without helical axial flow blades is shown. Instead, as shown, the ESP pump 346 has blades 347 of an impeller 348 that are more upright, vertical, or axial.

[0044] Back Figure 3-1As the impeller 361 rotates, the blades 363 generate a combination of axial and rotational motion on the fluid flowing through the helical axial flow pump 351. For example, the rotating helical impeller 361 imparts both axial and tangential velocities to the fluid, generating a swirling motion that transfers energy to the fluid, which is guided in a generally axial direction. This can be contrasted with other pumps, such as centrifugal pumps or multiphase pumps, that do not have helical axial flow blades, which may rely on radial acceleration and / or may accelerate the fluid with outward, radial, or centrifugal components.

[0045] In this way, impeller 361 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 uniform flow. In conventional pump stages, sudden energy transfer to the fluid tends to separate and / or accumulate free gas along the impeller blades, which can lead to airlock in the pump stage. In contrast, impeller 361 allows for gradual energy transfer, ensuring uniform acceleration of both gas and liquid and minimizing the possibility of gas separation and airlock in the pump stage.

[0046] In this way, the helical axial flow pump 351 can significantly reduce the risk of gas lock-up, allowing stable and efficient operation in environments with high gas content. For example, conventional pump stages may tend to experience gas lock-up at gas volume fraction (GVF) levels of 30%–40%, while the helical axial flow pump 351 can operate at up to 75% GVF or higher without gas lock-up. For instance, in some cases, the helical axial flow pump 351 can operate effectively at GVF levels of up to 85% or 90%. In some cases, the helical axial flow pump 351 can even operate at 100% GVF without gas lock-up. Therefore, the helical axial flow pump 351 can be effectively operated to pump liquid-gas multiphase fluid flows with elevated GVF levels, providing a significant advantage over other and / or conventional types of pump stages.

[0047] Furthermore, the helical axial flow pump 351 offers adaptability advantages. For example, as wells mature and gas content increases, conventional ESP pumps typically require frequent adjustments, replacements, or costly gas treatment upgrades. However, the helical axial flow pump 351 can naturally adapt to or compensate for changing flow conditions, reducing intervention needs and extending well productivity. By ensuring continuous operation in gas-rich environments, the helical axial flow pump 351 can maintain higher productivity and improve overall oilfield economics.

[0048] In this way, the ESP assembly described herein can benefit from implementing a helical axial flow pump 351 instead of other conventional types of pumps. For example, as mentioned above, the ESP assembly can be equipped with a gas separator that can operate to remove gases from the production fluid stream. In some cases, despite gas separation efforts, gases may still remain in the production fluid. For example, in some cases, not all gases are removed from the production fluid. In other cases, some types of gases are removed while others remain. For example, in the case of methane hydrate formations, methane gas can be substantially or completely removed from the production fluid, while other gases may still be present in the production fluid flowing to and through the pump. In this way, implementing a helical axial flow pump 351 as described may be advantageous.

[0049] Another advantage is that the helical axial flow pump 351 can have a smaller form factor and / or a smaller diameter than other types of pump stages. For example, since the operating mode of the helical axial flow pump 351 accelerates the fluid in the axial direction, it may not be necessary to utilize the large diameter of the helical axial flow pump to generate pressure. For example, other pumps that may centrifugally accelerate the fluid in the radial direction may rely on a larger radius to effectively generate pressure in the fluid. Therefore, implementing such a pump stage with a larger diameter may be advantageous. In contrast, the operating principle of the helical axial flow pump 351 can be independent of the radial dimension, thus facilitating the achievement of a smaller overall form factor.

[0050] This smaller form factor can be advantageous for implementing the helical axial flow pump 351 in a drillless ESP assembly, in which the ESP assembly is implemented within the production tubing. For example, the radial space within the production tubing may be limited compared to an ESP assembly implemented as part of the production tubing, while the ESP assembly can gain more space within a larger production casing. Therefore, the helical axial flow pump 351 can facilitate the drillless and / or transportable nature of the ESP assembly as described herein.

[0051] While helical axial flow pumps offer a smaller form factor and gas handling capacity, in some cases they may produce less head than other conventional pump types. For example, in some situations (such as standard and / or non-high-speed), a helical axial flow pump can produce up to about 15 feet of head per stage, thus requiring a corresponding number of stages to generate sufficient head for artificial lift purposes. Helical axial flow pumps, as well as other pump types, can operate at frequencies from about 50 Hz to about 60 Hz or from about 3000 rpm to about 3600 rpm. In some cases, these pumps can operate at frequencies below 70 Hz.

[0052] In some cases, the helical axial flow pump 351 can be a high-speed helical axial flow pump. Operating the helical axial flow pump 351 at higher speeds can facilitate the generation of significantly greater pressure and / or head. For example, in some cases, the helical axial flow pump 351 can operate at frequencies up to 70 Hz or higher (4200 rpm). In some cases, the helical axial flow pump 351 operates at frequencies up to 100 Hz or higher (6000 rpm). In some cases, the helical axial flow pump 351 operates at frequencies up to 120 Hz (7200 rpm). The helical axial flow pump 351 can be configured to operate at these higher speeds based on the associated motor of the corresponding ESP component. For example, the motors used to drive each stage of the helical axial flow pump 351 can be configured to operate with sufficient power and speed to achieve these higher frequencies of the helical axial flow pump 351.

[0053] Based on the high-speed implementation of the helical axial flow pump, it can generate a head exceeding 15 feet. For example, a high-speed helical axial flow pump can generate a head of 40 feet or more. In another example, a high-speed helical axial flow pump generates a head of up to 100 feet. Increasing speed in this way can promote the generation of more head based on the principle that the head, or pressure, is proportional to the square of the shaft rotation speed. Therefore, by using the helical axial flow pump 351 as a high-speed helical axial flow pump operating at twice the speed of a conventional (e.g., helical axial flow) implementation, four times the pressure can be generated. Three times the shaft rotation speed can generate eight times the pressure, and so on.

[0054] In this way, the helical axial flow pump 351 can provide the benefits of gas handling and space saving, and can also provide sufficient head to lift the production fluid to the ground. For example, conventional ESPs can use up to 150, 200, or even 500 pump stages to generate sufficient lift. However, the helical axial flow pump 351 can be implemented with as few as 50 pump stages or less. Furthermore, the number of pump stages of the helical axial flow pump 351 allows for an overall axial length of 35 feet or less. In contrast, other conventional ESP assemblies can have pumps with axial lengths exceeding 50, 100, or 150 feet. This reduced length facilitates the implementation of the ESP assembly described herein as a rig-free and / or deliverable ESP assembly, among other benefits.

[0055] Furthermore, in addition to the helical axial flow pump 351, the helical axial flow pump 351 can be implemented without using any other type of pump and / or pump stage (e.g., via multiple pump stages). For example, in some cases, the helical axial flow pump is implemented in an ESP assembly as a booster stage of the ESP assembly utilizing its gas handling capacity, and one or more other (e.g., conventional) types of pumps can be implemented downstream of the helical axial flow booster stage (e.g., in the uphole direction) to generate pressure and / or lift. As described herein, the helical axial flow pump 351 can operate as a high-speed helical axial flow pump to generate sufficient lift so that no other stage or pump is required to supplement the head generated by the helical axial flow pump 351.

[0056] Figure 4 A flowchart illustrating a method 400 or a series of steps for surface gas production in a wellbore described herein, according to at least one embodiment of the present disclosure. Although Figure 4 The actions according to one implementation are shown, but alternative implementations may add, omit, reorder, or modify them. Figure 4 Any action by [them].

[0057] In some implementations, method 400 includes action 410: driving a high-speed helical axial flow pump located inside the production tubing using a motor located inside the production tubing, wherein the high-speed helical axial flow pump and the motor are part of a drillless electric submersible pump (ESP) assembly that can be delivered within the production tubing.

[0058] In some implementations, method 400 includes action 420: pumping the flow of production fluid from an underground reservoir based on generating a head of production fluid using a high-speed helical axial flow pump to lift the production fluid to the ground.

[0059] In some implementations, method 400 includes action 430: flowing production fluid through a production line.

[0060] In some implementations, method 400 includes action 440: separating the gas phase and liquid phase from the production fluid using a gravity-assisted gas separator located below the helical axial flow pump well.

[0061] In some implementations, method 400 includes action 450: producing a gas phase at the surface based on allowing the gas phase to flow through the annulus between the wellbore and the production tubing.

[0062] In some implementations, method 400 also includes operating the high-speed helical axial flow pump at a frequency of 70 Hz or higher and generating a head of more than 15 feet per pump stage in the liquid phase.

[0063] In some implementations, operating a high-speed helical axial flow pump involves operating no more than 50 pump stages.

[0064] Figure 5 A method 500 or series of actions for producing methane gas from a wellbore described herein is shown according to at least one embodiment of this disclosure. Although Figure 5 The actions according to one implementation are shown, but alternative implementations may add, omit, reorder, or modify them. Figure 5 Any action by [them].

[0065] In some implementations, method 500 includes action 510: positioning the ESP assembly within the production tubing by conveying the ESP assembly through the production tubing located in the wellbore using a delivery line.

[0066] In some implementations, method 500 includes action 520: forming an electrical connection with the ESP assembly at a receptacle in the production tubing to connect the ESP assembly to a power transmission line located outside the production tubing and extending from the surface of the wellbore via the production tubing.

[0067] In some implementations, method 500 includes action 530: transmitting power to the downhole motor of the ESP assembly via a power transmission line to drive the high-speed helical axial flow pump of the ESP assembly to operate at at least 70 Hz.

[0068] In some embodiments, method 500 includes action 540: pumping a flow of aqueous production fluid from a methane hydrate formation using a high-speed helical axial flow pump to release methane gas from the solid state, wherein pumping the aqueous production fluid includes generating a head of at least 15 feet of aqueous production fluid per pump stage of the high-speed helical axial flow pump. In some embodiments, pumping the flow of aqueous production fluid includes utilizing no more than 50 pump stages of the high-speed helical axial flow pump.

[0069] In some implementations, method 500 includes action 550: separating methane gas from the aqueous phase of the water-bearing production fluid at a gravity-assisted gas separator located downhole of the ESP component well.

[0070] In some implementations, method 500 includes action 560: producing methane gas at the surface based on flowing methane gas through the annulus between the wellbore and the production tubing.

[0071] Industrial applicability The following description from sections A1–C2 includes various embodiments, which may be combined in any arrangement where feasible. For example, embodiments of section A1 may be combined with any or all of the embodiments in the following paragraphs. Embodiments describing method action may be combined with, for example, embodiments describing systems and / or apparatuses. Any arrangement of the following paragraphs is disclosed herein for the purpose of providing “clearly deducible support” for any modifications to the claims based on the following paragraphs. Furthermore, the following paragraphs provide support such that any combination of the following paragraphs does not produce an “intermediate generalization.”

[0072] A1. A wellbore production system, comprising: A production tubing located inside the wellbore; An electric submersible pump (ESP) assembly, located within the production tubing, is a rig-free ESP assembly, which can be transported within the production tubing via a conveyor line. The ESP assembly includes: High-speed helical axial flow pump; and Motor used to drive the spiral axial flow pump; A power transmission line extending from the surface of the wellbore outside the production tubing and connected to the motor via the production tubing; and A gravity-assisted gas separator is connected to the production oil line and to the intake port of the ESP assembly.

[0073] A2. The wellbore production system according to A1, wherein the motor and the high-speed helical axial flow pump are configured to operate at a frequency of 70 Hz or higher.

[0074] A3. The wellbore production system according to A1 or A2, wherein the motor and the high-speed helical axial flow pump are configured to operate at a frequency of 100 Hz or higher.

[0075] A4. The wellbore production system according to any one of A1 to A3, wherein the motor and the high-speed helical axial flow pump are configured to operate at up to 120 Hz.

[0076] A5. The wellbore production system according to any one of A1 to A4, wherein the high-speed helical axial flow pump comprises fewer than 50 pump stages.

[0077] A6. A wellbore production system according to any one of A1 to A5, wherein each stage of the high-speed helical axial flow pump is configured to generate a pressure head of more than 15 feet.

[0078] A7. The wellbore production system according to any one of A1 to A6, wherein the axial length of the high-speed spiral axial flow pump is 35 feet or less.

[0079] A8. The wellbore production system according to any one of A1 to A7, wherein the ESP component does not include pumps other than the high-speed helical axial flow pump.

[0080] A9. A wellbore production system according to any one of A1 to A8, wherein the delivery line is a cable (WL) or coiled tubing (CT).

[0081] A10. A wellbore production system according to any one of A1 to A9, wherein the production tubing is positioned in the wellbore to enter a methane hydrate formation, and the gravity-assisted gas separator separates methane gas from water.

[0082] A11. The wellbore production system according to A10, wherein the separated methane gas is configured to flow to the surface in the annulus between the wellbore and the production tubing.

[0083] A12. The wellbore production system according to any one of A1 to A11, wherein the gravity-assisted gas separator is a passive gas separator and does not include an active gas separation mechanism.

[0084] A13. The wellbore production system according to any one of A1 to A12, wherein the system does not include a gas separator other than the gravity-assisted gas separator.

[0085] A14. The wellbore production system according to any one of A1 to A13, wherein the production tubing does not include a packer located on the ESP assembly well.

[0086] A15. A wellbore production system according to any one of A1 to A14, wherein the high-speed helical axial flow pump is configured to operate at up to 75% gas volume fraction (GVF) without gas lock-up.

[0087] A16. A wellbore production system according to any one of A1 to A15, wherein the production tubing has a diameter of 6 inches or less.

[0088] B1. A method for producing gas at the surface of a wellbore, comprising: A high-speed spiral axial flow pump, also located inside a production tubing, is driven by a motor positioned inside the production tubing. The high-speed spiral axial flow pump and the motor are part of a drillless electric submersible pump (ESP) assembly capable of delivering within the production tubing. The flow of the production fluid is pumped from the underground reservoir by using the high-speed helical axial flow pump to generate a pressure head for the production fluid to lift the production fluid to the ground. The production fluid is allowed to flow through the production oil pipe; The gas and liquid phases of the production fluid are separated using a gravity-assisted gas separator located below the high-speed helical axial flow pump well; and The gas phase is produced at the surface by allowing the gas phase to flow through the annulus between the wellbore and the production tubing.

[0089] B2. The method according to B1 further includes operating the high-speed helical axial flow pump at a frequency of 70 Hz or higher and generating a head of more than 15 feet per pump stage in the liquid phase.

[0090] B3. The method according to B1 or B2, wherein operating the high-speed helical axial flow pump includes operating no more than 50 pump stages.

[0091] C1. A method for producing methane gas from a wellbore, comprising: The ESP assembly is positioned within the production tubing by conveying it through the production tubing located in the wellbore using a delivery line. An electrical connection is formed between the ESP assembly and the receptacle of the production tubing to connect the ESP assembly to a power transmission line located outside the production tubing and extending from the ground of the wellbore via the production tubing. Power is transmitted to the downhole motor of the ESP assembly via the power transmission line to drive the high-speed helical axial flow pump of the ESP assembly to operate at at least 70 Hz; The high-speed helical axial flow pump is used to pump the flow of water-bearing production fluid from the methane hydrate formation to release methane gas from the solid state, wherein pumping the water-bearing production fluid includes generating a head of at least 15 feet of the water-bearing production fluid in each pump stage of the high-speed helical axial flow pump. At a gravity-assisted gas separator located below the ESP assembly well, methane gas is separated from the aqueous phase of the water-containing production fluid; and The methane gas is produced at the surface by allowing the methane gas to flow through the annulus between the wellbore and the production tubing.

[0092] C2. The method according to C1, wherein the flow of pumping the aqueous production fluid comprises no more than 50 pump stages using the high-speed helical axial flow pump.

[0093] The implementation scheme of the production system described herein is primarily based on wellbore drilling operations; however, the production system described herein can be used for applications beyond wellbore drilling. In other embodiments, the production system according to this disclosure can be used outside of wellbores or other downhole environments used for exploring or producing natural resources. For example, the production system of this disclosure can be used in boreholes used for laying utility pipelines. Therefore, the terms "wellbore," "borehole," etc., should not be construed as limiting the tools, systems, components, or methods of this disclosure to any particular industry, field, or environment.

[0094] This document describes one or more specific embodiments of the present disclosure. These described embodiments are examples of the currently disclosed technology. Additionally, in order to provide a brief description of these embodiments, not all features of an actual embodiment may be described in this specification. It should be understood that when developing any such actual implementation in any engineering or design project, numerous implementation-specific decisions will be made to achieve the developer's specific goals, such as compliance with system-related and business-related constraints, which may vary from embodiment to embodiment. Furthermore, it should be understood that such development work may be complex and time-consuming, but will still be a routine task in design, fabrication, and manufacturing for those skilled in the art who benefit from this disclosure.

[0095] Additionally, it should be understood that references to “one embodiment” or “implementation” in this disclosure are not intended to be construed as excluding the existence of additional embodiments that also incorporate the described features. For example, any element described with respect to an embodiment herein may be combined with any element of any other embodiment described herein. As will be appreciated by one of ordinary skill in the art as covered by embodiments of this disclosure, the figures, percentages, ratios, or other values ​​stated herein are intended to include, and also include, other values ​​that are “about” or “approximately” as stated. Therefore, the values ​​should be interpreted broadly enough to cover values ​​that are at least close enough to the value to perform the desired function or achieve the desired result. The values ​​include at least the variations expected in a suitable manufacturing or production process and may include values ​​within 5%, 1%, 0.1%, or 0.01% of the stated value.

[0096] In view of this disclosure, those skilled in the art will recognize that equivalent constructions do not depart from the spirit and scope of this disclosure, and that various changes, substitutions, and modifications may be made to the embodiments disclosed herein without departing from the spirit and scope of this disclosure. Equivalent constructions (including the functional “apparatus plus function” clause) are intended to cover structures described herein as performing said functions, including structural equivalents operating in the same manner and equivalent structures providing the same function. The applicant’s explicit intent is not to invoke apparatus plus function or other functional requirements in any claim, except for those claims where the phrase “apparatus for…” appears with the associated function. Every addition, deletion, and modification to the embodiments falling within the meaning and scope of the claims will be included in the claims.

[0097] As used herein, the terms “approximately,” “about,” and “substantially” mean a quantity close to the stated amount, which is within standard manufacturing or process tolerances or still performs the desired function or achieves the desired result. For example, the terms “approximately,” “about,” and “substantially” can refer to a quantity less than 5%, less than 1%, less than 0.1%, and less than 0.01% of the stated amount. Furthermore, it should be understood that any direction or frame of reference in the foregoing description is only relative direction or movement. For example, any reference to “up” and “down,” or “above” or “below”, describes only the relative position or movement of the relevant element. Additionally, as used herein, the term “and / or” includes any and all combinations of one or more of the associated listed items.

[0098] This disclosure may be embodied in other specific forms without departing from the spirit or characteristics thereof. The described embodiments should be considered illustrative rather than restrictive. Therefore, the scope of this disclosure is indicated by the appended claims rather than by the foregoing description. Variations in the meaning and scope of equivalent forms of the claims are to be included within the scope of the claims.

Claims

1. A wellbore production system, comprising: A production tubing located inside the wellbore; An electric submersible pump (ESP) assembly, located within the production tubing, is a rig-free ESP assembly capable of being transported within the production tubing via a conveyor line, and includes: High-speed helical axial flow pump; and Motor used to drive the spiral axial flow pump; A power transmission line extending from the surface of the wellbore outside the production tubing and connected to the motor via the production tubing; and A gravity-assisted gas separator is connected to the production oil line and to the intake port of the ESP assembly.

2. The wellbore production system of claim 1, wherein the motor and the high-speed helical axial flow pump are configured to operate at a frequency of 70 Hz or higher.

3. The wellbore production system of claim 1, wherein the motor and the high-speed helical axial flow pump are configured to operate at a frequency of 100 Hz or higher.

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

5. The wellbore production system according to claim 1, wherein the high-speed helical axial flow pump comprises fewer than 50 pump stages.

6. The wellbore production system of claim 1, wherein each stage of the high-speed helical axial flow pump is configured to generate a pressure head of more than 15 feet.

7. The wellbore production system of claim 1, wherein the axial length of the high-speed helical axial flow pump is 35 feet or less.

8. The wellbore production system of claim 1, wherein the ESP component does not include pumps other than the high-speed helical axial flow pump.

9. The wellbore production system according to claim 1, wherein the delivery line is a cable (WL) or coiled tubing (CT).

10. The wellbore production system of claim 1, wherein the production tubing is positioned in the wellbore to enter 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 ground in the annulus between the wellbore and the production tubing.

12. The wellbore production system according to claim 1, wherein 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 other than the gravity-assisted gas separator.

14. The wellbore production system of claim 1, wherein the production tubing does not include a packer located on the ESP assembly well.

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

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

17. A method for producing gas at the surface of a wellbore, comprising: A high-speed spiral axial flow pump, also located inside a production tubing, is driven by a motor positioned inside the production tubing. The high-speed spiral axial flow pump and the motor are part of a drillless electric submersible pump (ESP) assembly capable of delivering within the production tubing. The flow of the production fluid is pumped from the underground reservoir by using the high-speed helical axial flow pump to generate a pressure head for the production fluid to lift the production fluid to the ground. The production fluid is allowed to flow through the production oil pipe; A gravity-assisted gas separator located below the high-speed helical axial flow pump well separates the gas and liquid phases from the production fluid; as well as The gas phase is produced at the surface by allowing the gas phase to flow through the annulus between the wellbore and the production tubing.

18. The method of claim 17, further comprising operating the high-speed helical axial flow pump at a frequency of 70 Hz or higher, and generating a head of more than 15 feet per pump stage in the liquid phase.

19. The method of claim 17, wherein operating the high-speed helical axial flow pump comprises operating no more than 50 pump stages.

20. A method for producing methane gas from a wellbore, comprising: The ESP assembly is positioned within the production tubing by delivering the ESP assembly through the production tubing located within the wellbore; An electrical connection is formed between the ESP assembly and the receptacle of the production tubing to connect the ESP assembly to a power transmission line located outside the production tubing and extending from the ground of the wellbore via the production tubing. Power is transmitted to the downhole motor of the ESP assembly via the power transmission line to drive the high-speed helical axial flow pump of the ESP assembly to operate at at least 70 Hz; The high-speed helical axial flow pump is used to pump the flow of water-bearing production fluid from the methane hydrate formation to release methane gas from the solid state, wherein pumping the water-bearing production fluid includes generating a head of at least 15 feet of the water-bearing production fluid in each pump stage of the high-speed helical axial flow pump. At the gravity-assisted gas separator located downhole of the ESP assembly, methane gas is separated from the aqueous phase of the water-containing production fluid; as well as The methane gas is produced at the surface by allowing the methane gas to flow through the annulus between the wellbore and the production tubing.

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