Sand Separator System for Artificial Lift Pumping System

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a non-provisional patent application claiming the benefit of, and priority to, U.S. Provisional Patent Application No. 63/718,081 , filed Nov. 8, 2024, which is incorporated by reference herein in its entirety.

FIELD OF THE DISCLOSURE

The present disclosure generally relates to a sand separator system for an artificial lift pumping system, and more specifically to a sand separator system that includes a spigot that enhances sand separation to reduce the amount of sand particles mixed with hydrocarbon fluid produced to the surface of a wellbore.

BACKGROUND

Wellbores are drilled into a subterranean formation to produce hydrocarbon fluids from a producing portion of the subterranean formation. Artificial lift pumping systems are commonly used to carry hydrocarbon production fluids (e.g., fluids containing liquid and/or gas hydrocarbons) from the subterranean formation, through the wellbore, and to a wellhead located above the surface of the earth. Artificial lift pumping systems include reciprocating rod pumping systems, electronic submersible pump systems (ESP systems), and long-stroke pumping system. These artificial lift pumping systems operate to generate sufficient pressure to pump the hydrocarbon production fluid from the wellbore to the wellhead.

Artificial lift pumping systems commonly utilize a wellbore casing cemented to the wall of the wellbore, which is perforated at or near a targeted subterranean formation to provide a fluid flow path from the subterranean formation, through the perforations, and to the wellhead. A sand separator is often deployed downhole from the perforated portion of the wellbore casing. Conventional sand separators are generally able to remove between about 25-51% of the sand particles from the hydrocarbon production fluid. This means that 49-75% of the sand is not removed from the hydrocarbon fluid, and the non-removed sand can flow into the pump with the hydrocarbon fluid, reducing pump useful life. Removing the remaining sand particles necessitates post-production procedures that increase the costs and time associated with the hydrocarbon production. Accordingly, the hydrocarbon production industry continues to demand technological advances in sand separation technology.

SUMMARY

Disclosed is a spigot for a sand separator system, including: a head including a crown and a cylindrical skirt extending therefrom; a stem extending from the head; and a body portion coupled to a distal end of the stem and including a plurality of fluid flow passages extending therethrough. In aspects, the spigot can be positioned between an outlet of a helical auger component and a purge valve of a sand separator system. In aspects, there exists a gap between the cylindrical skirt and the separator casing.

Also disclosed is a sand separator system, including: a perforated inlet including a plurality of perforations; a separator casing coupled to the perforated inlet; a pump inlet tubing disposed through a central bore of the perforated inlet and forming an annulus with the separator casing; a helical auger component disposed at a distal end of the pump inlet tubing and including a plurality of external helical pathways; and a spigot disposed downhole from the helical auger component, wherein the spigot includes a head including a crown and a cylindrical skirt extending therefrom, a stem extending from the head, and a body portion coupled to a distal end of the stem and including a plurality of fluid flow passages extending therethrough.

Further disclosed is an artificial lift pumping system, including: a surface unit; a wellhead disposed on a top of a wellbore casing cemented within a wellbore; a production tubing string extending through the wellbore casing; i) a polished rod coupled to the surface unit and extending through the production tubing string to impart reciprocating motion through a rod string disposed in the wellbore to a rod pump disposed at a bottom of or within the production tubing string or ii) an electric submersible pump positioned in the wellbore casing and coupled to the production tubing string; and a sand separator system positioned below the rod pump or the electric submersible pump, the sand separator system including: a perforated inlet; a separator casing coupled to the perforated inlet; a pump inlet tubing disposed through a central bore of the perforated inlet and forming an annulus with the separator casing; a helical auger component disposed at a distal end of the pump inlet tubing; and a spigot disposed downhole from the helical auger component, wherein the spigot includes a head includes a crown and a cylindrical skirt extending therefrom, a stem extending from the head, and a body portion coupled to a distal end of the stem and including a plurality of fluid flow passages extending therethrough.

Further disclosed is a method of producing hydrocarbon fluids from a wellbore, including: providing a sand separator system including: a perforated inlet; a separator casing coupled to the perforated inlet; a pump inlet tubing disposed through a central bore of the perforated inlet and forming an annulus with the separator casing; a helical auger component disposed at a distal end of the pump inlet tubing; and a spigot disposed downhole from the helical auger component, wherein the spigot includes a head including a crown and a cylindrical skirt extending therefrom, a stem extending from the head, and a body portion coupled to a distal end of the stem and including a plurality of fluid flow passages extending therethrough; drawing hydrocarbon fluid into the perforated inlet through a plurality of perforations that form a fluid pathway between a subterranean formation and the annulus; flowing the hydrocarbon fluid through the annulus and through a plurality of helical pathways formed in the helical auger component to impart a cyclonic motion to the hydrocarbon fluid; drawing the hydrocarbon fluid through a central bore of the helical auger component that forms a fluid flow path with the pump inlet tubing to separate the hydrocarbon fluid from a plurality of sand particles disposed therein; and passing the plurality of sand particles separated from the hydrocarbon fluid around and/or through the spigot, wherein at least 55%, at least 60%, at least 70%, at least 80% at least 90%, at least 95%, at least 96%, at least 87%, at least 98%, at least 99%, or even 100% of the plurality of sand particles are removed from the hydrocarbon fluid that enters the pump inlet tubing and flows to a wellhead.

Also disclosed is a method that includes producing hydrocarbon fluids from a subterranean formation with a sand separator system that is placed in a wellbore at a depth that is in fluid communication with a producing zone of the subterranean formation, wherein the sand separator system comprises: a perforated inlet; a separator casing coupled to the perforated inlet; a pump inlet tubing disposed through a central bore of the perforated inlet and forming an annulus with the separator casing; a helical auger component disposed at a distal end of the pump inlet tubing; and a spigot disposed within the separator casing and downhole from the helical auger component, wherein the spigot comprises any embodiment disclosed herein.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of this disclosure, reference is now made to the following description, taken in conjunction with the accompanying drawings, in which:

FIG. 1 illustrates a schematic diagram of an artificial lift pumping system.

FIG. 2 illustrates an exploded orthogonal side view of a sand separator system.

FIG. 3 illustrates an orthogonal side view of an embodiment of a spigot of the sand separator system, with the separator casing shown in cross-sectional view.

FIGS. 4A and 4B illustrate an oblique view and an orthogonal side view of an alternative embodiment of a spigot of the sand separator system.

FIGS. 5A and 5B illustrate an oblique view and an orthogonal side view of an alternative embodiment of a spigot of the sand separator system.

FIGS. 6A and 6B illustrate an oblique view and an orthogonal side view of an alternative embodiment of a spigot of the sand separator system.

FIGS. 7A and 7B illustrate an oblique view and an orthogonal side view of an alternative embodiment of a spigot of the sand separator system.

FIGS. 8A and 8B illustrate an oblique view and an orthogonal side view of an alternative embodiment of a spigot of the sand separator system.

FIGS. 9A and 9B illustrate an oblique view and an orthogonal side view of an alternative embodiment of a spigot of the sand separator system.

FIG. 10 illustrates a flowchart of a method of producing hydrocarbon fluids from a wellbore in an artificial lift pumping system according to an embodiment of the disclosure.

DETAILED DESCRIPTION

Referring to FIG. 1, an artificial lift pumping system 100 is shown. The artificial lift pumping system 100 may generally be configured for producing hydrocarbon fluids from a wellbore 150. In the embodiment shown, the artificial lift pumping system 100 comprises a reciprocating rod pumping system, which can also be referred to as a sucker rod pump, rod pump, or rod lift system. Alternatively, the artificial lift pumping system 100 may comprise an electronic submersible pump system (ESP systems), a tower-type long-stroke pumping system, or any other suitable pumping system known in the art.

The artificial lift pumping system 100, which embodied as a reciprocating rod pumping system, may generally comprise a surface unit 102, commonly referred to as a pump jack or a beam pump, and a drive unit 104. In some embodiments, the drive unit 104 may comprise an electric motor, a gasoline engine, or a diesel engine that causes the surface unit 102 to reciprocate. For tower-style reciprocating pumps, the surface unit 102 can be the tower that is coupled to the drive unit 104. For electronic submersible pumping systems, the surface unit 102 can include a variable-frequency drive electrically coupled to a transformer, that is electrically coupled to a downhole pump.

The artificial lift pumping system 100 may further comprise a wellhead 106 disposed on top of a wellbore casing 108 that extends from the wellhead 106 into the wellbore 150 and may be cemented within the wellbore 150. In some embodiments, the wellhead 106 may include additional components known in the art with the aid of this disclosure, such as a production tree, stuffing box, one or more seals, a blowout preventer (BOP), or any combination thereof. A production tubing string 110 may extend from the wellhead 106 through the wellbore casing 108 and provide a fluid path through which hydrocarbon fluids are produced to the surface. The wellhead 106 may also connect to a hydrocarbon production line 112, through which the produced hydrocarbon fluids flow from the wellhead 106 to a storage vessel and/or pipeline.

For artificial lift pumping system 100 embodied as a reciprocating rod pumping system, a polished rod 114 may be coupled to the surface unit 102 by a bridle assembly and extend through the wellhead 106 (e.g., via seals to prevent leakage of produced fluid from the wellhead 106). The polished rod 114 may be coupled to a rod string 116 (commonly referred to as a “sucker rod string”) and extend through the production tubing string 110 to a plunger or pump 118 disposed at a bottom of or within the production tubing string 110. The reciprocating motion of the surface unit 102 may therefore be imparted through the polished rod 114 and the rod string 116 to the pump 118 to draw hydrocarbon fluid (e.g., oil, gas, water, or combinations thereof) into a sand separator system 200, where sand particles accompanying the hydrocarbon fluid may be removed prior to producing the hydrocarbon fluid to the wellhead 106 and into the hydrocarbon production line 112. The sand separator system 200 can be attached or otherwise fixed to the bottom of the wellbore 150 or to the production tubing string 110.

In embodiments where the artificial lift pumping system 100 is an electrical submersible pump system, the pump 118 can be an assembly that includes a pump, an electric motor, and a seal assembly positioned between the pump and the electric motor, where the assembly is located within the wellbore 150 and electrically connected to the surface unit 102 (e.g., via an electrical cable). The assembly can be attached to the production tubing string 110 and suspended in the wellbore 150 above the sand separator system 200.

Referring to FIG. 2, an exploded orthogonal side view of the sand separator system 200 is shown according to an embodiment of the disclosure. The sand separator system 200 is located in the wellbore 150, below the pump 118 that produces hydrocarbon fluids to the surface. The sand separator system 200 may generally comprise a sand separator assembly 201 comprising a perforated inlet 202, a separator casing 204, a pump inlet tubing 206, and a helical auger component 208. The sand separator system 200 may also comprise a spigot 210 disposed downhole from the helical auger component 208. Further, the sand separator system 200 may also comprise a purge valve 212 disposed downhole from the spigot 210.

In some embodiments, the perforated inlet 202 may be coupled to the wellbore casing 108 and/or form a portion of the wellbore casing 108. The perforated inlet 202 may be disposed at or near a targeted or producing subterranean formation 122. The perforated inlet 202 may generally comprise a plurality of perforations 203. The perforations 203 may provide a fluid pathway for hydrocarbon fluids to enter the wellbore casing 108. A packer seal (not shown) may generally be disposed above the perforated inlet 202 to prevent produced hydrocarbon fluids from ascending in the wellbore casing 108. The perforations 203 may be disposed around the perforated inlet 202 and communicate with a central bore extending therethrough. The perforations 203 may comprise angled, spiraled, and/or helical perforations that impart a cyclonic or swirling rotation to the hydrocarbon fluids that enter the perforated inlet 202 upon production. In aspects where the perforations 203 are angled, the perforations 203 are angled less than 90° with respect to a longitudinal axis of the wellbore. In aspects where the perforations 203 are spiraled, the spiral orientation may be clockwise or counterclockwise with respect to a longitudinal axis of the wellbore and/or the perforated inlet 202. The cyclonic or swirling motion may promote a homogeneous mixing of the hydrocarbon fluid and sand particles disposed therein. In some embodiments, the cyclonic or swirling motion may also aid in removing air bubbles or trapped gasses from the hydrocarbon fluid.

The separator casing 204 may be coupled to the perforated inlet 202. Additionally, the pump inlet tubing 206 may extend from the pump 118 through the central bore in the perforated inlet 202. An annulus 205 is formed between the separator casing 204 and the pump inlet tubing 206. Produced hydrocarbon fluid may enter the perforated inlet 202 through the perforations 203, where it may flow downward through the annulus 205 and continue to travel in the cyclonic or swirling motion along the annulus 205. A plurality of baffles 207 may be disposed within the annulus 205 and coupled to the separator casing 204 and/or the pump inlet tubing 206. In some embodiments, the baffles 207 may promote removal of the air bubbles or trapped gasses from the hydrocarbon fluid and/or may also further promote the continued cyclonic or swirling motion as the produced hydrocarbon fluid continues to flow along the annulus 205.

A helical auger component 208 may be coupled to the pump inlet tubing 206 at a distal downhole end of the pump inlet tubing 206. The helical auger component 208 may comprise a plurality of helical pathways 209 that extend around the helical auger component 208 in clockwise or anticlockwise direction. Helical pathways 209 may also extend around the helical auger component 208 in same or opposite direction of plurality of the angled, spiraled, and/or helical passaged perforations 203 of the perforated inlet 202. As the flow of hydrocarbon fluid continues downward through the annulus 205, it enters the helical pathways 209 of the helical auger component 208. In some embodiments, the helical pathways 209 may change the velocity of the flow of the produced hydrocarbon fluid with a centrifugal force sufficient to move the sand particles radially outward further than the hydrocarbon fluid relative to a longitudinal axis of the helical auger component 208. In some embodiments, the escape velocity of the flow of the produced hydrocarbon fluid from the helical auger component 208 may be in a range of from 1000 inch/sec to 1800 inch/sec (25.4 m/sec to 45.72 m/sec). It will be appreciated that the length of the helical auger component 208 and/or the number and size of the helical pathways 209 may be based on a desired minimum escape velocity, which is the velocity at which the produced hydrocarbon fluid exits the helical pathways 209 to ensure the sand particles are sufficiently forced radially outward towards the wall(s) of the separator casing 204. The number of helical pathways 209 on the helical auger component 208 can range from 1 to 6. In some aspects, the number of helical pathways 209 is one or two. In other aspects, the number of helical pathways 209 is three, four, five, or six. The greater the number of helical pathways 209, the greater the flow rate that can be achieved through the helical auger component 208. For example, the artificial lift pumping system 100 in FIG. 1, which is a reciprocating rod pumping system, may have a production flow rate of 80 to 200 bbl/day, and 1 or 2 helical pathways 209 on the helical auger component 208 may provide sufficient volume for the production flow rate. In an electronic submersible pumping system, the production flow rate may be 2,000 to 3,000 bbl/day, for example, and 3 to 6 helical pathways 209 on the helical auger component 208 may be utilized in order to provide sufficient volume for the production flow rate.

As the produced hydrocarbon fluid exits the helical pathways 209 of the helical auger component 208, the hydrocarbon fluid may be drawn into a central bore of the helical auger component 208 that is in fluid communication with the pump inlet tubing 206, and consequently the pump 118. The high velocity cyclonic or swirling motion forces the sand particles trapped in the produced hydrocarbon fluid radially outwardly toward the wall of the separator casing 204, thereby forcing the sand particles to separate from the produced hydrocarbon fluid and to fall (e.g., by force of gravity) towards the spigot 210 while the produced hydrocarbon fluid experiences a reversal in direction (e.g., due to a suction generated by the pump 118 in an upward direction to the pump inlet tubing 206) which draws the produced hydrocarbon fluid into the bottom of the helical auger component 208 and upward inside the helical auger component 208 to the pump inlet tubing 206.

The spigot 210 may be disposed within the separator casing 204 and downhole from the helical auger component 208 (e.g., between the helical auger component 208 and the purge valve 212). The spigot 210 generally comprises a head 214, a stem 216, and a body portion 218. The head 214 can guide any sand particles proximate the longitudinal axis of the separator casing 204 generally in a radially outward direction toward a gap that exists between the edges of the head 214 and the separator casing 204. All sand particles can flow through the gap and downward around or through the other portions (e.g., the stem 216, body portion 218) of the spigot 210. The head 214 may comprise a crown 220 having a cylindrical skirt 222 extending therefrom. In aspects, the crown 220 can be flat, concave, or convex in shape. The crown 220 may be placed at a distance from the helical auger component 208 that promotes and/or enhances sand particle separation from the produced hydrocarbon fluid. In some embodiments, the distance between the crown 220 and the helical auger component 208 may be at least 1 inch, at least 2 inches (5.08 cm), at least 3 inches (7.62 cm), at least 4 inches (10.16 cm), at least 5 inches (12.7 cm), or at least 6 inches (15.24 cm). Additionally, the distance between the crown 220 and the helical auger component 208 may be not greater than 6 inches (15.24 cm), not greater than 5 inches (12.7 cm), not greater than 4 inches (10.16 cm), not greater than 3 inches (7.62 cm), or even not greater than 2 inches (5.08 cm). Further, it will be appreciated that the distance between the crown 220 of the head 214 of the spigot 210 and the helical auger component 208 may be between any of these values, such as at least 1 inch (2.54 cm) to not greater than 6 inches (15.24 cm).

In some embodiments, the diameter of the crown 220 and/or the cylindrical skirt 222 of the head 214 may be optimized to maximize sand particle removal from the produced hydrocarbon fluid and/or minimize the amount of sand particles that enter the pump inlet tubing 206 with the produced hydrocarbon fluid. In some embodiments, the crown 220 and the cylindrical skirt 222 of the head 214 may comprise a diameter that is at least 40%, at least 60%, at least 65%, at least 66.7%, or at least 70% of the inner diameter of the separator casing 204 and/or the wellbore casing 108 in the wellbore 150. In aspects, a height or length of the cylindrical skirt 222 can be equal to or less than a diameter of the crown 220. Further, in some embodiments, the crown 220 may comprise a flexible, elastomeric cover or flange that extends beyond the outer circumference or diameter of the crown 220. In some embodiments, the flange may deflect and/or have slits formed therein to allow separated sand particles to pass beyond the head 214 of the spigot 210.

The stem 216 may generally extend from the cylindrical skirt 222 of the head 214. The stem 216 may comprise a smaller diameter than the cylindrical skirt 222. As such, the cylindrical skirt 222 may block sand particles from bypassing the head 214 once the sand particles have passed around the cylindrical skirt 222. In some embodiments, the stem 216 may comprise a first stem portion 216a coupled to the cylindrical skirt 222 and a second stem portion 216b coupled to the body portion 218. In some embodiments, the first stem portion 216a and the second stem portion 216b may be threadedly connected, welded, or any other form of detachable connection. In some embodiments, the first stem portion 216a and the second stem portion 216b may be welded, friction welded, or employ other means to couple the first stem portion 216a to the second stem portion 216b. In other embodiments, the stem 216 may comprise a single unitary component. Further, in some embodiments, the length of the stem 216 may be optimized to prevent or reduce reversal of the direction of flow of the sand particles (e.g., prevent upward flow of the sand particles), which may be dependent on the diameter of the wellbore casing 108, the separator casing 204, or other component and/or the flow rate of the hydrocarbon fluid therethrough.

The body portion 218 may be integrally formed with the stem 216 of the spigot 210. In aspects, the head 214, the stem 216, and the body portion 218 are integrally formed. The body portion 218 may generally comprise a larger diameter than the head 214 and the stem 216. In some embodiments, the body portion 218 may substantially fill the separator casing 204, such that the spigot 210 is affixed within the separator casing 204 to remain stationary during hydrocarbon production operations. In some embodiments, the body portion 218 may comprise a connector (e.g., external threads) that couple to the separator casing 204 and/or may be captured between various sections of the separator casing 204 that collectively form the separator casing 204. The body portion 218 may comprise a plurality of flow passages 219 that assists in reducing velocity of the sand particles flowing down through the flow passages 219 and allow the sand particles that flow from the head 214 (sand trapped in the spigot 210) to flow beyond and/or through the body portion 218. The velocity of the sand particles at the exit of the flow passages 219 or flow restriction area of the spigot is between 20 inch/sec to 50 inch/sec (50.8 cm/sec to 127 cm/sec). In some embodiments, the flow passages 219 may be semi-helical, such that each of the flow passages 219 extends only partially helically around the body portion 218. Further, in other embodiments, the flow passages 219 may comprise other configurations that promote continued sand particle removal as the hydrocarbon fluids are produced. Once the sand particles have passed through the flow passages 219 of the body portion 218, the sand particles may be prevented from rising towards the pump inlet tubing 206 due to pressure in the separator casing 204, thereby trapping and/or permanently removing the sand particles from the produced hydrocarbon fluid.

The purge valve 212 may be disposed in the separator casing 204 downhole from the spigot 210. The purge valve 212 may collect the separated sand particles that have been permanently removed from the produced hydrocarbon fluid by the sand separator assembly 201 and the spigot 210. The purge valve 212 may accumulate sand particles and perform a dumping operation in response to the weight of the accumulated sand particles and/or pressure on the purge valve 212 exceeding a predetermined threshold pressure. In some embodiments, the purge valve 212 may discharge the accumulated sand particles when the threshold pressure inside the separator casing 204 reaches or exceeds about 14.5 pounds per square inch (psi) (1 atm.). During the dumping operation, the purge valve 212 may expel the accumulated sand particles to the wellbore 150 to altogether remove the sand particles from the separator casing 204.

In operation, hydrocarbon fluid may be produced from the subterranean formation 122 and pass through the sand separator assembly 201 and the spigot 210, collectively, the sand separator system 200 to remove sand particles from the produced hydrocarbon fluid. The components of the sand separator assembly 201 and/or the spigot 210 may be sized to reduce or eliminate a pressure differential, maximize the cyclonic motion of the produced hydrocarbon fluid, and maximize the amount of sand particles removed from the produced hydrocarbon fluid that exceeds the performance of traditional sand separator system that operate without the spigot 210. In some embodiments, the sand separator system 200 may operate to remove at least 55%, at least 60%, at least 70%, at least 80% at least 90%, at least 95%, at least 96%, at least 87%, at least 98%, at least 99%, or 100% of the sand particles from the produced hydrocarbon fluid that passes into the pump inlet tubing 206, which is produced to the wellhead 106. Thus, the sand separator system 200 provides a noticeable increase in separation efficiency (at least 5% to 50% increase) over traditional sand separator systems, thereby reducing and/or altogether eliminating the expenses and time associated with post-production procedures needed to remove any residual sand particles from the produced hydrocarbon fluid.

Referring to FIG. 3, an orthogonal side view of an embodiment of a spigot 300 of the sand separator system 200 is shown, with the separator casing 204 shown in cross-sectional view. The spigot 300 may generally comprise a head 214, a stem 216, and a body portion 218. Further, in some embodiments, a flexible, elastomeric flange 302 may be disposed over or extend from the crown 220 of the head 214 that extends beyond the outer circumference or diameter of the crown 220. In some embodiments, the flange may deflect to allow separated sand particles to move downward past the head 214 of the spigot 210. As stated, the body portion 218 may generally comprise a larger diameter than the head 214 and the stem 216. In some embodiments, the body portion 218 may substantially fill the separator casing 204, such that the spigot 210 is affixed within the separator casing 204 to remain stationary during hydrocarbon production operations. In some embodiments, the body portion 218 may comprise one or more externally threaded portions 304 that threadably couple to the separator casing 204 and/or may be positioned between various sections 204a, 204b of the separator casing 204 that collectively form the separator casing 204. Further, in some embodiments, a spring 306, such as a wave spring or other suitable spring, may be disposed between the body portion 218 and one or more of the sections 204a, 204b of the separator casing 204.

Referring now to FIGS. 4A to 9B, oblique views and orthogonal side views of alternative embodiments of a spigot 400, 500, 600, 700, 800, 900 of the sand separator system 200 are shown. Each of the spigots 400, 500, 600, 700, 800, 900 may be substantially similar to spigot 210, 300 and comprise a head 214 and a stem 216. However, spigots 400, 500, 600, 700, 800, 900 comprise a plurality of body portions 402, 502, 602, 702, 802, 902, respectively. For clarity, the spigots 400, 500, 600, 700, 800, 900 are shown without the head 214, which may include in some embodiments a first stem portion 216a extending therefrom that couples to the second stem portion 216b of each of the spigots 400, 500, 600, 700, 800, 900.

As shown in FIGS. 4A and 4B, the spigot 400 may comprise a plurality of body portions 402 that may be substantially similar to body portion 218. Each body portion 402 may comprise a plurality of angled, spiraled, or helical flow passages 404. In some embodiments, the flow passages 404 may be substantially similar to flow passages 219. In some embodiments, the flow passages 404 may extend only partially around their respective body portion 402.

As shown in FIGS. 5A and 5B, the spigot 500 may comprise a plurality of body portions 502. Each body portion 502 may comprise a semi-circular or semi-annular baffle comprising an angled top portion 504. Each baffle of spigot 500 may extend radially from the second stem portion 216b. In some embodiments, each baffle of spigot 500 may extend at least partially around the second stem portion 216b. In some embodiments, each baffle of spigot 500 may extend at least 90 degrees around the second stem portion 216 b. In some embodiments, each baffle of spigot 500 may extend at least 180 degrees around the second stem portion 216b such that each baffle longitudinally overlaps at least one adjacent baffle.

As shown in FIGS. 6A and 6B, the spigot 600 may comprise a plurality of body portions 602. Each body portion 602 may be substantially similar to body portions 502 and comprise a semi-circular or semi-annular baffle comprising an angled top portion 604. However, the baffles of spigot 600 do not extend radially from the second stem portion 216b and instead wrap spirally or helically at least partially around the second stem portion 216b. In some embodiments, each baffle of spigot 600 may extend at least 90 degrees around the second stem portion 216b. In some embodiments, each baffle of spigot 600 may extend at least 180 degrees around the second stem portion 216b such that each baffle longitudinally overlaps at least one adjacent baffle.

As shown in FIGS. 7A and 7B, the spigot 700 may comprise a plurality of body portions 702. Each body portion 702 may be substantially similar to body portions 502 and comprise a semi-circular or semi-annular baffle. Each baffle of spigot 700 may also extend radially from the second stem portion 216b. However, the baffles of spigot 700 are inverted with respect to the baffles of spigot 500 and comprise a curved or radiused bottom portion 704. Each baffle of spigot 700 may extend radially from the second stem portion 216b. In some embodiments, each baffle of spigot 700 may extend at least 90 degrees around the second stem portion 216b. In some embodiments, each baffle of spigot 700 may extend at least 180 degrees around the second stem portion 216b such that each baffle longitudinally overlaps at least one adjacent baffle.

As shown in FIGS. 8A and 8B, the spigot 800 may comprise a plurality of body portions 802. Each body portion 802 may be substantially similar to body portions 502 and comprise a semi-circular or semi-annular baffle. Each baffle of spigot 800 may also extend radially from the second stem portion 216b. However, the baffles of spigot 800 comprise a flat top portion 804. In some embodiments, each baffle of spigot 800 may extend at least 90 degrees around the second stem portion 216b. In some embodiments, each baffle of spigot 800 may extend at least 180 degrees around the second stem portion 216b such that each baffle longitudinally overlaps at least one adjacent baffle.

As shown in FIGS. 9A and 9B, the spigot 900 may comprise a plurality of body portions 902. Each body portion 902 may comprise a tubular protrusion that extends radially from the second stem portion 216b. In some embodiments, the tubular protrusions of spigot 900 may be aligned in lateral rows 904a, 904b, . . . 904n around the circumference of the second stem portion 216b. In some embodiments, the tubular protrusions of spigot 900 may be alternatingly staggered along the length of the second stem portion 216b such that a body portion 902a in a first row 904 of tubular protrusions may be disposed between two adjacent body portions 902b in an adjacent second row 906 of tubular protrusions. However, in other embodiments, the tubular protrusions of spigot 900 may be aligned helically or any other pattern to allow separated sand particles to pass around and/or through the spigot 900.

It will be appreciated that the spigots 210, 300, 400, 500, 600, 700, 800, 900 may be implemented in a sand separator system 200 and disposed downstream from a sand separator assembly 201. The spigots 210, 300, 400, 500, 600, 700, 800, 900 are designed to enhance the sand particle removal from the produced hydrocarbon fluid that is extracted from the subterranean formation 122. In some embodiments, the spigots 210, 300, 400, 500, 600, 700, 800, 900 may also trap separated sand particles from reentering the stream of produced hydrocarbon fluid that exits the helical auger component 208 and turns to enter the central bore of the helical auger component 208 to the pump inlet tubing 206. While traditional sand separators may remove between about 25-51% of the sand particles from the produced hydrocarbon fluid, embodiments of the sand separator system 200 disclosed here that comprise a spigot 210, 300, 400, 500, 600, 700, 800, 900 may remove at least 55% of the sand particles from the hydrocarbon fluid that enters the pump inlet tubing 206 and is subsequently produced to the wellhead 106. In some embodiments, the sand separator system 200 disclosed here that comprise a spigot 210, 300, 400, 500, 600, 700, 800, 900 may remove at least 60%, at least 70%, at least 80% at least 90%, at least 95%, at least 96%, at least 87%, at least 98%, at least 99%, or even 100% of the sand particles from the hydrocarbon fluid that enters the pump inlet tubing 206 before carrying the produced hydrocarbon fluid to the wellhead 106.

Referring to FIG. 10, a flowchart of a method 1000 of producing hydrocarbon fluids from a subterranean formation 122 is shown according to an embodiment of the disclosure. The method 1000 may begin at block 1002 by providing a sand separator system 200 in the wellbore 150. The sand separator system 200 may generally comprise a perforated inlet 202, a separator casing 204 coupled to the perforated inlet 202, a pump inlet tubing 206 disposed through a central bore of the perforated inlet 202 and forming an annulus 205 with the separator casing 204, and a helical auger component 208 disposed at a distal end of the pump inlet tubing 206. The sand separator system 200 may also comprise a spigot 210 disposed downhole from the sand separator assembly 201, and a purge valve 212 disposed downhole from the spigot 210.

The method 1000 may continue at block 1004 by drawing hydrocarbon fluid into the perforated inlet 202 through a plurality of perforations 203 forming a fluid pathway between a subterranean formation 122 and the annulus 205.

The method 1000 may continue at block 1006 by flowing the hydrocarbon fluid through the annulus 205 and through a plurality of helical pathways 209 formed in the helical auger component 208 to impart a cyclonic motion to the hydrocarbon fluid.

The method 1000 may continue at block 1008 by drawing the hydrocarbon fluid through a central bore of the helical auger component 208 that forms a fluid flow path with the pump inlet tubing 206 to separate the hydrocarbon fluid from a plurality of sand particles disposed therein.

The method 1000 may continue at block 1010 by passing the plurality of sand particles separated from the hydrocarbon fluid around and/or through the spigot 210, wherein at least 55%, at least 60%, at least 70%, at least 80% at least 90%, at least 95%, at least 96%, at least 87%, at least 98%, at least 99%, or even 100% of the plurality of sand particles are removed from the hydrocarbon fluid that enters the pump inlet tubing 206.

It will be appreciated that a spigot 210, 300, 400, 500, 600, 700, 800, 900, an artificial lift pumping system 100, a sand separator system 200, and/or a method 1000 of producing hydrocarbon fluids from a subterranean formation 122 may comprise one or more of the following embodiments:

• • Embodiment 1. A spigot for a sand separator system, comprising: a head comprising a crown and a cylindrical skirt extending therefrom; a stem extending from the head; and a body portion coupled to a distal end of the stem and comprising a plurality of fluid flow passages extending therethrough.
  • Embodiment 2. The spigot of embodiment 1, wherein the stem comprises a smaller diameter than the head.
  • Embodiment 3. The spigot of embodiment 1 or 2, wherein the stem comprises a first stem portion coupled to the head and a second stem portion coupled to the body portion.
  • Embodiment 4. The spigot of embodiment 3, wherein the first stem portion is connected, welded, or any other form of detachable connection to the second stem portion are threadedly.
  • Embodiment 5. The spigot of embodiment 1 to 4, wherein the head, the stem, and the body portion are integrally formed as a single piece.
  • Embodiment 6. The spigot of embodiment 1 to 5, wherein the body portion comprise a larger diameter than the head and the stem.
  • Embodiment 7. The spigot of embodiment 6, wherein the body portion comprises a plurality of flow passages that allow sand particles to pass through the body portion.
  • Embodiment 8. The spigot of embodiment 7, wherein the flow passages extend only partially around the body portion.
  • Embodiment 9. The spigot of embodiment 1 to 8, wherein the spigot comprises a plurality of body portions.
  • Embodiment 10. The spigot of embodiment 9, wherein each of the body portions comprises a semi-annular baffle.
  • Embodiment 11. The spigot of embodiment 10, wherein each of the body portions comprises a plurality of flow passages.
  • Embodiment 12. The spigot of embodiment 11, wherein each of the body portions extends at least 180 degrees around the stem, such that each body portion longitudinally overlaps at least one adjacent body portion.
  • Embodiment 13. The spigot of embodiment 9, wherein each of the body portions comprises a tubular protrusion that extends radially from the stem.
  • Embodiment 14. The spigot of embodiment 1 to 13, wherein the spigot is configured to be disposed downhole from a helical auger component of a sand separator assembly.
  • Embodiment 15. The spigot of embodiment 1 to 14, wherein the spigot is configured to remove at least 55%, at least 60%, at least 70%, at least 80% at least 90%, at least 95%, at least 96%, at least 87%, at least 98%, at least 99%, or even 100% of sand particles from a hydrocarbon fluid.
  • Embodiment 16. A sand separator system, comprising: a perforated inlet comprising a plurality of perforations; a separator casing coupled to the perforated inlet; a pump inlet tubing disposed through a central bore of the perforated inlet and forming an annulus with the separator casing; a helical auger component disposed at a distal end of the pump inlet tubing and comprising a plurality of external helical pathways; and a spigot disposed downhole from the helical auger component, wherein the spigot comprises a head comprising a crown and a cylindrical skirt extending therefrom, a stem extending from the head, and a body portion coupled to a distal end of the stem and comprising a plurality of fluid flow passages extending therethrough.
  • Embodiment 17. The sand separator system of embodiment 16, wherein the perforations comprise angled, spiraled, and/or helical passages that impart a cyclonic or swirling rotation to a hydrocarbon fluid that enter the perforated inlet.
  • Embodiment 18. The sand separator system of embodiment 16 or 17, wherein the crown of the spigot is disposed between at least 1 inch (2.54 cm) to not greater than 6 inches (15.24 cm) from the helical auger component (e.g., from an outlet of the auger component or from a distal end of the auger component).
  • Embodiment 19. The sand separator system of embodiment 16 to 18, wherein the spigot is affixed within the separator casing to remain stationary during hydrocarbon production operations.
  • Embodiment 20. The sand separator system of embodiment 19, wherein the body portion of the spigot comprises a connector that couples the spigot to the separator casing (e.g., the connector is positioned or captured between sections of the separator casing).
  • Embodiment 21. The sand separator system of claim 16 to 20, wherein the spigot is configured to remove at least 55%, at least 60%, at least 70%, at least 80% at least 90%, at least 95%, at least 96%, at least 87%, at least 98%, at least 99%, or even 100% of sand particles from a hydrocarbon fluid.
  • Embodiment 22. The sand separator system of embodiment 16 to 21, further comprising: a purge valve disposed downhole from the spigot and configured to collect separated sand particles that have been permanently removed from a hydrocarbon fluid by the sand separator assembly.
  • Embodiment 23. The sand separator system of embodiment 22, wherein the purge valve is configured to perform a dumping operation to expel the separated sand particles to a wellbore in which the sand separator system is disposed in response to a weight of the separated sand particles or pressure on the purge valve exceeding a predetermined threshold.
  • Embodiment 24. An artificial lift pumping system, comprising: a surface unit; a wellhead disposed on a top of a wellbore casing cemented within a wellbore; a production tubing string extending through the wellbore casing; i) a polished rod coupled to the surface unit and extending through the production tubing string to impart reciprocating motion through a rod string disposed in the wellbore to a rod pump disposed at a bottom of or within the production tubing string or ii) an electric submersible pump positioned in the wellbore casing and coupled to the production tubing string; and a sand separator system according to any of the preceding embodiments and comprising: a spigot according to any of the preceding embodiments.
  • Embodiment 25. A method of producing hydrocarbon fluids from a subterranean formation, comprising: providing a sand separator system comprising: a perforated inlet; a separator casing coupled to the perforated inlet; a pump inlet tubing disposed through a central bore of the perforated inlet and forming an annulus with the separator casing; a helical auger component disposed at a distal end of the pump inlet tubing; and a spigot disposed downhole from the helical auger component, wherein the spigot comprises a head comprising a crown and a cylindrical skirt extending therefrom, a stem extending from the head, and a body portion coupled to a distal end of the stem and comprising a plurality of fluid flow passages extending therethrough; drawing hydrocarbon fluid into the perforated inlet through a plurality of perforations that form a fluid pathway between a subterranean formation and the annulus; flowing the hydrocarbon fluid through the annulus and through a plurality of helical pathways formed in the helical auger component to impart a cyclonic motion to the hydrocarbon fluid; drawing the hydrocarbon fluid through a central bore of the helical auger component that forms a fluid flow path with the pump inlet tubing to separate the hydrocarbon fluid from a plurality of sand particles disposed therein; and passing the plurality of sand particles separated from the hydrocarbon fluid around and/or through the spigot, wherein at least 55%, at least 60%, at least 70%, at least 80% at least 90%, at least 95%, at least 96%, at least 87%, at least 98%, at least 99%, or even 100% of the plurality of sand particles are removed from the hydrocarbon fluid that enters the pump inlet tubing and flows to a wellhead.
  • Embodiment 26. A method comprising: producing hydrocarbon fluids from a subterranean formation with a sand separator system that is placed in a wellbore at a depth that is in fluid communication with a producing zone of the subterranean formation, wherein the sand separator system comprises: a perforated inlet; a separator casing coupled to the perforated inlet; a pump inlet tubing disposed through a central bore of the perforated inlet and forming an annulus with the separator casing; a helical auger component disposed at a distal end of the pump inlet tubing; and a spigot disposed within the separator casing and downhole from the helical auger component, wherein the spigot comprises any embodiment disclosed herein.
  • Embodiment 27. A method comprising: dumping sand from a sand separator system that is placed in a wellbore at a depth that is in fluid communication with a producing zone of a subterranean formation, wherein the sand separator system comprises: a perforated inlet; a separator casing coupled to the perforated inlet; a pump inlet tubing disposed through a central bore of the perforated inlet and forming an annulus with the separator casing; a helical auger component disposed at a distal end of the pump inlet tubing; and a spigot disposed within the separator casing and downhole from the helical auger component, wherein the spigot comprises any embodiment disclosed herein.
  • Embodiment 28. A sand separator system, comprising: a perforated inlet comprising a plurality of perforations having any configuration disclosed herein; a separator casing coupled to the perforated inlet; a pump inlet tubing disposed through a central bore of the perforated inlet and forming an annulus with the separator casing; and a helical auger component disposed at a distal end of the pump inlet tubing and comprising a plurality of external helical pathways.
  • Embodiment 29. A method of separating sand particles from hydrocarbon fluid: entering the fluid including sand particles in an annulus of a separator casing through a perforated inlet coupled at an upper end of the separator casing; flowing down of the fluid in an annulus defined as a hollow space between the separator casing and a pump inlet tube placed in the center bore of the separator casing; entering of the fluid into a helical auger placed at a distal end of the annulus to produce a cyclonic or swirling motion in the fluid and the sand particle; exiting of the fluid from the auger with high cyclonic or swirling motion resulting in pushing the sand particles present in the fluid towards a wall of the separator casing; flowing down of the sand particles towards a spigot head to guide the sand particles towards the wall of the separator casing; and flowing of the sand particles towards flow restriction area provided at the body of the spigot to reduce velocity of the sand particles to accumulate the sand particles on a purge valve.

Although the present disclosure and its advantages have been described in detail, it should be understood that various changes, substitutions, and alterations can be made herein without departing from the spirit and scope of the disclosure. Moreover, the scope of the present application is not intended to be limited to the particular embodiments of the process, machine, manufacture, composition of matter, means, methods and steps described in the specification. As one of ordinary skill in the art will readily appreciate from the disclosure, processes, machines, manufacture, compositions of matter, means, methods, or steps, presently existing or later to be developed that perform substantially the same function or achieve substantially the same result as the corresponding embodiments described herein may be utilized according to the present disclosure. Accordingly, the appended claims are intended to include within their scope such processes, machines, manufacture, compositions of matter, means, methods, or steps.