VALVE ROD GUIDES FOR BOTTOM HOLE PUMP ASSEMBLIES, AND RELATED METHODS AND PARTS

A bottom hole pump (BHP) assembly for a reciprocating sucker rod in a production well has: a downhole fluid pump; a valve rod mounted to reciprocate within the downhole fluid pump, the valve rod having a sucker rod connector; and a valve rod guide mounted to the downhole fluid pump around the valve rod and connected to, in use, receive fluids into an internal fluid chamber from an internal bore of the downhole fluid pump and direct the fluids radially outward to an annulus of a well bore through a radial port in the valve rod guide assembly; and in which the valve rod guide has a ceramic wear sleeve that lines an internal valve-rod-receiving cylindrical passage defined by the valve rod guide.

TECHNICAL FIELD

This document relates to valve rod guides for bottom hole pump (BHP) assemblies, and related methods and parts.

BACKGROUND

The following paragraphs are not an admission that anything discussed in them is prior art or part of the knowledge of persons skilled in the art.

Deviated wellbores and imperfectly straight sucker rod strings may lead to wear on various parts of a production well. One example of such wear may occur on or in the bottom hole pump assembly. A valve rod guide may be used to centralize and reduce wear on the valve rod (connected to the sucker rod string) during pumping action. Valve rod guides are typically used with carbide inserts that fracture, break, and wear over time.

SUMMARY

A bottom hole pump (BHP) assembly is disclosed for a reciprocating sucker rod in a production well comprising: a downhole fluid pump; a valve rod mounted to reciprocate within the downhole fluid pump, the valve rod having a sucker rod connector; and a valve rod guide mounted to the downhole fluid pump around the valve rod and connected to, in use, receive fluids into an internal fluid chamber from an internal bore of the downhole fluid pump and direct the fluids radially outward to an annulus of a well bore through a radial port in the valve rod guide assembly; and in which the valve rod guide has a ceramic wear sleeve that lines an internal valve-rod-receiving cylindrical passage defined by the valve rod guide.

A production well assembly is disclosed comprising: a sucker rod string within a well that penetrates a formation; a primary mover at a well surface, the primary mover connected to reciprocate the sucker rod string; and a BHP assembly, in which the sucker rod connector of the valve rod is connected to the sucker rod string.

A method is disclosed of operating a production well assembly comprising reciprocating the sucker rod string using the primary mover to pump well fluids from a fluid inlet of the downhole fluid pump, through the valve rod guide, and up to the well surface.

A valve rod guide is disclosed comprising: a rod guide body defining an open downhole cylindrical pump-barrel-mounting end that defines an internal pump fluid chamber and a radial port to an exterior surface of the rod guide body, the rod guide body being structured for, in use, receiving and directing well fluids pumped through the open downhole cylindrical pump-barrel-mounting end into a wellbore annulus via the radial port, the rod guide body defining a valve rod axial bore therethrough; a ceramic wear sleeve seated within an internal valve-rod-receiving cylindrical passage defined by the rod guide body; and a rod guide cap mounted to an uphole end of the rod guide body to secure an uphole end of the ceramic wear sleeve within the wear sleeve receptacle.

A method is disclosed comprising driving a sucker rod string to pump well fluids from a fluid inlet of a downhole fluid pump, through a valve rod guide, and up to the well surface, in which the valve rod guide has an internal ceramic wear sleeve that lines an interior bore of the valve rod guide and encircles a valve rod, which is driven by the sucker rod string to drive the downhole fluid pump.

In various embodiments, there may be included any one or more of the following features: The ceramic wear sleeve is cylindrical. The valve rod guide comprises: a rod guide body; and a rod guide cap. The rod guide body has an open downhole end that defines the internal fluid chamber and the radial port. The open downhole end defines a threaded female box. The rod guide body defines an uphole-facing internal axial shoulder that seats a downhole end of the ceramic wear sleeve in the internal valve-rod-receiving cylindrical passage. The rod guide cap is threaded to an uphole end of the rod guide body. The rod guide cap defines a downhole-facing internal axial shoulder that secures an uphole end of the ceramic wear sleeve. The rod guide cap has a threaded female box end that mounts to a threaded male end of the rod guide body. The rod guide cap defines a bushing keyway torque slot. The bushing keyway torque slot defines a radial slot at an uphole end of the rod guide cap. A valve rod bushing, of the sucker rod connector or connected to the sucker rod connector, defines a key structured to mate with the bushing keyway torque slot for torque transfer. The downhole fluid pump comprises: a traveling valve mounted to the valve rod; and a standing valve mounted to a downhole fluid inlet of the downhole fluid pump. The ceramic wear sleeve is cylindrical; and the open downhole cylindrical pump-barrel-mounting end defines a threaded female box. The rod guide cap has a threaded female box that mounts to a threaded male end of the rod guide body; and the rod guide cap defines a bushing keyway torque slot.

The foregoing summary is not intended to summarize each potential embodiment or every aspect of the subject matter of the present disclosure. These and other aspects of the device and method are set out in the claims.

DETAILED DESCRIPTION

In the life of an oil well there are several phases—drilling, completion, and production. Once a well has been drilled, it is completed to provide an interface with the reservoir rock and a tubular conduit for the well fluids. Well completion is a generic term used to describe the installation of tubulars and equipment required to enable safe and efficient production from an oil or gas well. The production phase occurs after successful completion, and involves producing hydrocarbons through the well from an oil or gas field.

Referring toFIG.1, a production wellhead assembly12is illustrated. The assembly12may be an assembly of components that form the surface termination of a wellbore and includes various production equipment at the surface. A production wellhead assembly may include spools, valves, manifolds, and assorted adapters that provide pressure control of a production well. The assembly12may incorporate components, such as a casing bowl or spool13, for internally mounting a casing hanger14during the well construction phase. The casing hanger14suspends a casing string16, which may be steel pipe cemented in place during the construction process to stabilize the wellbore. The wellhead or bowl or casing spool13may be welded onto the outer string of casing, which has been cemented in place during drilling operations, to form an integral structure of the well.

The assembly12may include surface flow-control components, such as the group of components that are sometimes collectively referred to as a Christmas tree22. The Christmas tree22may installed on top of the casing spool13, for example with isolation valves24, and choke equipment such as production valves26to control the flow of well fluids during production. Other components such as a flow manifold27, also known as a flow tee, a bonnet44and a rod blowout preventer (BOP)29may be provided as part of the production wellhead assembly12. Manifold27, bonnet44, and BOP29may be mounted on a spool31mounted on the tubing head18. The flow manifold27may direct produced fluids to processing or storage equipment, such as a surface production tank.

The production wellhead assembly12may incorporate a mechanism for hanging production tubing17. For example, the assembly12may include a tubing head18mounted on the casing spool13, the tubing head18internally mounting a tubing hanger20. A tubing hanger20is a component used in the completion of oil and gas production wells. It may be set in the Christmas tree22or the wellhead and suspends the production tubing17and/or casing. Sometimes the tubing hanger20provides porting to allow the communication of hydraulic, electric and other downhole functions, as well as chemical injection. The tubing hanger20may also serve to isolate the interior bore38and production areas (i.e., within the interior of the tubing17). The production tubing17runs the length of the well to a bottom hole pump assembly10(BHP), and serves to isolate the tubing interior from the annulus for production up the interior of the tubing17.

A production wellhead assembly12may connect to or house part of an artificial lift system such as a reciprocating rod pump assembly10or drive. An artificial lift is a system that adds energy to the fluid column in a wellbore with the objective of initiating and improving production from the well. Artificial-lift systems use a range of operating principles, including rod pumping, gas lift and electric submersible pump. A reciprocating rod drive, such as a pump jack28, is an artificial-lift pumping system that uses a surface power source to drive a BHP assembly (pump assembly10). A beam and crank assembly in the pump jack28converts energy, for example in the form of rotary motion from a prime mover (although the pump jack28may be considered part of the prime mover), into a reciprocating motion in a sucker-rod string30that connects to a BHP assembly. The BHP may contain a plunger and valve assembly to convert the reciprocating motion to vertical fluid movement.

A pump jack28is also known as an oil horse, donkey pumper, nodding donkey, pumping unit, horsehead pump, rocking horse, beam pump, dinosaur, grasshopper pump, Big Texan, thirsty bird, or jack pump in some cases. A pump jack or other artificial lift system may be used to mechanically lift liquid out of the well when there is not enough bottom hole pressure for the liquid to flow all the way to the surface. Pump jacks are commonly used for onshore wells producing little oil. In some cases, a pump jack may be used with the disclosed embodiments, and in other cases, other types of drives may be used, including elevator rotating drives.

A reciprocating rod drive such as a pump jack28may connect via a bridle32to a piston known as a polished rod34that passes through a stuffing box36to enter the wellbore. The polished rod34is the uppermost joint in the sucker rod string30used in a rod pump artificial-lift system. The polished rod34enables an efficient hydraulic seal to be made by the stuffing box36around the reciprocating rod string. Thus, the polished rod34is able to move in and out of the stuffing box without production fluid leakage. The bridle32follows the curve of the horse head33as it lowers and raises to create a nearly vertical stroke. The polished rod34is connected to a long string30of rods called sucker rods, which run through the tubing17to the down-hole pump, usually positioned near the bottom of the well.

The sucker rod string30may have a suitable structure, and be made up of a plurality of sucker rods. A sucker rod may be a steel rod, typically between 25 and 30 feet (7 to 9 meters) in length, and usually threaded at both ends, and that is used to join together the surface and downhole components of a reciprocating piston pump assembly10installed in an oil well. The pumpjack28may make up the visible above-ground drive for the well pump, and be connected to the BHP assembly10at the bottom of the well by a series of interconnected sucker rods, forming a sucker rod string30. Sucker rods may be terminated in metallic threaded ends, for example a female box at one end and a male pin at the other end. At the bottom of the sucker rod string30may be located the down-hole pump assembly10. Referring toFIGS.1and2, a BHP assembly10may have dual valves such as two ball check valves, such as valve assemblies63and68, for example a stationary valve at bottom called the standing valve or standing valve assembly68, and a valve on the piston of the pump connected to the bottom of the sucker rods that travels up and down as the rods reciprocate, known as the traveling valve or travelling valve assembly63. Fluid may enter the pump assembly10from a formation49into the bottom of the borehole through perforations that have been made through the casing and cement. When pumpjack28is going through an upstroke, the sucker rods are travelling up, the traveling valve is closed and the standing valve is open (due to the drop in pressure in the pump). Consequently, the pump fills with the fluid from the formation as the traveling piston lifts the previous contents of the pump upwards. At the same time (upstroke), any fluid that is located in the pump assembly10uphole from the traveling valve will be forced in the uphole direction, into the tubing17and up the well. When the pumpjack28begins a downstroke, the traveling valve opens and the standing valve closes (due to an increase in pressure in the pump). The traveling valve passes through the fluid in the pump assembly10, which has been sucked in during the upstroke. The pump assembly10then reaches the end of its stroke and begins its path upwards again, repeating the process.

The successful operation of the polished rod and sucker rod string30requires careful alignment from surface to formation49. At surface, a tight seal is required between the polished rod34and the seals (not shown) of the stuffing box36. If the polished rod34becomes damaged, for example scored, the rod34must be replaced before damage is done to the stuffing box36. In some cases, the seals also must be replaced. During use, damage to the polished rod34and rod string30may be caused from continued contact with internal components of the production wellhead assembly12, the tubing17, or the components of the BHP assembly10. Even in a perfectly vertical well, or a well nominally deviated from vertical near the surface, the rod string30may reciprocate with continual or intermittent contact with various above-ground and downhole parts of the production well. In some wells that deviate from true vertical measured with respect to the surface of the earth, rod34or rod string30may be drawn to one side where contact can occur to a greater degree than other locations or orientations. A fluid leak may be caused if damage is done to the rod34, such leak leading to potential environmental damage and cleanup cost. Wear on the rod string30and/or BHP assembly10may also cause leakage or inefficient/non-functioning pumping action below surface. Production wellheads are often unmanned and in remote areas in many cases, and thus, even a relatively small fluid leak or inefficiency carries a potential for exacerbated negative effects because the leak or damage may go unnoticed for days and sometimes weeks. Replacing the rod34or rod string30may require a well service entity to temporarily kill the well, lift the damaged rod out of the well, connect a new rod, and repair any damaged parts of the production well before reassembling and re-initiating the well back into production. In many cases the new rod34or rod string30may itself become damaged in a short period of time, because the underlying cause of the damage still exists, namely the deviated well. In some cases, a well operator will install roller guides or centralizers40on the rod34or rod string30at various spaced locations to ride along the rod string30or guide the rod string into alignment below the tubing hanger20.

Minor deviations from vertical often occur naturally in the wellbore. Such deviations may be related to formation properties, such as dip angle and hardness, and other factors. Deviation of the wellbore can cause wear on sucker rods, which may eventually ruin the sucker rods, or damage the downhole components of the pump assembly10, potentially causing the entire well to fail. A rod rotator is one solution that has been used to extend the lifespan of the sucker rod string30. A rod rotator may function by incrementally rotating the sucker rod with each stroke of the pumpjack to evenly distribute wear around the rods and couplings, rather than limiting the wear to one side of the sucker rods. However, the use of a rod rotator is not a permanent solution as wear will still ultimately degrade and ruin the sucker rods, which will eventually cause the pump to lose efficiency as the fit of the sucker rods within the well is modified by the wear.

Within a BHP assembly10, a valve rod guide80may be used to centralize the valve rod50of the pump assembly10along an axis88of the pump assembly10. A conventional valve rod guide80may carry a carbide insert (not shown), which acts as a sacrificial material, as such will wear down itself over time, preventing or delaying the valve rod50from being worn down at the same rate. Once the carbide insert has been sufficiently worn down, only the insert may be needed to be replaced with a new carbide insert, thus decreasing usage costs if the insert can be used to avoid or delay replacement of the rod string30, the BHP assembly10or part of either. However, since carbide is a relatively hard material, when the carbide insert wears out, pieces may break off of the carbide insert, or the insert may fail entirely—defeating the purpose of the insert and leading to rod string30wear and eventual pump failure. Broken pieces from the carbide insert are known to jam up the pump48and any piece that runs through the guide.

Referring toFIGS.2-8, a valve rod guide80is illustrated, for use in a BHP assembly10. In use, the BHP assembly10may comprise a downhole pump48, a valve rod50and the valve rod guide80. The valve rod50may be mounted to reciprocate within the downhole fluid pump48. The valve rod50may have a sucker rod connector, for example an uphole male cylindrical threaded end50A, which may connect to a sucker rod of a sucker rod string30(not shown inFIGS.2-8). The valve rod guide80may be mounted to, for example within, the downhole fluid pump48, for example at or near an uphole end48A of the pump48. The guide80may be mounted to encircle the valve rod50in use and may be connected to receive fluids into an internal fluid chamber82G-1(for example of a rod guide body82of the guide80) from an internal bore48C of the downhole fluid pump48. The valve guide80may be structured to direct received fluids radially outward to an annulus17C of a well bore (defined in the example ofFIG.2as the interior of the tubing17) in use through a radial port82F in the valve rod guide80assembly. The valve rod guide80may define an internal valve-rod-receiving cylindrical passage82G-2, which may form part of an interior bore80C of the guide80. The side slots (radial ports) in the guide may be provided for fluid transfer to allow fluid to escape from and lubricate the guide

Referring toFIGS.2-8, the valve rod guide80may have a ceramic insert wear sleeve84. The sleeve84may line a portion of the interior bore80C of the valve rod guide80, for example, the sleeve84may line at least a portion of the passage82G-2. A ceramic material may be made from any of the various hard, brittle, heat-resistant and corrosion-resistant materials made by shaping and then firing an inorganic, nonmetallic material, such as clay, at a high temperature. Ceramics are known to be abrasion resistance, and may show plastic deformation. However, because of the rigid structure of ceramic material they may deform very slowly. To overcome the brittle behavior, ceramic material development has introduced the class of ceramic matrix composite materials, in which ceramic fibers are embedded and with specific coatings are forming fiber bridges across any crack. This mechanism substantially increases the fracture toughness of such ceramics. Ceramics may be chemically resistant and can be used in wet environments where other parts would rust. The ceramic wear sleeve84may have a suitable shape, for example the sleeve84may be cylindrical. In other cases, the ceramic wear sleeve84may be any shape which allows for the ceramic wear sleeve84to extend the life of the well.

Referring toFIGS.2-8the valve rod guide80may comprise various parts, such as a rod guide body82, the ceramic insert wear sleeve84, and a rod guide cap86. The rod guide body82may define an open downhole end, such as a cylindrical pump-barrel-mounting end, such as a downhole female box threaded end82B. The end82B or other portion of the body82may define internal pump fluid chamber82G-1and radial port82F to an exterior surface82E-1of the rod guide body82. The valve rod guide body82may be structured for, in use, receiving and directing well fluids pumped through the open downhole end82B, into a wellbore annulus (such as annulus17C defined by tubing17) via the radial port82F. The ceramic wear sleeve84may be seated within a wear sleeve receptacle82J, which may form part of the passage82G-2. The receptacle82J may define an interior sidewall82J-3that extends between an uphole axial end82J-1and a downhole shoulder end82J-2of the receptacle82J. The rod guide body82may define an uphole-facing internal axial shoulder, in this case forming end82J-2of the receptacle82J, which may seat a downhole end, such as downhole axial shoulder end84B, of the ceramic wear sleeve84in the internal valve-rod-receiving cylindrical passage82G-2. Referring toFIGS.2-4, another part of the guide80may abut or retain the uphole end84A of the sleeve84, for example, the rod guide cap86may be mounted to an end of the rod guide body82, for further example uphole cylindrical male threaded end82A of body82, to secure uphole end84A of the ceramic wear sleeve84within the wear sleeve receptacle82J. In the example shown, the rod guide cap86defines a downhole-facing internal axial shoulder86G that secures uphole end84A of the ceramic wear sleeve84. During assembly, the ceramic wear sleeve84may be inserted into the ceramic insert receptacle82J by a suitable manner, such as axially passing the sleeve84through the uphole open axial ends82J-1and82A of body82, and may thereafter be seated upon the uphole-facing axial shoulder end82J-2of the ceramic insert receptacle82J. Referring toFIG.4, the ceramic insert wear sleeve84may be sized so that an exterior cylindrical surface84C of the ceramic wear sleeve84abuts the interior cylindrical sidewall82J-3of the ceramic insert receptacle82J. The wear sleeve84may fit loosely or tightly within the receptacle82J as desired. Referring toFIG.2, the rod guide cap86and body82may collectively define the interior bore80C, which is structured to receive and pass the valve rod50during use.

Referring toFIG.4, the rod guide cap86may have various suitable characteristics. The rod guide cap86may be threaded to an uphole end of the rod guide body82, for example a downhole female box threaded end86B of the rod guide cap86may be threaded to an uphole cylindrical threaded male end82A of the rod guide body82. The threaded male end82A of the rod guide body82may define a neck82D, which may project from an uphole shoulder end82C-1of an axial cap shoulder82C of the body82. The axial cap shoulder82C may define uphole shoulder end82C-1, and a downhole shoulder end82C-2. A diameter82C-3of the axial cap shoulder82C may be larger than a of the diameter82D-1of the neck82D, but commensurate with a maximum outer diameter86K of the cap86. An outer diameter82E-2of a base82E of the guide body82may be wider than diameters82C-3and86K to define annulus17C (FIG.2) and facilitate uphole passage of fluids through. An inner diameter84F of the wear sleeve84may be defined by the interior cylindrical surface84D, which may form an interior bore84E. The inner diameter84F of the interior bore84E may be sized as the minimum internal dimension of the valve guide80, and may be equal to or larger than an outer diameter (not shown) of the valve rod50. In other cases, the cap86and/or body82may define external slots (not shown) to permit axial fluid passage to the annulus17C of tubing17(or well bore). The downhole female box threaded end86B may define a gasket ring slot86H (for fitting of a gasket, not shown), which may facilitate the rod guide cap86to seal to the uphole male threaded end82A of the rod guide body82. When the rod guide cap86is threadedly connected to the rod guide body82, the downhole axial nose shoulder86G of the rod guide cap86may secure an uphole end84A of the ceramic wear sleeve84, as above. Referring toFIGS.2-4and9-11, the rod guide cap86may define a cylindrical collar body86C, and may define an uphole axial shoulder end86A and downhole female box threaded end86B. An interior cylindrical sidewall86C-1of the collar body86C may define an interior bore86L of the cap86. An uphole end of the bore86L may be tapered, for example to form a conical mouth guide86M, to facilitate axial entry of the valve rod50to pass into and through the interior bore86L.

Referring toFIGS.2-4,9and11, the rod guide cap86may be structured for torque transfer from an axial uphole location. The cap86may define a bushing keyway torque slot86E. The bushing keyway torque slot86E may comprise a radial slot along (for example at) the uphole end86A of the rod guide cap86. The radial slot86E may be defined between and by the uphole facing torque ridges86D, which in the example shown are arcuate ridges when viewed in an axial direction along rod guide axis90. Referring toFIG.2, in use, a downhole valve rod bushing52, which may be connected to or form part of the sucker rod connector, may define a key52B-1structured to mate with the bushing keyway torque slot86E for torque transfer therebetween. The valve rod bushing52may be connected (for example as shown) to the sucker rod connector of the valve rod50, such as by threaded connection between an uphole male threaded end50A of the valve rod50to a downhole female threaded box52B of the valve rod bushing52. In use, the key52B-1of the valve rod bushing52may be axially moved downhole relative to the cap86to mate with the keyway slot86E of the rod guide cap86for torque transfer therebetween. The key52B-1may have a suitable structure, for example a central radial ridge as shown, although other mating connections may be used, such as splines, male and female parts, and in some cases, the valve rod bushing52may define a slot and the cap86may define a keyway.

Referring toFIGS.1and2, the valve rod guide80may be used in a production well assembly12. The production well assembly12may comprise a sucker rod string30within a well that penetrates a formation49. A primary mover at a well surface, such as a pumpjack28, may be connected to reciprocate the sucker rod string30. The BHP assembly10may be configured in such a way so that the sucker rod connector, such as the uphole threaded male end50A, of the valve rod50is connected to the sucker rod string30, for example through the use of the valve rod bushing52. In use, the sucker rod string30may be reciprocated using the primary mover to pump well fluids from a fluid inlet72E of the downhole fluid pump48, through the valve rod guide80, and up to the well surface A (FIG.1). Prior to reciprocating, the operator of the well may install the rod guide80, for example by assembling the rod guide80as par of the BHP assembly10. In some cases, assembly is carried out at surface and the BHP assembly10is thereafter passed downhole by assembly and insertion into the well of the sucker rod string30. In other cases, the rod guide80may be installed by passing the various parts downhole along an existing sucker rod string30.

Referring toFIG.2, an example of a downhole pump48is illustrated, incorporating the valve rod guide80. The connections in the example will now be described, although it should be understood that the pump48shown inFIG.2is just an example and other configurations of pumps may be used. The valve rod bushing52of sucker rod string30may define an uphole threaded male end52A, which may connect to a sucker rod female collar30C of or connected to a sucker rod. The downhole female threaded box52B of the valve rod bushing52may connect to the uphole male threaded end50A of the valve rod50. The valve rod bushing52may form a coupling to permit reciprocating action of the sucker rod string30to be transferred to the travelling valve via the valve rod50. As described further below, the valve rod50extends centrally through the pump48to a downhole end50B that threads to an uphole female box end60A of a top plunger coupling60of the pump48.

A downhole female box end82B of the rod guide body82may connect to an uphole male cylindrical threaded end54A of a seating mandrel54. The seating mandrel54may comprise a cylindrical body54C, the body54C defining an exterior sidewall54D and an interior bore54J. The cylindrical body54C may narrow toward a downhole male cylindrical threaded end54B, and may define a seating ring stop ridge54E and a seating ring radial seat neck54F. The stop ridge54E and the seat neck54F may allow for a series of seating cups54G and spacer rings54H to encompasses the seat neck54F of the seating mandrel54. The seating cups54G and the spacer rings54H may be secured in place on the seat neck54F by a lock nut55. The cups54G and rings54H may seal to a downhole end17A of the tubing17, which may secure to the pump48by a suitable mechanism (not shown). An uphole end55A of the lock nut55may abut the most downhole seating cup54G. The lock nut55may comprise a threaded cylindrical body55C, which may be threadedly connected to the downhole male cylindrical threaded end54B of the seating mandrel54.

The downhole male cylindrical threaded end54B of the seating mandrel54may threadedly connect to an uphole female box threaded end56A of a barrel bushing56. The barrel bushing56may connect to the same male threaded end54B as the lock nut55, and may define a cylindrical body56C with an interior bore56D. A downhole cylindrical male threaded end56B of the barrel bushing56may connect to an uphole female box threaded end58A of a barrel58. The barrel58may define a cylindrical body58C, an external sidewall58D, an internal sidewall58E, and an interior bore58F.

The interior bore58F of the barrel58may house the valve and stroke volume of the downhole fluid pump. The downhole fluid pump may comprise a traveling valve assembly63mounted to the valve rod50and a standing valve assembly68mounted to (for example at) a downhole fluid inlet72E. The barrel58may also house a top plunger coupling60and a plunger62. An exterior cylindrical sidewall62E may form the cylindrical body62of the plunger62. The top plunger coupling60may connect to the downhole male threaded end50B of the valve rod50via an uphole female threaded end60A. The plunger coupling60may be connected to an uphole male threaded cylindrical end62A of the plunger62via a downhole female threaded end60B. An interior bore60F of the plunger coupling60may receive downhole fluid from an interior bore62F of the plunger62. The downhole fluid may exit the interior bore60F through a radial port60G of the plunger coupling60into an annulus60H. The annulus60H may be formed between the interior sidewall58E of the barrel58and an exterior surface of the neck portion60C of the top plunger coupling60. A body portion60D of the plunger coupling60may form an exterior cylindrical sidewall60E and the cylindrical sidewall60E may extend to and abut the interior sidewall58E, which may prevent the downhole fluid from back flowing.

A downhole male threaded cylindrical end62B of the plunger62may connect to an uphole female threaded box end64A of a traveling valve cage body64. The traveling valve assembly63may comprise the traveling valve cage body64, a seat plug65, a seat ring66and a ball67. An uphole male threaded end65A of the seat plug65may connect to a downhole female threaded box end64B of the traveling valve cage body64. The traveling valve assembly63may be contained within the barrel58, and an exterior cylindrical sidewall64D of the cylindrical body64may abut the interior sidewall58E of the barrel58. The exterior cylindrical sidewall64D may form the cylindrical body64C of the cage body64. The seat plug65may abut and hold the seat ring66into place, for example, the seat plug65may abut the downhole shoulder end66B of the seat ring66. The seat plug65may press an uphole shoulder end66A seat ring66against the seat plug retainer stop ring64H of the traveling valve cage body64. The seat66C of the seat ring66may be structured to seal against the ball67, to retain the ball67within an interior bore64J of the traveling valve cage body64and prevent back flow during upstroke. The ball67may be retained within the interior bore64J at the uphole end of the interior bore64J through the use of an inverse conical valve retainer64E. The seat plug65may comprise an interior bore65C, which may allow fluid to pass through. The interior bore64J may comprise bypass slots64F, which may allow the downhole fluid to pass around the ball67while the ball67is being retained by the inverse conical valve retainer64E during upstroke, to feed fluid uphole through the pump48.

The standing valve assembly68of the pump assembly10may comprise a standing valve cage body70, a cage bushing72, a seat ring73and a ball74. An uphole cylindrical male threaded end70A of the standing valve cage body70may connect to a downhole female box threaded end58B of the barrel58, and may abut a downhole shoulder end65B of the seat plug65. An uphole cylindrical male threaded end72A of the cage bushing72may connect to a downhole cylindrical male threaded end70B of the standing valve cage body70. An exterior side wall70D may form the cylindrical body70C of the cage body70. The cage bushing72may abut and hold the seat ring73into place, for example, the cage bushing72may abut the downhole shoulder end73B of the seat ring73. An exterior side wall72D may form the cylindrical body72C of the cage bushing72. The cage bushing72may press an uphole shoulder end73A seat ring73against the seat plug retainer stop ring70H of the standing valve cage body70. The seat73C of the seat ring73may be structured to seal against the ball74to retain the ball74within an interior bore70J of the standing valve cage body70to prevent backflow during downstroke. The ball74may be retained within the interior bore70J at the uphole end of the interior bore70J through the use of an inverse conical valve retainer70E. The interior bore70J may comprise bypass slots70F, which may allow the downhole fluid to pass around the ball74while the ball74is being retained by the inverse conical valve retainer70E.

Referring toFIGS.1and2, the sucker rod string30may use the primary mover, for example a pump jack28, to pump well fluids from a fluid inlet, for example the fluid inlet72E, of the downhole fluid pump, through the valve rod guide80, and up to the well surface A. The upward stroke of the pump jack28may draw the downhole fluid into the pump assembly10. The upward stroke of the pump jack28may lift the polished rod34, which via the sucker rod string30and valve rod50may lift the traveling valve assembly63. When the pump jack28performs an upward stroke, the traveling valve assembly63is lifted, causing a drop in pressure in the barrel58. The drop of pressure may cause the traveling valve assembly63to close by forcing the ball67onto the seat66C of the seat ring66, and the standing valve assembly68to open, allowing downhole fluid to enter the pump assembly10through the downhole axial fluid inlet72E, pass through the seat ring73and into the interior bore58F of the barrel58, while also pushing fluids uphole that are located uphole of the travelling valve.

Referring toFIGS.1and2, the downward stroke of the pump jack28may lower the travelling valve in the pump48through a volume of fluid to be lifted thereafter. The downward stroke of the pump jack28may move the polished rod34in a downward direction, causing the traveling valve assembly63to be lowered, which may cause an increase in pressure in the barrel58. The increase of pressure may cause the traveling valve assembly63to open by lifting the ball67off of the seat66C, and the standing valve assembly68to close, by forcing the ball74onto the seat73C of the seat ring73. The downward motion of the traveling valve assembly63causes the valve assembly63to move down through the fluid contained within the barrel58until the pump jack28reaches the bottom of the downstroke. The process may then be repeated and the pump jack28may thereafter begin another upstroke, closing and moving the traveling valve assembly63in the upward direction, causing the traveling valve assembly63to lift the fluid contained within the interior bore58F of the barrel58into the interior bore62F of the plunger62. With each stroke, the fluid may rise from the interior bore62F of the plunger62to the interior bore60F of the top plunger coupling60. The fluid may then move from the interior bore60F through the port60G into the annulus60H. The fluid may be lifted into the interior bore56D of the barrel bushing56, and into the interior bore80C of the valve rod guide80. The fluid may then move through the side ports82F of the rod guide body82into an interior bore38(such as annulus17C of the tubing17) of the casing string16, where the fluid may continue to be lifted until it reaches the surface.

Referring toFIG.2, the valve rod guide80may extend the lifespan of the pump assembly10. In order to connect to the uphole female threaded end60A of the top plunger coupling60, the valve rod50may run through the interior bore80C of the valve rod guide80, the interior bore54J of the seating mandrel54, the interior bore56D of the barrel bushing56and the interior bore58F of the barrel58. The valve rod guide80may extend the lifespan of the pump assembly10by keeping the moving parts of the pump assembly10, such as the valve rod50, the top plunger coupling60, the plunger62and the traveling valve assembly63, in line with a pump axis88. Keeping the moving parts of the pump assembly10in line with the pump axis88and out of rubbing connection with steel stationary parts of the pump48may reduce the wear on the parts by allowing them to move smoothly when in use. The ceramic sleeve84of the valve rod guide80may assist in keeping the valve rod50in line with the pump axis88. The ceramic sleeve84may be able to keep the valve rod50in line with the pump axis88, preventing excess wear on the valve rod50. The ceramic sleeve84may accumulate wear faster than the valve rod50, and once the sleeve84is worn, the sleeve84may be replace with a new ceramic sleeve84in order to continue to keep the valve rod50in line with the pump axis. In some cases, the embodiments may be used in deviated or horizontal applications, where the severity of a dog leg in the well may otherwise cause more wear on the parts, if not centralized. Wear on the side of the valve rod and the side of the guide may otherwise cause a loss of pulling power.

In the claims, the word “comprising” is used in its inclusive sense and does not exclude other elements being present. The indefinite articles “a” and “an” before a claim feature do not exclude more than one of the feature being present. Each one of the individual features described here may be used in one or more embodiments and is not, by virtue only of being described here, to be construed as essential to all embodiments as defined by the claims.