Patent Publication Number: US-10316838-B2

Title: Method and apparatus for preventing gas lock/gas interference in a reciprocating downhole pump

Description:
CROSS-REFERENCE TO RELATED APPLICATION 
     This Application claims priority to U.S. Provisional Patent Application No. 62/210,663, filed Aug. 27, 2015. 
    
    
     FIELD OF TECHNOLOGY 
     The following relates to downhole reciprocating pumps used to pump oil and other fluids from oil wells and, in particular, to a method and apparatus for minimizing or overcoming gas locking and or gas interference. 
     BACKGROUND 
     When an oil well is first drilled and completed, the fluids, such as crude oil, in the wellbore may be under natural pressure sufficient to produce on its own. In other words, the oil rises to the surface without any assistance. In many oil wells however and particularly those having been established for years, natural pressure can decline to a point where the oil must be artificially lifted to the surface. For artificially lifting oil, subsurface pumps are located downhole in the well below the level of the oil. A string of sucker rods extends uphole from the pump to the surface to a pump jack device, or beam pump unit. A prime mover, such as a gasoline or diesel engine, or an electric motor, on the surface causes a pivoted walking beam of a pump jack to rock back and forth, one end connected to a string of sucker rods for moving or reciprocating the string up and down inside of the well tubing. 
     As is known, a string of sucker rods operates the subsurface pump, with the typical pump having a plunger that is reciprocated inside of a pump barrel by the sucker rods. The barrel has a standing one-way valve adjacent a downhole end, while the plunger also has a one-way valve, called a travelling valve. Alternatively, in some pumps the plunger has a standing one-way valve, while the barrel has a traveling one-way valve. Relative movement alternatively charges the pump chamber, between the standing and travelling valves, with a bolus or increment of liquid and then transfers the bolus of liquid uphole. More specifically, reciprocation charges a displacement pump chamber between the valves with fluid and then displaces the fluid out of the chamber to lift the fluid up the tubing towards the surface. The one-way valves open and close according to pressure differentials across the valves. 
     Pumps are generally classified as tubing pumps or insert pumps. A tubing pump includes a pump barrel which is attached to the end joint of the well tubing. The plunger is attached to the end of the rod string and inserted down the well tubing and into the barrel. Tubing pumps are generally used in wells with high fluid volumes. An insert pump has a smaller diameter and is attached to the end of the rod string and run inside of the well tubing to the bottom. The non-reciprocating component is held in place by a hold-down device that seats into a seating nipple installed on the tubing. The hold-down device also provides a fluid seal between the non-reciprocating barrel and the tubing. 
     The hold down device may be assembled to provide for either, or both of, a top hold down configuration or top anchoring of the downhole pump, or a bottom hold down configuration or bottom anchoring of the downhole pump. 
     A top anchored rod pump is generally used in shallower, e.g., 5000 feet or less, sandy, low fluid level, gassy, or foamy wells, and has some benefits to those well known to the pump industry, while the bottom anchored rod pump has benefits in deeper wells. 
     The benefit and disadvantages of both top and bottom anchored pumps would be well known to those familiar with rod pump selection procedures and will not be discussed in further detail here. 
     Volumetric efficiency of a pump is reduced in wells that have gas. The displacement chamber between the standing and traveling one-way valves fails to fill completely with liquid. Instead, the displacement chamber also contains undissolved gas, air or vacuum, which are collectively referred to herein as “gas”. 
     The gas may be undissolved from the liquid (so called “free gas”), or it may be dissolved in the liquid (so called “solution gas”) until subjected to a drop in pressure in an expanding displacement chamber, wherein the gas comes out of solution. Gas takes the place of liquid in the displacement chamber, permitting a compression of the gassy fluid in the chamber and diminishing the displacement and lifting of liquid therefrom. The presence of gas in the displacement chamber reduces the efficiency of the pump, and lifting costs to produce the liquid to the surface are increased. This condition is known as “gas interference”. 
     The presence of too much gas in the displacement chamber can completely eliminate the ability of the pump to lift liquid. This is because the gas in the displacement chamber prevents the contents therein from being compressed to a high pressure sufficient to overcome the hydrostatic pressure above on the traveling valve. This condition is known as “gas locked”, and is a type of gas interference. In other words, the pump can become gas-locked when a quantity of gas becomes trapped between the traveling valve and the standing valve balls. Hydrostatic pressure above the traveling valve ball holds the ball in a seated position, while the pressure from the trapped gas will hold the standing valve ball in a seated position. With the balls unable to unseat, pumping comes to a halt with reduction or cessation of liquid production and other related issues. 
     In common field practice, a common method to break a gas lock in a conventional pump is to adjust the spacing of the pump setting, placing the bottom of the stroke into an interference state during reciprocation, and tap or impact the pump hard on the down stroke. This is done in an effort to jar the travelling valve open so as to break a gas lock. Hitting the pump to open the valves causes damage to pump components and the rod string. The adjustment of the pump requires a service visit and the extent of the tap is not always appreciated at the surface when the impact actually occurs one or more kilometers downhole. Further, rather than have service personnel return multiple times in response to repeated gas locking, a pump might actually be left configured to tap bottom continuously, damaging the sucker rods, rod guides, pump plunger and barrel. 
     Other attempts to solve the gas lock problem have concentrated on the valves, and the compression of a gas in the displacement chamber. One typical attempt is to remove the oil pump or the plunger from the barrel, and release the trapped gas. This can be time-consuming and interrupts pumping operations. 
     Operating the pump in a gas locked condition is undesirable because energy is wasted in that the pump is reciprocated but no fluid is lifted. The pump, sucker rod string, surface pumping unit, gear boxes and beam bearings can experience mechanical damage due to the downhole pump plunger hitting the liquid-gas interface in the displacement chamber on the down stroke. Loss of liquid lift leads to rapid wear on pump components, as well as stuffing box seals. This is because these components are designed to be lubricated and cooled by the well liquid. 
     Gas locking, and implementation of the above-mentioned solution for overcoming same, not only damages the pump and stuffing box, but can reduce the overall productivity of the well. Producing gas without the liquid component removes the gas from the well. The gas is needed to drive the liquid from the formation into the well bore. 
     Still another problem arises in the Texas Panhandle of the United States, where some oil fields have a minimum gas-to-oil ratio production requirement. In other words, both gas and oil must be produced. Many gas wells are unable to produce gas at their full potential because the downhole pumps are unable to lift the liquid, as the pumps are essentially gas locked. 
     Still another problem arises in stripper wells, which are wells that produce ten barrels or less of liquid each day. Stripper wells are low volume wells. The output from a stripper well is produced into a stock tank on the surface. Separation equipment, which separates the gas from the well, is not used because the production volume is too low to justify the expense of separation equipment. Produced gas is vented off of the stock tank into the atmosphere, contributing to air pollution and a waste of natural gas. 
     Still another problem arises in wells with little or no “rat hole”. The rat hole is the distance between the deepest oil, gas and/or water producing zones and the plugged back, or deepest depth of the well bore. Conventional downhole pumps cannot pump these wells to their full potential due to the low working submergence of the pump in the fluid. The low submergence results in both liquid and gas being sucked into the displacement chamber. If insufficient volumes of liquid are drawn into the chamber, the pump becomes gas locked. In low volume wells, the common practice is to shut the pump off for a period of time to allow sufficient liquid to enter the well bore. But, in wells with little or no rat hole, shutting the pump off has no effect because the liquid level is too low. Deepening the well bore is typically too expensive. While these wells do contain oil, it cannot be produced with known pumps. 
     There are also many wells which produce fluids having a high gas content. The pumping efficiency of conventional pumps, as hereinabove discussed, is considerably reduced, and pumping action can be completely blocked. While a liquid is substantially incompressible, hydraulically opening the check valves during the reciprocating pump stroke, a gas is compressible. Thus, gas located between the traveling check valve and the standing check valve can merely compress during the down stroke without generating sufficient pressure to open the traveling valve. No liquid is then admitted above the valve to be lifted during the up stroke and the pump is gas locked. This problem is aggravated in large bore pumps, where considerably more internal volume in the displacement chamber is available for gas accumulation, with concomitant low pressurization during compression. 
     In the past, it has been suggested to remedy such gas locking condition by preventing gas from reaching the pump. One way this was accomplished was by using an annulus below the pump inlet. However, in order to implement such a remedy, accurate data is required about the generally unknown formation characteristics. Furthermore, the fluid reservoir characteristics of such formations change with time, requiring constant adjustments to the pump installations. As such, the annulus method of preventing gas from reaching the pump is neither practical nor effective. 
     Such failures to completely fill the chamber are attributed to various causes. In a gas lock situation or a gas interference situation, the formation produces gas in addition to liquid. The gas collects at the top of the chamber, while the liquid is at the bottom, creating a liquid-to-gas interface. If this interface is relatively high in the chamber, then gas interference results. In gas interference, the plunger, on down strokes, descends in the chamber and hits the liquid-to-gas interface. The change in resistances causes a mechanical shock or jarring. Such a shock damages the pump, the sucker rods and the tubing. If the liquid-to-gas interface is relatively low in the chamber, gas lock results, wherein insufficient pressure is built up inside of the chamber on the down stroke to open the plunger valve. The plunger is thus not charged with liquid and the pump is unable to lift anything. A gas locked pump, and its associated sucker rods and tubing, may experience damage from the plunger hitting the interface. 
     In a pump off situation, the annulus surrounding the tubing down at the pump has a low fluid level, and consequently a low fluid head is exerted on the barrel intake valve. In an ideal pumping situation, when the plunger is on the upstroke, the annulus head pressure forces annulus fluid into the chamber. However, with a pump off condition, the low head pressure is unable to force enough fluid to open the valve and completely fill the chamber. Consequently, the chamber has gas, air or a vacuum therein. A pump in a pump off condition, as well as its associated equipment, suffers mechanical shock and jarring as the plunger passes through the liquid-to gas interface. A restricted intake can also cause pump off. 
     There is therefore a need for apparatus and methodologies that can effectively address gas lock/gas-interference in downhole reciprocating pumps. 
     Further to the foregoing, pump valves are designed for hostile environments, as they are subject to high pressures, high temperatures and corrosive fluids. The valves include a valve seat and a ball. The valve seat is a ring having a lapped, or shaped, surface for receiving the ball. When the ball engages the seat, the valve is closed. When the ball is disengaged from the seat, the valve is opened. Differential pressure moves the ball into or out of engagement with the seat. 
     For example, traveling valve assemblies are designed to allow the fluid that has entered the pump on the previous upstroke to pass through it with minimal pressure differential created during the down-stroke cycle of the pump. This is because, as the pressure differential increases, weight from the sucker rods directly above the pump is required to force the liquid through the plunger, and too much weight will cause them to buckle slightly and to come into contact with the inside of the tubing string, causing wear on the tubing string and on the sucker rods. It is therefore desirable to lower the force required to move the plunger through the fluid, not only to increase pumping rate and overall system efficiency, but to reduce wear. 
     An improperly guided ball in either valve will have difficulty seating, resulting in improper closure and leaking through the valve. Ball cages are used to constrain the movement of the ball and ensure a properly working valve, and are well-known in the art. The cage limits the movement of the ball axially along a narrow path and/or prevents the ball from oscillating and causing excessive wear. The tolerance between the ball and the inside side walls of the cage is small in order to minimize side-to-side movement of the ball. In addition, the cage provides openings around the ball for fluid to flow. See for example U.S. Pat. No. 6,830,441 to Williams. 
     Some wells produce relatively large quantities of sand. As the sand flows through the valve, it tends to accumulate and cause a loss in efficiency in pumping fluid to the surface, for example by choking off fluid flow, or by interfering with the ability of the ball to reseat and seal the valve, to release from the valve seat or to find the valve seat. 
     The ball and seat components used in both the traveling valve and the standing valve are exposed to excessive wear as a result of a number of factors, including the turbulent flow of fluids at high pressures. The turbulence leads to uncontrolled movement of the ball in the valve cage, or rattling side-to-side, eventually causing damage to both the ball and valve cage. Several attempts have been made to minimize rattling within ball check valves. See for example U.S. Pat. No. 6,899,127 to Swingley which describes methods that are relatively effective in minimizing rattle, but that also increase friction and therefore result in a decrease in the kinetic energy of the liquid flowing through the valve and an increase the pressure drop across the valve with all the disadvantages associated therewith. 
     Eventually, pump components need to be replaced as a result of being exposed to excessive wear and damage. In the past, valve cages have been equipped with hardened liners, in order to increase valve cage life. However, hardened liners can be expensive. 
     Valve cages commonly comprise guides, which may be formed either of hard metal or of elastomer pieces fixed within the cage. While elastomers are useful for wear aspects, they are not usually structural per se. Elastomer guides are difficult to assemble in the structural aspect of the cage and in lock in place. Unless pins or clips are used as locking means, it has been necessary to distort the guide pieces to insert or remove them. 
     There remains a need in the art for a pump valve that minimizes sand accumulation in the valve, that maximizes the flow capacity of the fluid of the cage, minimizing pressure drop across the valve, that minimizes the effects of travelling ball movement without causing additional friction, that maximizes the suspension time of solids within the fluids, which enhances flow capability of the fluid through the cage and through the tubing string, that further reduces or eliminates wear, avoids using guides, and that maximizes efficiency or operational capacity of the pump. 
     SUMMARY 
     An aspect relates to an apparatus and methodologies for reducing gas interference in a downhole pump. More specifically, the present apparatus and methodologies may reduce or eliminate gas lock in a reciprocating pump positioned within a subterranean wellbore. 
     In one embodiment, the present apparatus for reducing gas interference is provided in a pump, the pump comprising at least one standing valve, at least one traveling valve, a cylindrical barrel positioned therebetween, and at least one reciprocating piston operative to open and close the valves. The present apparatus may comprise at least one cylindrical bushing forming a fluid bore, the bushing having an uphole and a downhole end, the downhole end being in fluid communication with at least one downhole standing valve for receiving fluids drawn from the wellbore into the bore, and the uphole end being in fluid communication with at least one uphole standing valve for transporting fluids within the bore to the cylindrical barrel, the bushing having at least one fluid port, extending through the wall of the bushing, for directing fluids from the annulus of the wellbore into the fluid bore wherein fluids from the annulus increase the hydrostatic pressure of the fluids within the bore to reduce gas interference therein, enabling opening and closing of the traveling valve upon reciprocation of the piston. 
     In another embodiment, the present methodologies for reducing gas interference in a reciprocating pump comprises sealingly positioning the pump within the annulus of a subterranean wellbore, the pump comprising at least one traveling valve, at least two standing valves and a cylindrical bushing positioned therebetween and in fluid communication therewith, a cylindrical barrel and at least one reciprocating piston operative to open and close the valves, injecting fluids into the annulus of the wellbore, operating the pump by reciprocally moving the piston upwardly, opening the at least one standing valve downhole of the bushing, drawing fluids from the reservoir into the bushing, opening the at least one standing valve uphole of the bushing, drawing fluids from the bushing into the cylindrical barrel, and receiving injected fluids from the annulus into the bushing, increasing the hydrostatic pressure therein, and moving the piston downwardly, opening the at least one traveling valve, increasing pressures within the bushing, and pumping the reservoir fluids uphole through the barrel. 
     In another embodiment, the present apparatus comprises a modified valve for use in a reciprocating pump for recovering reservoir fluids from a subterranean wellbore, the pump having at least one standing valve, at least one traveling valve, a cylindrical barrel positioned therebetween, and at least one reciprocating piston operative to open and close the valves, the at least one traveling or standing valve being modified to comprise a cylindrical housing, a tubular insert, releasably positioned within the housing, the insert having a fluid inlet end, a fluid outlet end, and a sidewall, the inlet end forming a valve ball stop and the sidewall forming at least one fluid port therethrough, a valve ball, and a valve seat, releasably positioned within the housing, wherein ball is sealingly received by the ball stop to plug the inlet end of the insert, creating a vacuum thereabove, and drawing fluids through the at least one fluid ports into the insert, and wherein ball is sealingly received by the valve seat to close the valve. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Some of the embodiments will be described in detail, with reference to the following figures, wherein like designations denote like members, wherein: 
         FIG. 1A  is an illustration in cross section of a related art gas-lock breaking bushing (showing the pump in the upstroke); 
         FIG. 1B  is an illustration in cross section of the related art bushing shown in  FIG. 1A  (showing the pump on the down stroke); 
         FIG. 2  is an illustration in cross section of the present apparatus according to embodiments herein showing the pump on the upstroke; 
         FIG. 3  is an illustration in cross section of the present apparatus shown in  FIG. 2  showing the pump on the down stroke; 
         FIG. 4  is an illustration in cross section of the present apparatus shown in  FIGS. 2 and 3  showing the pump on the subsequent upstroke; 
         FIG. 5A  is an illustration in cross section of the present apparatus; 
         FIG. 5B  is an illustration in side view of the present apparatus; 
         FIGS. 5C, 5D and 5E  are illustrations in side cross-sectional view of the present apparatus showing the present bushing port ( 5 C), an enhanced view thereof ( 5 D), and a perspective view ( 5 E); 
         FIG. 5F  is a perspective view of the present apparatus and port; 
         FIG. 6  is a perspective cross-sectional view of a pump valve according to embodiments herein (showing the ball seated in the valve seat); 
         FIG. 7  is a cross-sectional side view of the valve shown in  FIG. 6 ; 
         FIG. 8  is a perspective cross-sectional view of the pump valve according to  FIG. 6  further comprising a vortex initiator, and showing the ball positioned in the ball stop; 
         FIG. 9  is a cross-sectional side view of the valve shown in  FIG. 8 ; 
         FIG. 10  is a top view of the vortex initiator shown in  FIGS. 8 and 9 ; 
         FIG. 11  is a cross-sectional perspective view of a pump valve according to embodiments herein, the valve being used in combination with a ported rod connector; 
         FIG. 12  is a cross-sectional perspective view of the rod connector, according to a first embodiment, as shown in  FIG. 11 ; and 
         FIG. 13  is a perspective side view of the rod connector according to a second embodiment. 
     
    
    
     DESCRIPTION 
     According to embodiments herein, the present apparatus and methodologies may be may be operative for reducing or preventing gas locking/interference, enabling rapid resumption of liquid production, improving pump efficiency, and increasing production. System and pump maintenance may also be reduced through the elimination of damaging techniques such as ‘tapping bottom’ including, for example, the mitigation of damage to valve balls, cages and seats, and premature stuffing box failure. Rod life may be increased through the reduction in ‘rod slap’. 
     According to further embodiments, the present apparatus and methodologies provides a pump valve that may be suitable for use as a standing valve, a travelling valve, or as a replacement for a three-wing case/spiral guide combination typically used at the top end of a hollow pull tube on hollow valve rod pumps. It is an advantage of the present technology that, when used as a standing valve, the present apparatus may also be used in combination with a vortex initiator. 
     By way of background, the present technology may be operative for use with reciprocating pump assemblies positioned within a standard wellbore. Having regard to  FIGS. 1A and 1B  (RELATED ART), reciprocating pump assemblies, such as a bottom hold-down pump  100 , are commonly installed in conventional oil wells and comprise a standing one-way check valve  110 , positioned on the bottom of a string of tubing pipe  120  in the liquid fluid near the bottom of the well, a traveling plunger or piston  130  in a hollow cylindrical barrel  140  just over the standing valve  110  with a traveling one-way check valve  150  in the piston  130 , a sucker rod or pump rod extending from the piston to the wellhead on the surface, and an actuator (e.g. pump jack) connected to the rod for reciprocating the piston  130  and traveling valve  150 . 
       FIG. 1A  shows the conventional pump assembly in the upstroke, while  FIG. 1B  shows the same assembly in the down stroke. As would be understood, in operation, the bottom hold-down pump  100  operates by, during the upstroke, drawing or sucking fluid (F, arrows) through the standing valve  110  into the barrel  140 . Then, on the down stroke, the piston  130  travels downwardly and the standing valve  110  closes to prevent fluid F in the barrel  140  from being pushed by the piston  130  back into the well. At the same time, the traveling valve  150  opens to allow the fluid F in the barrel  140  (above the standing valve  110 ) to flow through the piston  130  to a position in the barrel  140  above the piston  130 . On the next upstroke, as the standing valve  110  is opened again, more fluid F is drawn into the barrel  140  under the piston  130 , the traveling valve  150  in the piston  130  is closed to prevent the fluid F above the piston  130  from flowing back through the piston  130 . In this manner, each successive stroke cycle of the piston  130  draws more fluid F from the reservoir to first position below the piston, and then to a position above the piston, eventually pumping the fluid F to the surface. 
     As described, many reservoirs produce excessive compressible fluids, such as gas, along with the non-compressible fluids (e.g. oil/water), which can cause problems for the pump  100 . Such problems are commonly referred to as ‘gas lock’, or ‘gas interference’, and result from the gas G being drawn through the standing valve  110  into the barrel  140  on the upstroke. However, on the down stroke, when the standing valve  110  is closed, the non-compressible liquid is normally expected to force the traveling valve  150  open, gas G in the barrel  140  between the traveling valve  150  and the standing valve  110  will compress, allowing the hydrostatic head of the fluid above the traveling valve  150  from opening. On the upstroke, the gassy liquid caught above the standing valve  110  prevents any more fluid F from being drawn into the barrel  140  because the gassy liquid merely expands to fill the space in the barrel  140 . As a result, the reciprocating pump strokes simply continue to alternate, compressing and expanding the gassy liquid trapped in the barrel  140 , without pumping any liquid. 
     One attempt to address such gas-interference has been to incorporate a gas-lock breaker bushing  160 . For example, the bushing  160  may be positioned within the barrel  140 , between the traveling valve  150  and the standing valve  110 . The bushing  160  may provide a gas-bleed port  161  through its side wall and may be operative to enable a controlled leak from the port. As such, during the down stroke, the movement of the piston  130  compresses the gas and forces it to bleed from the bushing  160 . Gas continues to bleed until only fluid F remains, the traveling valve  150  then opens again to continue pumping the fluid F to the surface. 
     While known mechanisms for breaking gas-lock/gas-interference may be successful, such mechanisms suffer from numerous drawbacks (including as described above). For instance, gas G, with some entrained fluid F and even some solids, exit from the bushing  160  with high velocity, jetting against adjacent tubing causing damage to the tubing  120 . Further, it is often the case that such bushings  160  cannot be removed or interchangeable, resulting in the system being restricted to its 0.032 inch opening, and being subjected to plugging of the bushing port by well debris. 
     Having regard to  FIGS. 2-4 , the present apparatus and methodologies comprise may be utilized with a conventional downhole reciprocating pump, as described. For example, pump may comprise at least one standing valve  10 , traveling piston  13  within cylindrical barrel  14 , and at least one traveling one-way valve  15 . The present apparatus may comprise a modified gas-lock reduction apparatus  20  and method of using same. Apparatus  20  may comprise a machined cylindrical bushing having a downhole inlet end  22  and an uphole outlet end  24 , forming a bore  23  therebetween. Downhole end  22  may be configured for connection with the at least one standing valve  10   a  there below, such as, for example, by comprising a female threaded connection. Uphole end  24  may be configured for connection with the at least one second, otherwise standard, standing valve  10   b , such as, for example, by comprising a male threaded connection. The entire apparatus  20  may be configured for positioning within a seating device installed in standard tubing  12 . 
     As will be described in more detail below, the positioning of the present apparatus  20  between uphole and downhole standing valves  10   b , 10   a  enables controlled fluid communication between the annular space A (formed between the apparatus  20  and the tubing  12 ) and the bore  23 , and between the bore  23  and the barrel  14 . More specifically, the present apparatus  20  provides controlled ‘leaking’ of fluids from the annular space A into the bore  23  between the valves  10   a , 10   b , the leaked fluid operative to reduce gas interference within the barrel  14 . That is—large amounts of fluids injected into the substantial annular space A from the surface fill the space and give rise to significant hydrostatic pressure outside of the present apparatus  20 , compared to the pressures within the apparatus  20 , particularly in deeper wells. Controlled fluid flow from the annular space A into the apparatus  20  enables the fluids within the apparatus  20  to be subjected to the same hydrostatic pressures as fluids in the annulus A, ultimately reducing gas interference or gas lock therein. As such, it is an advantage of the present configuration that the bottom hold-down assembly sealing secures the present apparatus  20  within the tubing  12 , sealing closing annular space A formed there between, preventing the pumped fluids F delivered to the annular space A from flowing back into the pump intake again. The bottom hold-down assembly further prevents any reciprocation motion of the barrel  14 . 
     Bushing  20  may further comprise at least one vent or port  25  for providing fluid communication (e.g. forming fluid pathways) from bore  23  to the exterior of the bushing  20 . In some embodiments, bushing  20  may comprise at least one port  25 . In other embodiments, bushing  20  may comprise at least two ports  25 , the ports  25  being diametrically opposed from one another. In other embodiments, bushing  20  may comprise a plurality of ports  25 , the ports  25  being radially spaced around the circumference of the bushing  20 . 
     Having regard to  FIGS. 5A-5F , ports  25  may be machined such as to be directed at an angle from the longitudinal axis of the wellbore (and pump  100 ). For example, ports  25  may be angled at least between 10-80° from the axial plane of bore  23 . That is—ports  25  may be provide at an angle of at least 10° and less than 80°, and preferably at an angle of approximately 45° from the longitudinal axis of bore  23  (α,  FIG. 5D ). In some embodiments, ports  25  may be oriented at a direction generally outward from bore  23 , and generally downhole and/or uphole from bushing  20 . In some other embodiments, ports  25  may be oriented at a direction generally perpendicular to the longitudinal axis of the pump, or bore  23 . 
     Having further regard to  FIGS. 5A-5F , according to embodiments herein, ports  25  may be configured such that the internal diameter of the port may be adjusted. For example, ports  25  may be configured to receive a tubular insert, such as a carbide insert, enabling the size of the port  25  to be increased or decreased with the insertion or removal of the insert. Inserts may be readily available for use in different port  25  sizes, e.g. from the standard 0.032 inch opening to a customized size for a particular field requirement. Different port  25  sizes may be required depending upon the depth of the well and pump bore sizes. Use of replaceable carbide inserts in ports  25  allows for easy removal, maintenance, or replacement of inserts, rather than having to replace the entire bushing  20 , reducing repair costs. Although it is an advantage of the present apparatus  20  that the size of the apparatus  20  may be adapted to all sizes of production tubing, such as between being 2⅜″, 2⅞″, and 3½″, and that the internal diameter of the ports  25  therein may also be adapted (as described), a skilled person would appreciate that the apparatus  20  may have non-replaceable components, or integrated ports  25  without affecting the gas interference reduction functionality. 
     According to embodiments herein, as shown in  FIG. 2 , the internal volume of barrel  14  is divided by traveling valve  15  into an upper barrel chamber  16  above the traveling valve  15 , and a lower barrel chamber  18 , below the traveling valve  15 . Upper and lower chambers  16 , 18  are in controllable fluid communication with each other through traveling valve  15 , where lower chamber  18  operates as a displacement chamber. Bore  23 , between standing  10   a , 10   b , forms an additional chamber. As such, the flow of fluids F from the reservoir into bore  23  is controlled by downhole standing valve  10   a , while the flow of fluids F from bore  23  into displacement chamber  18  is controlled by uphole standing valve  10   b . Fluid flowing down annulus A is received by at least one ports  25  of bushing  20 . 
     Generally, in operation, on the upstroke ( FIG. 2 ), piston  13  moves upwardly (e.g. travels uphole), decreasing the pressure in the lower chamber  18  of the barrel. If there is little or no gas G in the lower chamber  18 , then the pressure therein is decreased sufficiently to actuate the traveling valve  15 , closing the valve, due to the higher hydrostatic pressure of the fluids in the upper chamber  16 . Both standing valves,  10   a , 10   b , open due to the low pressure formed in the lower chamber  18  (opens valve  10   b ) and the higher pressure in the reservoir applied from downhole (opens  10   a ). Opening of both standing valves  10   a , 10   b , draws reservoir fluids F (arrows) into the barrel  14 . In addition, bore  23  receives ‘leaking’ fluid from the annular space A, via ports  25 , for transport to barrel  14 . The hydrostatic pressure of the leaked fluid from the annular space A acts upon the uphole standing valve  10   b , assisting to force the ball off the seat, opening the valve and filling lower chamber  18  of the barrel  14 . As such, during the upstroke, free gas G may enter the displacement chamber, or solution gas may break out of the fluids F in displacement chamber  18  due to the pressure decrease therein. 
     On the subsequent down stroke ( FIG. 3 ), piston  13  moves downwardly (e.g. travels downhole). The gas G in the displacement chamber  18  is compressed, resulting the traveling valve  15  remaining closed due to the higher hydrostatic pressure of the fluids F in the upper chamber  16 . With the compression of gas G in the lower chamber  18 , the pressure therein increases. At the bottom of the down stroke, the hydrostatic pressure in the upper chamber  16  above the traveling valve  15  becomes the same as that in the annular space A. 
     As shown in  FIG. 4 , on the subsequent upstroke, piston  13  travels uphole, decreasing the pressure in the lower chamber  18 . In a conventional pump, as gas in the lower chamber  18  expands, the pressure decrease in the lower barrel  18  is smaller than that when no gas G is in the lower barrel  18 , thus tending to be insufficient to permit the uphole standing valve  10   b  to open. However, when the present apparatus  20  is installed, two upward forces are applied at the uphole standing valve  10   b  to open same. A first upward force is from the pressure that already exists in the bore  23  from the reservoir through the downhole standing valve  10   a , which is applied to the downhole side of the uphole standing valve  10   b . While the first upward force itself may not be sufficient to open the upper valve  10   b , a second upward force from the hydrostatic pressure of the liquid injected from the surface into the annular space A is also applied to the downhole side of the uphole valve  10   b . This second pressure is applied via fluid flowing from the annular space A through ports  25  into bore  23 . Specifically, the hydrostatic pressure of the liquid in the annular area A exerts pressure, causing a small increment of liquid to enter ports  25  into bore  23 . As the piston  13  travels uphole, the pressure in the displacement chamber  18  further decreases to a point when the first and second forces overcome the pressure above the upper standing valve  10   b , opening the valve  10   b . Then, fluid in the bore  23  between the two standing valves  10   a , 10   b , as well as a squirt of liquid from the annular space A through ports  25 , enters the lower displacement chamber  18 . 
     With the introduction of liquid from the annular space A into lower chamber  18 , the lower chamber  18  may then have sufficient incompressible fluids F therein such that, on the next down stroke, the traveling valve  16  is opened. Alternatively, if the lower chamber  18  does not have sufficient incompressible fluids F therein after an upstroke, then the introduction of incremental liquid from the annular space A into the lower chamber  18  continues on subsequent upstrokes until, eventually, after several reciprocations, the fluids F in the lower chamber  18  accumulates to a sufficient amount to open the traveling valve  15  on a down stroke. Further, on the down stroke, the uphole standing valve  10   b  closes and prevents a sustained jetting of fluid F through ports  25  (with the exception of an extremely small volume that is enough to flush said ports  25 , prior to the closing of the uphole standing valve  10   b , but is not enough to cause erosive damage to the tubing  12 ). When the traveling valve  15  opens, and fluids F in the bore  23  and lower chamber  18  are pumped uphole, decreasing the pressure in the bore  23  to lower than that of the reservoir, causing, on the next upstroke, the downhole standing valve  10   b  to open and draw more fluids F from the reservoir. It would be understood that the present apparatus and methodologies serve to overcome gas interference (or gas lock) conditions in the pump. 
     According to embodiments herein, it is an advantage of the present apparatus  20  that the uphole standing valve  10   b  may open on every upstroke, thus continually introducing fluids F into the pump. Moreover, the present apparatus  20  restricts the flow of liquid from the annular space A into bore  23 , preventing the discharge of fluids F into the annular A (with the exception of a minute volume to flush ports  25 ). 
     It would be understood that the present apparatus  20  may be a separate component from the standing valves  10   a , 10   b . Alternatively, it would be understood that, rather than separate components, the present apparatus  20  may be manufactured integral to the uphole standing valve  10   b , for coupling between the traveling valve  15  and a conventional standing valve therebelow, or integral to the downhole standing valve  10   a , for coupling below a conventional standing valve thereabove. In one embodiment, the present apparatus  20  may be manufactured to be integral with, and sandwiched between, two standing valves  10   a , 10   b , and manufactured as a single apparatus for replaces a conventional standing valve. 
     According to embodiments herein, as shown in  FIGS. 6 and 7 , the present apparatus may be configured to comprise valve  30  having housing  32 , tubular insert  34 , a conventional valve ball  36  and seat  38 . Valve components may be composed of any appropriate materials, such as stainless steel, and alloy or some other material capable of withstanding the conditions present in typical oil well environments, and may be coated, for example nickel spray coated. 
     In some embodiments, valve  30  may be used as a traveling valve, such as traveling valve  15  described herein. In such a case, valve  30  may comprise inlet  40 , outlet  42 , and bore  44  there between. Valve seat  38  is carried by housing  32  at or near inlet  40 , while insert  34  is carried by housing  32  at or near outlet  42 . Valve ball  36  may be disposed between seat  38  and insert  34 . It would be understood that any appropriate connection means for connecting seat  38  and insert  34  to housing  32 , such as threaded connections, are contemplated. Further, it would be understood that any appropriate connection means for connecting valve housing  32  to a pump plunger or piston, such as piston  13 , thereabove, and components therebelow, such as bushing  20 , are contemplated. Further, and in contradistinction with known cage-type ball valve structures, ball  36  is not constrained radially by restrictive structure and instead is axially movable through a large cross-sectional flow area within housing  32 . 
     As is shown in  FIG. 7 , at its downhole end, insert  34  may form ball stop  45 , correspondingly sized to receive ball  36  therein. In one embodiment, stop  45  comprises edges, the edges being concave or otherwise inwardly angled for guiding ball  36  into the centre of the stop  45 , blocking the inlet of the bore formed within tubular insert  34  (i.e. effectively plugging the inlet). In some embodiments, stop  45  may comprise a hemi-spherical socket configuration that is adapted to correspond to the size and shape of the ball  36 , holding the ball  36  therein. More specifically, stop  45  may accommodate the exact circumferential dimension of the ball  36 . Stop  45  may further be configured to provide one or more ball guides (not shown), radially spaced around the internal surface of stop  45 , for further securing ball within stop  45 . Guides may or may not be configured to further create a vortex of fluid around the ball  36 . Stop  45  may be fitted with a welded and finished/polished inlay of Stellite, or some other such hardening or treatment. 
     As is further shown in  FIG. 7 , at its uphole end, insert  34  may form flange  46 , for abutting inner shoulder  47  of housing  32 . It should be appreciated that inner threads within housing  32  may be threadingly engaged with piston  13 , said piston  13  serving to secure tubular insert  34  in position. Such threading engagement of the piston  13 , valve  30  and valve components, such as insert  34 , enable the valve  30  to be removed and repaired, or replaced as necessary. Tubular insert  34  may form at least one port radially spaced about the circumference of the insert  34 , and preferably may form at least three ports  35 . Each port  35  may or may not have the same diameter. 
     Valve seat  38  may be positioned within housing  32 , and may be a conventional rod pump valve seat. As shown in  FIGS. 6 and 7 , seat  38  may be inserted into housing  32  such that it abuts inner shoulder  39  of housing  32 . Seat  38  may be manufactured from tungsten carbide, or some other material capable of withstanding oil well environments. Inner threads on housing  32  may be used to threadably engage housing with a conventional seat plug (not shown), the plug being operative to hold the seat  38  in place in the bore of the housing  32 . 
     Valve ball  36  may be a conventional ball, although smaller than those used in conventional pump valves, and would be well known in the industry. For instance, use of smaller valve balls provides more clearance and a greater flow area through the valve, where use of a smaller ball in a known valve or cage could lead to premature wear due to turbulent flow resulting from the larger flow area, leading to uncontrolled movement of the ball in the valve cage, or rattling. 
     When valve  30  is used as a traveling valve, such as valve  15 , and the piston  13  begins into the down stroke, ball  36  responds to a decrease in pressure within the housing  32  (relative to valve inlet  40 ) and moves towards ball stop  45 . As a result, fluids (F, arrows) travel into the valve inlet  40 , around the ball  36 , and into the bore  44  of housing  32 , that is—into the annular area formed between the inside of the valve housing  32  and the outside of the ported insert  34 . Fluids F then flow into the bore of the insert  34 , via ports  35 , and out of the uphole end of the insert  34  into the barrel  14 . 
     During this time, valve ball  36  is received and held within the ball stop  45 . Ball  36  is actuated into this position because present valve design creates flow dynamics that generate a vacuum above the ball  36  in the bore of the insert  34 , aiding to keep the ball  36  in its unseated position and preventing uncontrolled movement thereof. As the ball  36  is held in position against the ball stop  45 , fluid F passes freely and around the ball  36  with ease. 
     While the ball  36  is lifted and held in position against ball stop  45 , any violent action of the ball  36  or ‘ball rattling’ is eliminated, thereby obviating a need for a hard liner or longitudinally extending ribs, or races to be included in the valve cage, unlike typical known valve cages. Such a configuration further prevents premature damage to the seat  38 , and premature valve leakage as a result of uncontrolled up and down movement of the ball  36 , as may be the case with standard API valves. The flow dynamics about the periphery of the ball  36  and the axial spacing of the ball stop  45  from the valve seat  38  may further be configured to minimize ball rattle. 
     On the upstroke, fluid flow and gravity acts on ball  36 , increasing pressure above the valve  30  and causing ball  36  to drop from stop  45 . The ball  36  drops axially or straight down from the stop  45 , falling onto seat  38  therebelow and blocking reverse flow of fluid through the valve  30 . 
     As would be known, known hard-lined ball cages with their ribbed structure and their close tolerances between the inside of the cage and the outside of the ball (e.g., see U.S. Pat. No. 6,830,441) can lead to solids eventually wedging themselves against the ball, thereby preventing the ball from reseating. It is an advantage of the present technology that valve  30  eliminates the use of cages or longitudinally extending ribs, significantly increasing the clearance between the ball  36  and the closest adjacent surface (the radially-spaced inside of the housing). With this larger clearance, solids are less likely to become lodged, to accumulate around the ball  36 , or to be stacking up during pumping operations and reducing the efficiency of the pump. 
     Known attempts to minimize ball rattling by reducing the clearance between the ball and the valve body (e.g., see U.S. Pat. No. 6,899,127) increases friction between the fluid, the valve ball and the valve body, thereby dissipating the kinetic energy of the flowing fluid and increasing the pressure drop across the valve. It is an advantage of the present technology that valve  30  provides a shorter distance between valve seat  38  and ball stop  45 , without sacrificing flow area and the problems associated therewith. Thus, valve  30  can have a flow area that is sufficiently large that there is little or no reduction in kinetic energy or a resulting increase in pressure drop. Valve  30  may further be capable of creating faster seating of the ball  36  within the seat  45  on the up-stroke, reducing pump stroke loss and providing for more efficient pumping. 
     Having regard to  FIGS. 8 and 9 , when the valve  30  is used as a standing valve, such as valve  10 , a vortex initiator  50  may also be used. In some embodiments, the use of initiator  50  may be preferred when valve  30  is used as a standing valve. In such a case, the upper part of housing  32  may be modified to provide outer threads, for threadably engaging housing  32  with barrel  14 , while inner housing threads at the downhole end of housing  32  may be used to threadably engage housing to a hold-down seal assembly and/or a conventional seat plug (not shown) to hold the valve seat  38  in place. 
     Vortex initiator  50  may be positioned within housing  32  at or above insert  34 . Lock nut  51  may then be positioned (e.g. threaded) in housing  32  to hold the vortex initiator  50  and insert  34  in place in bore  44 . Vortex initiator  50  may comprise a tubular structure having a top end and a bottom end, and a flow passage there between. As shown in  FIG. 10 , the vortex initiator comprises a circular housing  52 , central bore  54 , forming a flow passage, and inwardly extending flanges  56 . Flanges  56  each comprise two surfaces  57  that are helically directed, creating a vortex in the fluid F as it flows through bore  54 . 
     According to embodiments herein, vortex initiator  50  may enhance fluid F flow by causing the fluid to move faster. This is achieved because the fluid F enters into a spin as it exits the vortex  50 , resulting in better pump fillage. That is—the radial design of the vortex initiator  50  allows for faster fluid passage with greater flow capacity, forcing solids within the fluid F away from valve seat  38 . As a result, the ball seats with less interference from debris which results in a longer run life for the valve ball  36  and valve seat  38 . 
     When used as a standing valve, as the piston  13  begins into the down stroke, ball  36  moves towards valve seat  38  in response to an increase in pressure above the valve ball  36 . The flow of fluid through the valve is blocked. On the subsequent upstroke, the ball  36  moves directly towards ball stop  45  at the bottom of the insert  34 , in response to a decrease in pressure within housing  32  relative to pressure at the valve inlet  40 . Fluid F travels into the valve inlet  40  from the reservoir, around the ball  36 , and into the annular area  44 , as described above. Fluid then flows into insert  34 , via ports  35 , and then out of the insert  34  through the vortex initiator  50  and into the barrel  14 . 
     Having regard to  FIGS. 11 and 12 , when the valve  30  is in conjunction with a top-ported rod connector, a ported rod connector  60  may be used. The valve  30  and rod connector  60  may be used as replacement for a top three-wing cage/spiral guide combination, commonly used on hollow valve rod pumps or hollow pull tube pumps. Hollow valve rod pumps are commonly used for deep wells to overcome the problem with solid valve rods connected to the plunger having a tendency to buckle during the down-stroke due to compressive loads operating there, creating friction between the valve rod and valve rod guide and between the barrel and the plunger. Also the addition of the top valve to these pumps has been known to have some benefits, known to those in the industry, for gassy wells. 
     As shown in  FIG. 11 , the top-ported rod connector  60  comprises a fluid inlet that is in fluid communication with the fluid outlet of insert  34  and ports  35 , allowing fluids F to enter connector  60  from insert  34 , and to exit connector  60  via ports  62 , into the annular space A of the tubing  12 . In one embodiment (shown in  FIG. 12 ), connector  60  comprises connection means (e.g. external threads) for connecting with housing  32 . Connector  60  further comprises connection means (e.g. internal threads) for connecting with insert  34 , aiding to hold insert  34  in place within the housing  32 . Finally, connector  60  may connection means (e.g. external threads), at its upper end, for connecting to a sucker rod (not shown). In such a case, housing  32  may be adapted to a hollow valve rod, which may also hold the valve seat  38  in place. It would be understood that housing  32  may be coated, for example with a nickel spray coating, to harden it. Having regard to  FIG. 13 , it would be appreciated that insert  34  and connector  60  may integral to one another, and may vary in size shape and the number of ports  35 ,  61 , respectively. 
     Although the hollow valve rod replacement to the solid valve rod solves a great deal of the problems associated with buckling as described above, there can still be some buckling particularly on deep wells. This buckling can still force a conventional top, three-wing cage valve over to the side of the tubing as the rod bends due to compressive forces. The valve with its sharp edges can rub on the tubing causing premature wear. One solution is to add a spray metal spiral guide to the top of the three-wing cage valve which reduces wear and by its design will last much longer than the three-wing cage itself. The problem with the spray metal spiral guide/three-wing cage is there are a number of edges that can still cause wear on the tubing. The present valve/rod connector provides advantages over known three-wing cage valve/spiral guide combinations. The cost for the valve/ported rod connector is lower, there is less wear of the tubing as a result of the smooth one piece spray metal coated surface. The valve housing is coated with a hardening process, which may be nickel spray metal, or some such other hardening process to reduce friction and enhance valve life. The valve/ported rod connector will come pre tightened or factory tightened, as a one piece add on, versus the two three-wing cage valve and spiral guide components, which can be subject to human error on under tightening. 
     In operation, when used with the ported rod connector  60 , and in response to decrease in pressure within the valve body relative to pressure at the valve inlet  40 , the valve ball  36  moves towards ball stop  45  at the bottom of insert  34 . Fluid F travels into the valve inlet  40 , around the ball  36 , and into the bore  44 . Fluid then flows into the insert  34 , via ports  35 , out of the insert  34  into flow passage of the rod connector  60  and out through ports  61  and into the annulus A of the tubing  12 . On the upstroke, ball  36  drops from ball stop  45  onto seat  38 , blocking reverse flow of fluid through the valve  30 . 
     While the pump valve has been described in conjunction with the disclosed embodiments and examples which are set forth in detail, it should be understood that this is by illustration only and this disclosure is not intended to be limited to these embodiments and examples. On the contrary, this disclosure is intended to cover alternatives, modifications, and equivalents which will become apparent to those skilled in the art in view of this disclosure. 
     For the sake of clarity, it is to be understood that the use of ‘a’ or ‘an’ throughout this application does not exclude a plurality, and ‘comprising’ does not exclude other steps or elements.