Patent Application
20150376995
This application claims priority to co-pending U.S. patent application Ser. No. 13/773,826, entitled Modular Top Loading Downhole Pump, filed Feb. 22, 2013, the entirety of which is incorporated herein by reference.
The present invention relates generally to downhole pumps and, more particularly, but not by way of limitation, to downhole pumps in subterranean wells for moving fluids and slurries to the surface of the earth and for preventing gas lock. Methods of pumping fluids and of preventing gas-lock in downhole pumps are also provided.
The present invention is directed to a downhole pump positioned below the tubing string of a well for pumping fluids. A downhole pump positioned below the tubing string of a well for pumping fluids. The pump comprises a body, at least one valve connectable with the body, wherein fluids enter the at least one valve and exit the at least one valve and enter the body. The pump comprise a plunger moveable between an upper first position and a lower second position, wherein the upper first position is below the at least one valve. During plunger downstrokes, fluids enter the body and wherein during plunger upstrokes, fluids move up the tubing string.
The present invention is further directed to a system for pumping fluids in a well having a tubing string. The system comprises a body, at least one valve connectable with the body, wherein fluids enter the at least one valve and exit the at least one valve and enter the body, and a plunger moveable between an upper first position and a lower second position, wherein the upper first position is below the at least one valve. During plunger downstrokes, fluids enter the body and wherein during plunger upstrokes, fluids move up the tubing string.
The present invention is further directed to method of pumping fluids from a reservoir via a well comprising a tubing string. The method comprises the steps of intaking fluid into a body positioned below the tubing string via a valve positioned above a plunger within a barrel and moving the fluids up the tubing string on the upstroke of the plunger.
The present invention is further directed to a method of preventing gas lock in a well comprising a tubing string. The method comprises the steps of intaking fluid via a valve positioned above a plunger within a barrel, moving the plunger between an upper first position and a lower second position, wherein the upper first position is below the valve, discharging fluid from the valve into a body positioned below the tubing string and moving the fluids up the tubing string on the upstroke of the plunger.
The present invention further is directed to an exit valve for use in the tubing string of a well for pumping fluids. The exit valve comprises a valve body comprising a hollow center and a seal.
The task of moving subterranean fluids, including oil, gas and slurries, from a reservoir to the surface of the earth requires a system of equipment that typically includes a downhole pump, often a reciprocating-type positive displacement pump, positioned within the borehole of the well. The downhole pump is connected, directly or indirectly, to a sucker rod string within the tubing in the borehole. The rod string cooperates with an artificial lift unit or pump jack that is powered by a prime mover, such as a combustion engine or electric motor. The sucker rod string moves up and down within the tubing in the borehole via motion of the artificial lift unit and transfers movement to the downhole pump.
Downhole positive displacement pumps of the reciprocating type often have a plunger within a barrel and a series of inlet and outlet valves for receiving and discharging fluid. The barrel is attached to the end of the tubing, and the plunger is attached to the sucker rod string. Reciprocating action of the plunger charges a cavity disposed between a traveling valve and a standing valve and lifts fluids through the tubing to the surface. Fluids flow into the pump through inlet valves on the suction, or up stroke, of the plunger as the cavity is expanding, and they are discharged through outlet valves on the discharge or down stroke as the cavity size decreases. Fluids discharged from the pump are forced up the tubing string to the wellhead where liquids and gases are separated and moved into production streams.
In conventional rod pumping systems, the standing valve is positioned at the bottom of the tubing, below the barrel and the plunger, while the traveling valve is positioned at the bottom of the sucker rod string and above the standing valve. On downstrokes of the plunger, the traveling valve is open and the standing valve is closed due to the weight of the fluid above it, which is moving upward through the open traveling valve, into the tubing, as the plunger moves downward. Conversely, on upstrokes, the traveling valve closes and fluids enter the barrel. As the plunger moves upward again, the available volume increases in the barrel between the standing valve and the traveling valve. When the plunger reaches the top of its stroke, the movement repeats downward again, and the traveling valve opens while the standing valve closes. Thus, conventional downhole pumps lift fluids up the tubing string on the downstroke of the plunger.
Problems can arise when gases are present. Some wells produce free gas, or gases entrained in liquid will come out of solution during production. If the produced fluid retains free gas, then the valves will not necessarily open or close at the top or bottom of the stroke. These gases may partially fill the cavity of the pump, displacing oil or other more desirable liquids, thereby adversely affecting the efficiency of the well. Additionally, the greater the volume of free gas, the greater the pumping action of the plunger is dedicated to expansion and compression of free gas rather than pumping fluids to the surface.
Moreover, gases may overtake the cavity of the pump, causing gas lock. Gases trapped between the inlet and outlet valves prevent the pump from achieving sufficient pressure to move fluids up the tubing string. When this happens, all valves are stuck in the closed position, and this holds the ball off seat, preventing fluid from moving through the pump or up the string to the surface. Concomitant losses in productivity occur. Efforts to eliminate gas lock sometimes occasion damage to the equipment and tools in the wellbore.
The downhole pump of the present invention overcomes problems associated with gas lock. Through a unique configuration, the plunger is positioned within a barrel below inlet valves in the pump. Inlet valves cooperate with a body positioned above the plunger and the barrel so that fluids enter the above the plunger and barrel. When the plunger moves up, intake fluids close off the valves and fluids are forced up the tubing string through a conventional slide valve that normally is used to connect the sucker rod string to the valve rod. This configuration elimates the need for outlet valves and eliminates gas lock in wells having a larger production levels.
The present invention further comprises a sealable exit valve in working cooperation with a valve rod that forms an aperture. The sealable exit valve forms a positive seal with the valve rod yet still allows the valve rod to move through the exit valve while allowing free and entrained gases to escape, thus preventing gas lock.
Furthermore, the present invention allows modularity of the pump components and offers benefits as the productivity of the well changes. An operator easily can alter the size of the barrel and the plunger to match modifications in production. For example, as well productivity decreases, the plunger and barrel can be replaced by smaller units that will pump fewer barrels in a given time period. Alternately, if enhanced recovery techniques cause the well to increase production, the modularity of the pump design of the present invention permits plunger and barrel to be easily interchanged with components matching higher production levels.
The modular design of the present invention also eases maintenance and decreases shut-in times and frequency. It is expected that mechanical parts, especially in moving systems, will break down or require maintenance. The unique configuration enables repair or replacement of valves, plunger, barrel, body and other parts without replacing the entire pump, resulting in lower maintenance costs and more efficient repair and shut-in times. These and other advantages of the present invention will be apparent from the following description of embodiments.
Turning now to the drawings in general, and to
Turning now to
In one embodiment of the invention, slide valve 26 permits the flow of fluids from the pump 12 into the tubing string 18. As the pump jack moves up and down, the sucker rod string 20 moves valve rod 22, which reciprocate within the pump 12. The valve rod 22 extends through the slide valve 26 and connects with components in the pump. Fluids enter the pump 12 in a manner yet to be described and move up the tubing string in the direction of arrow x. In this embodiment of the invention, the slide valve 26 acts as an exit valve for free gas or gases entrained in produced fluids. Fluids can seep between the two components, valve rod 22 and slide valve 26, into the pump 12. The amount of fluid that seeps between the valve rod 22 and slide valve 26 may vary due to the measured tolerance between these two components, the hydrostatic pressure exerted by the produced fluid, the produced fluid type, the depth of the well, the strokes per minute of the pumping unit and other factors. As the volume of the fluids seeped approaches the designed pumping volume of the pump 12, the efficiency of the pump will decrease.
In wells that produce fluids at rates of less than about 300 bbl/day, or if the tolerance between the valve rod 22 and slide valve 26 is excessive, for example, but without limitation, tolerances greater than about 0.005 inches, a different mechanism may be employed to prevent gas locking. Turning now to
The exit valve 100 comprises an exit valve body 102, a nut 104 and one or more seals 106 to engagingly seal with the valve rod 22. The exit valve body 102 may made be of any material suitable for use downhole, including steel, chrome, steel chrome-plated, steel with nickel/silicon carbide composite coating, brass, brass-chrome plated, brass with nickel/silicon carbide composite, stainless steel, stainless chrome-plated, stainless with nickel/silicon carbide composite coating, carbonitrided steel, nickel carbide plated steel, tempered steel and polyvinylchloride. It will be appreciated that the exit valve body 102 may be produced from other materials suited to the particular temperatures, pressures, fluids, and other conditions at the well 14 where in use. The diameter and length of the exit valve body 102 are variable and depend upon the size of the well 14, the diameter of the casing 16, the size and diameter of the barrel 28 and the plunger 30 and the quantity of production from the well, for example.
The nut 104 engages with the exit valve body 102. In one embodiment of the invention, the nut 104 is a flange nut and threadably engages with the exit valve body 102 via threads 110 and 112, shown in
The nut 104 may made be of any material suitable for use downhole, including steel, chrome, steel chrome-plated, steel with nickel/silicon carbide composite coating, brass, brass-chrome plated, brass with nickel/silicon carbide composite, stainless steel, stainless chrome-plated, stainless with nickel/silicon carbide composite coating, carbonitrided steel, nickel carbide plated steel, tempered steel and polyvinylchloride. It will be appreciated that the nut 104 may be produced from other materials suited to the particular temperatures, pressures, fluids, and other conditions at the well 14 where in use. The diameter and length of the nut are variable and depend upon the size of the exit valve body 102, the size of the well 14, the diameter of the casing 16, the size and diameter of the barrel 28 and the plunger 30 and the quantity of production from the well, for example.
The seal 106 is receivable at a seat or shoulder 116 formed in exit valve body 102. It will be appreciated that multiple seals may be used in the exit valve 100 and that not all seals necessarily must abut the seat or shoulder 116. A spacer, not shown, may be employed between the shoulder 116 and seal 106. Some examples of suitable seals 106 useful in the invention include mechanical seals and tolerance seals. Seals 106 may be may made be of any material suitable for use downhole, including nitrile, urethane, neoprene, fluorosilicone, nilrile, polyurethane, FEP, polyacrylate, silicone and other elastomers and fibers.
In this embodiment of the invention shown in
With continuing reference to
With continuing reference to
The plunger 30 is a reciprocating plunger connectable to valve rod 22 and may be made of any material suitable for use downhole, including carbon, steel, chrome and spray coated metal and is adapted for use in corrosive and abrasive conditions. It will be appreciated that the plunger 30 may be produced from other materials suited to the particular temperatures, pressures, fluids, and other conditions at the well 14 where in use. The diameter and length of the plunger 30 are variable and depend upon the size of the well 14, the diameter of the casing 16, the size and diameter of the barrel and the amount of production from the well, for example. It will be appreciated that the plunger 30 may be produced from other materials suited to the particular temperatures, pressures, fluids, and other conditions at the well 14 where in use. The diameter and length of the plunger 30 are variable and depend upon the size of the well 14, the size of the barrel 28, and the quantity of production from the well, for example. The length of the plunger 30 generally ranges from at least about 2 to at least about 50 feet, while the diameter of the plunger generally ranges from about 1 inch to about 7 inches. It will be appreciated, however, that the plunger 30 may be any diameter and length suited for conditions at the well where in use. The plunger 30 preferably, though not necessarily, complies with American Petroleum Institute (API) quality standards and dimensions. Plungers suitable for use in the invention are produced by Norris, Harbison-Fischer and Cameron, among others.
Turning now to
The diameter and length of the body 32 are variable and depend upon the size of the well 14, the diameter of the casing 16, the size and diameter of the barrel 28 and the plunger 30, the quantity of production from the well, and the number of valves 34, for example. The length of the body 32 generally ranges from at least about 1 foot to at least about 60 feet, while the diameter of the body generally ranges from about 0.5 inches to at least about six feet. It will be appreciated, however, that the body 32 may be any diameter and length suited for conditions at the well where in use. Persons skilled in the art of pumping fluids will know how to size components for the conditions suited to a particular well.
In one embodiment of the invention, body 32 forms threaded ends 40 and 42 and is threadably receivable with couplings 50 and 52, shown in
With continuing reference to
Valve 34 is connectable to body 32 via connector 38. The connector 38 may be made of any material suitable for use downhole, including steel, chrome, chrome-plated steel, steel with nickel/silicon carbide composite coating, brass, brass-chrome plated, brass with nickel/silicon carbide composite, stainless steel, stainless chrome-plated, stainless with nickel/silicon carbide composite coating, carbonitrided steel, nickel carbide plated steel, tempered steel and polyvinylchloride. It will be appreciated that the connector 38 may be produced from other materials suited to the particular temperatures, pressures, fluids, and other conditions at the well 14 where in use. While the shape of valve 38 may be any shape configured to fit downhole, a tubular shape generally is preferred as it facilitates operation with other tools and equipment in the well 14.
Connector 38 may be partially recessed in body 32 to enable the valve to sit closely to the exterior surface 58 of the body, creating a smaller overall dimension of the body and enabling use in smaller casing 14. Connector 38 may be welded to body 38, as in one embodiment of the invention, although it will be appreciated that connector 38 may be secured, joined or affixed to body 32 by any known means.
Turning now to
In operation of the invention, when the plunger 30 reciprocates up, in the direction of arrow x, fluid moves the ball 68 on top of the seated plug 72. Spring 70 holds ball 68 against seat 72 and seals the off fluid flow into the body 32 through aperture 62. Because the body 32 and valves 34 are positioned above the plunger 30, the upstroke of reciprocating plunger 30 forces fluids to move up through the body 32 into the tubing 18 and to the surface of the well 14 toward the surface equipment or the sales line. On the downstroke of reciprocating plunger 30, the ball 68 is unseated and fluids entering through aperture 60 again may exit the valve 34 and enter the body 32 through aperture 62. It now will be appreciated that valves 34 operate as inlet valves for intaking fluids from well 14 into body 32 and that the unique configuration of pump 12 eliminates the need for outlet valves. Fluids exit the body 32 and enter the tubing string 18 through slide valve 26.
Thus, it now apparent that the pump 12 moves fluid up the tubing 18 to the surface on the upstroke of the plunger. The pump 12 and sliding valve 26 may be combined in operation with a conventional traveling valve and standing valve, which move fluids on the downstroke of a plunger. This will enable the plunger 30 to move fluids up the tubing 18 both on the upstroke and the downstroke of the plunger 30, thus, effectively multiplying the efficiency and productivity of the well 14. The combination may also require the use of a pull tube or hollow rod as a valve rod 22.
It further will be appreciated how the unique configuration of the downhole pump of the present invention prevents gas lock. During normal pump operation and when placed in wells that produce fluids in excess of 300 bbl/day, the mechanism that prevents gas lock is provided by seepage of the fluids being pumped, in both liquid and gaseous form, between the valve rod 22 and the slide valve 26. The measured tolerances between a conventional slide valve 26 and valve rod 22 can range from about 0.001 to about 0.025 of an inch, or more. If gas becomes trapped within the body 32 above the plunger 30, the tolerance between the two components will either allow the gas to seep upwards past the slide valve 26 into the tubing 18 and/or to match the hydrostatic pressure exerted by the fluids within the tubing 18 above the slide valve 26.
In wells that produce fluids at rates of less than 300 bbl/day, or if the tolerance between the valve rod 22 and slide valve 26 are found to be excessive, an alternative embodiment may be employed to prevent gas locking. As stated above, the amount of fluid that seeps between the valve rod 22 and the sliding valve 26 components may vary due to the measured tolerance between these components, the hydrostatic pressure exerted by the produced fluid, the strokes per minute of the prime mover and other factors. As the volume of fluids that seep back into the pump 12 through the valve rod 22 and slide valve 26 approaches the designed pumping volume of the pump, the efficiency of the pump will decrease.
In these cases, it has been found that the sealable exit valve 100, in conjunction with the valve rod 22 forming aperture 120 prevents gas lock. Returning to s 3 and 3A, the aperture 120 has an upper end 122 and a lower end 124. The aperture 120 is formed towards an upper end 130 of the valve rod 22. The exit valve 100 also has an upper end 140 and a lower end 142. During pump 12 operation, and at or around the bottom of the downstroke of the plunger 30, the bottom end 124 of the aperture 120 passes through a bottom end 142 of the exit valve 100, while the top end 122 of the aperture 120 remains above the top end 140 of the exit valve 100, as shown in
The present invention permits modularity of the components of the pump 12. An operator easily can change out the barrel 28, plunger 30, body 32 valves 34, exit valve 100 or valve rod 22 when changes in production necessitate modifications in size of components or when maintenance is needed. Only one component need be substituted to alter the production of the well 14.
The efficiency and utility of a pump constructed in accordance with the present invention is demonstrated by the following example. An operating well, drilled to a depth of at least 7800 feet, was selected that produced 360 bbl/day at 100% efficiency. A pump of the present invention was installed using a 2 inch diameter plunger and a body constructed of 2 and ¾ inch inside diameter tubing sub, 20 feet long, inside a barrel of 2 and ¼ inches diameter. The well was run for a period of 24 hours, during which time the well produced 16.4 bbl/hour using 5 strokes of the plunger per minute. The well produced an additional 31 bbl/day, increasing overall productivity 8.5% to 391 bbl/day and profitability of the well by approximately $3,000 per day.
The efficiency and utility of the pump constructed in accordance with the present invention with exit valve and valve rod forming an aperture is demonstrated by the following example. A modular downhole pump with sealable exit valve and valve rod forming an aperture was tested in a completed well drilled to a depth of 5,820 feet. Prior to the test installation of the present invention, the subject well, over a period of four months, had produced a total of 60 barrels of fluid due to frequent episodes of gas locking of prior downhole pumps installed at the well. After the experimental test installation of the invention, the well is producing an average 28.33 bbl/day of fluid, and the pump has not gas locked at any time.
The present invention further is directed to a method of pumping fluids from a reservoir in a well comprising a tubing string 18. Fluids are drawn in via at least one inlet valve 34 positioned above a plunger 30 within a barrel 28. The fluids move up the tubing string in the direction of arrow x on the upstroke of the plunger 30. The productivity of the well 14 may be altered by changing the plunger 30 to a larger or smaller size, in length, diameter or both, or by changing the size of the barrel, in length, diameter or both. The at least one valve is employed in connection with a body 32 used in association with the barrel 28 and plunger 30. The productivity of the well also may be altered by increasing the number of, or the changing the configuration of, valves 34 employed with body 32 and positioned above the barrel 28 and plunger 30.
The present invention further is directed to a method of preventing gas lock in a well 14 comprising a tubing string 18. To prevent gas lock, fluids are drawn in via at least one inlet valve 34 employed with a body positioned above a plunger 30 within a barrel 28. Fluids enter body 32 through inlet valves 34 and exit the body 32 through slide valve 26 into tubing string 26. The unique configuration of pump 12 eliminates the need for outlet valves.
During normal pump operation, and when placed in wells that produce fluids in excess of about 300 bbl/day, the mechanism that prevents gas locking is provided by seepage of the fluids, in both liquid and gaseous form, between the valve rod 22 and the sliding valve 26. In the practice of the invention using slide valve 26 and valve rod 22 without an aperture, if gas becomes trapped within the body 32 above the plunger 30, the tolerance between the valve rod 22 and slide valve 26 will either allow the gas to seep upwards past the slide valve into the tubing 18 and/or allow it to match the hydrostatic pressure exerted by the fluids within the tubing above the slide valve.
Alternatively, exit valve 100, in conjunction with the valve rod 22 having aperture 120 may be used to prevent gas lock. The aperture 120 in valve rod 22 forms a passage between the body 32 of the pump 12, above the plunger 30, and the fluids within the tubing 18 above the exit valve 100. This channel allows gas trapped within the body 32 of the pump 12 above the plunger 30 to move upwards, past the exit valve 100 into the tubing 18. It also allows trapped gas to match the hydrostatic pressure exerted by the fluids within the tubing 18 and above the exit valve 100, thus preventing gas lock
The unique configuration of pump 12 also eliminates gas lock. Fluids, including gases from the formation 10 or coming out of solution, are forced up the tubing string 18 on the upstroke of the plunger 30. These fluids cannot lock the plunger 30 since the plunger is positioned below the valves 34. Further, the fluids cannot lock the valves 34 since the valves are positioned above the plunger 30 and function as inlets.
It now will be appreciated that the present invention presents a new downhole pump having a unique configuration that places the valves above the plunger and barrel of the pump. This configuration forces fluids up through the tubing string 18 on the upstroke of the plunger 30 to the surface and prevents gas lock. The invention also present a unique exit valve which, in cooperation with a valve rod having an exit valve, permits free and entrained gasses to escape and further enhances the ability of the invention to prevent gas lock. The configuration is modular and allows easy replacement, maintenance or alteration of the components of the pump, including the barrel, plunger, body or valves. The configuration also increases productivity in a well when using smaller components.
The invention has been described above both generically and with regard to specific embodiments. Although the invention has been set forth in what has been believed to be preferred embodiments, a wide variety of alternatives known to those of skill in the art can be selected with a generic disclosure. Changes may be made in the combination and arrangement of the various parts, elements, steps and procedures described herein without departing from the spirit and scope of the invention as defined in the following claims.
| Number | Date | Country | |
|---|---|---|---|
| Parent | 13773826 | Feb 2013 | US |
| Child | 14848848 | US |
