TUBING INSERTED BALANCE PUMP
Pump assemblies for use with a subsurface fluid reservoir include an upper barrel connected to a fluid filled conduit extending to the surface, a lower barrel connected to the upper barrel and in fluid communication with the reservoir, and a plunger assembly movably located within the upper and lower barrels. As the fluid pressure within production tubing, external to the pump assembly, increases, movement of the plunger draws fluid into the pump. As the fluid pressure within the production tubing decreases, the plunger pushes fluid into the production tubing.
Embodiments usable within the scope of the present disclosure relate, generally, to systems and methods usable in subsurface pumps for removing fluids (e.g., hydrocarbons) from subterranean reservoirs, and more particularly, to rodless pumping systems and methods.
BACKGROUNDPresently, low pressure reservoirs, incapable of producing fluid from the reservoir to the surface naturally, account for a majority of the hydrocarbon producing wells in the United States. There are various means of pumping fluid from these wells, such as the use of sucker rod pumps, hydraulic pumps, jet pumps, and semi-submersible electric pumps. Most of these depleted wells produce fluid at pressure and flow rates too low for the majority of existing pumps to operate efficiently and/or economically.
The most common method used for producing these low pressure, low flow rate wells is the use of sucker rod pumping systems. Sucker rod pumping systems include a downhole plunger and cylinder type pump, connected to a surface unit (e.g., a pump jack) by connecting rods (e.g., sucker rods). Existing sucker rod systems include multiple limitations and difficulties inherent in their use. While the stroke length of the pump and the stroke frequency may be controlled through the selection of the pump jack size, pumping jacks are too costly, and each pump size is limited to a specific range of flow rates and depth of the reservoir. Once a pump unit is placed, it is cost prohibitive to change the pump jack, thus modification of stroke length and/or frequency is often impossible. Another large problem with conventional sucker rod systems relates to the sucker rods, themselves. Sucker rods include segments of metal or fiberglass rod which are connected together to form a continuous string of rods, normally several thousand feet in length when used in hydrocarbon wells. These rod strings are typically connected using pin and box connections (e.g., threaded connections). The process of connecting the rod string when running sucker rod segments into a wellbore, or disconnecting the string when removing rod segments from the wellbore, is time consuming and costly. Additionally, the length and weight of these rods and the repeated reciprocation of the rods caused by the pump jack often results in failure, commonly by parting of the sucker rod string. Another difficulty associated with the use of sucker rod strings is the position of the rod string within a tubing string (e.g., production tubing). When the system is operating, it is common for the rod string to contact the inner wall of the tubular string at various points, which results in wear of both the rod string and the tubular string, and can eventually cause failure of the well tubing string, as well as the rod string. Depending of the severity of the wellbore conditions, rod pumping systems fail on the average of once a month, quarterly, or semiannually, requiring significant repair and maintenance costs. The frequency and expense of necessary repairs and maintenance is often a significant factor that causes production of a well to become uneconomical. Failure rates in rod pumping systems are significantly more common in deviated and/or non-vertical wellbores.
There have been attempts to develop a pumping system which utilizes a plunger/cylinder-type downhole pump while eliminating the use of sucker rods, thereby eliminating the problems inherent in the use of sucker rods. Existing rodless pump systems typically include a surface unit, which is connected to a subsurface pump by a fluid conduit, such as the tubing string. The surface unit activates the subsurface pump by applying pressure to the fluid in the tubing string to compress a spring or similar member in the subsurface pump and displace a slidable piston, which thereby draws fluid from the wellbore into a pump chamber. When the surface unit releases the fluid pressure, a spring mechanism in the subsurface pump will displace the piston and lift the fluid from the pump chamber into the tubing string and toward the surface. Although, such systems eliminate use of a sucker rod string, they require a compression spring for lifting the produced fluid into the tubing string. Use of such a spring severely limits the stroke length and thus, the flow rate of the pump. Further, springs used in this manner tend to fail due to wear and/or the accumulation of debris carried into the pump.
Other existing rodless pumps replace the physical spring with a gas chamber. When pressure is applied to the tubing string, a piston will compress the gas within the chamber, and when the pressure is relieved, the gas will expand to lift fluid into the tubing string. These systems allow for a longer stroke length and thus much higher efficiency, but introduce additional problems. A major problem inherent in the use of rodless pumps is that unlike sucker rod pumps, a rodless pump does not have a precisely defined stroke length. In a rodless pump, the stroke length is affected by the length of time the surface unit applies pressure to the fluid in the tubing string during each cycle, by the compressibility of the fluid in the tubing string, and by the amount of ballooning of the tubing that occurs. The stroke length is also influenced by the pressure in the gas chamber, since the pressure in the gas chamber must be sufficient to support the hydrostatic pressure of the entire column of fluid extending to the surface. At the end of each downstroke, enough force is applied to the plunger to cause the plunger to strike the bottom of the barrel with a significant impact, causing excessive wear and potential damage. Also, because the surface unit is unable to stop applying pressure to the tubing at the precise moment necessary to prevent this contact, the plunger will also impact the limit stop at the end of each upstroke. Thus, unlike sucker rod pumps, rodless pumps are difficult to design in a manner that enables the maximum stroke to be utilized without the plunger contacting the barrel at the end of the upstroke and downstroke, severely limiting the usable life of such pumps.
Other rodless pumps attempt to overcome these severe plunger impacts through use of dampening mechanisms, such as elastomer barriers, springs, and/or other types of dampeners, at both the top and bottom of the plunger's stroke. However, such rodless pump systems still utilize a downhole gas source within the pump to force the plunger assembly downward after the surface pressure source releases the pressure being exerted on the downhole pump. The gas pressure source requires a substantially self-contained pressure chamber, which can be part of the pump, can be positioned downhole, and can be used to contain a substantially compressible fluid. The chamber is also preferably precharged with a gas, such as nitrogen. Although this arrangement is an improvement over preceding pumps, particularly those subject to plunger impact, it still possesses inherent limitations. For example, this arrangement of pump requires a very high precharge pressure in the gas chamber, suffers from a short piston life due to fluid leakage and contamination, and requires bleeding the substantial gas chamber pressure whenever retrieving the pump to the surface.
Embodiments usable within the scope of the present disclosure improve upon these and other existing designs by eliminating use of rods, pump jacks, springs, and downhole gas sources or gas pressure chambers within the pump.
Another limitation associated with existing pumps is the use of a housing structure, which surrounds sections of the pump, as a means of engagement. To install such a pump, the production tubing string must be extracted from the well, such that the pump can be connected at the end of the tubing (e.g., via threading the housing to the tubing). The pump is then lowered into the well by lowering the tubing string. This undertaking requires a significant quantity of manual labor and well downtime, resulting in significant costs and losses of revenues. Furthermore, most repairs to these types of pumps also require the extraction of the entire tubular string to access the pump, which requires a major rig to handle the weight.
Embodiments usable within the scope of the present disclosure improve upon these and other existing designs by eliminating the use of wide housing, thereby enabling insertion and extraction of the pump from and/or through production tubing without requiring extraction of the production tubing itself.
However, pumps that do not contain a housing structure and are inserted into existing production tubing can be faced with certain problems. Because such pumps have small barrel and plunger diameters, they are normally capable of moving only small volumes of produced hydrocarbons with each stroke. One system that can overcome this limitation is a system that includes a pump with an increased stroke length. Pumps having longer stroke lengths, however, can be encumbered with problems, such as piston rod buckling, ineffective sealing between the pistons and the pump barrel, and significant barrel strains due to deep well pressures. Embodiments usable within the scope of the present disclosure improve upon existing systems and methods of use.
In the detailed description of various embodiments usable within the scope of the present disclosure, presented below, reference is made to the accompanying drawings, in which:
Before describing selected embodiments of the present disclosure in detail, it is to be understood that the present invention is not limited to the particular embodiments described herein. The disclosure and description herein is illustrative and explanatory of one or more presently preferred embodiments and variations thereof, and it will be appreciated by those skilled in the art that various changes in the design, organization, order of operation, means of operation, equipment structures and location, methodology, and use of mechanical equivalents may be made without departing from the spirit of the invention.
As well, it should be understood that the drawings are intended to illustrate and plainly disclose presently preferred embodiments to one of skill in the art, but are not intended to be manufacturing level drawings or renditions of final products, and may include simplified conceptual views as desired for easier and quicker understanding or explanation. As well, the relative size and arrangement of the components may differ from that shown and still operate within the spirit of the invention.
Moreover, it will be understood that various directions such as “upper,” “lower,” “bottom,” “top,” “left,” “right,” and so forth are made only with respect to explanation in conjunction with the drawings, and that the components may be oriented differently, for instance, during transportation and manufacturing as well as operation. Because many varying and different embodiments may be made within the scope of the concepts herein taught, and because many modifications may be made in the embodiments described herein, it is to be understood that the details herein are to be interpreted as illustrative and non-limiting.
Embodiments within the scope of the present disclosure relate, generally, to systems and methods usable for pumping fluids from a well. One disclosed embodiment of the pump eliminates costly repair and maintenance of producing wells due to sucker rod separation by eliminating the use of rods and by connecting the pump to a second smaller tubing (i.e. conduit) string, which also enables ease of insertion and retrieval. In an embodiment, the pump can be inserted into production tubing used throughout the petroleum industry and utilizing the tubing packer (i.e. seating nipple) already present at the bottom of most such production tubing. The conduit also enables the formation of a second fluid column, which balances fluid pressure in the production tubing, which enables the actuation of the downhole pump by intermittently applying and removing pressure from the production tubing.
Referring now to
During typical operation, the pump (10) can be positioned toward the downwell end of the tubing string (5), within the reservoir (3) area. A casing may be inserted into the wellbore (4) to prevent the walls of the wellbore from collapsing. The wellbore (4) and the casing include perforations formed in the side walls thereof to permit fluid to flow from a well production zone into the wellbore (4), such that a wellbore fluid annulus (6), which surrounds the pump (10), can be filled with production fluid. The area of the wellbore fluid annulus (6), filled with production fluids, will hereafter be referred to as the reservoir (3). It should be understood, however, that embodiments usable within the scope of the present disclosure could also be used within uncased wellbores.
As depicted in
At the upwell end of the pump (10),
As shown, the downwell end of the pump (10) includes a lower barrel (12). As depicted in
Referring specifically to the plunger assembly (20),
As further depicted in
Referring again to the plunger assembly (20) depicted in
The lower plunger (22), depicted in
Embodiments of the plunger assembly (20), which are disclosed above, require little to no significant compression forces to be applied to the shaft (23) during the operation of the pump (10). Therefore, the shaft (23) in the present pump can be longer than the rods in conventional subsurface pumps, enabling an increased stroke and pumping capacity. During the down stroke, the production fluid flows through the traveling check valve (41) to offer little resistance to the lower plunger (22). During the up stroke, the traveling check valve (41) closes, preventing fluid flow through the fluid passageway of the lower plunger (22), however, the shaft (23) is in tension during this stage. In the embodiment depicted, the stroke length is 24 feet, however, other embodiments, having strokes greater or less than 24 feet are also possible.
Generally, the outside diameter of the upper and lower plungers (21, 22) must properly mate with the inside diameters of the corresponding barrels (11, 12), the relative fit between the plungers (21, 22) and barrels (11, 12) being sufficiently close to facilitate a formation of a fluid seal between the two sets of components, but at the same time to allow the plungers (21, 22) to move freely within the barrels (11, 12). The lengths of the plungers (21, 22) can vary depending on the overall length and stroke length of the pump (10).
As it is desirable that the pump (10) be inserted into tubing string (5) and, at the same time, maintain the largest possible internal volume, embodiments of the present pump can include barrels (11, 12) having wall thicknesses less than that of conventional downwell pumps. The thin walls of the pump (10) can be more susceptible to high hydrostatic pressures associated with deep wells, and can undergo significant strains when lowered to high depths. At such depths, the barrel (11, 12) walls may be compressed and the inside diameter of the pump (10) narrowed to a point where contact and/or friction between the plungers (21, 22) and barrels (11, 12) causes the plungers (21, 22) to become unable to reciprocate within the barrels (11, 12). To prevent such seizure, the outside diameters of the plungers (21, 22) may be sized to be significantly smaller than the inside diameters of the barrels (11, 12). However, incorporating a large clearance (25) in the fit, between the upper barrel (11) and the upper plunger (21), can result in fluids leaking between the upper and central cavities (51, 53).
To solve this problem, the outside surface of the plungers (21, 22) can be configured to include sealing elements to prevent such fluids from leaking during pump operation. Sealing elements such as lip seals, cups, and/or sealing rings, and other similar sealing elements, can be used. For example, metal sealing rings (26) shown in
Several significant improvements can be attributed to the novel configuration of the pump (10) as disclosed. For example, embodiments of the present subsurface pump (10) can allow for a stroke that may be 24 feet in length or longer. Due to such long strokes, the pump cycle frequency is significantly slowed when compared to conventional pumps, resulting in reduced wear and extending the life of the pump. Furthermore, as shown in
As the thin barrel walls require less lateral forces to cause bending, the pump (10) flexes more easily with less internal stresses (e.g. tension, compression, shear, etc.) within the barrel walls during lowering and retrieval into or from a wellbore. As a result, the barrel walls experience lesser internal strains and therefore a lesser chance of permanent deformation in the pump structure. Also, the large clearance (25) in the fit between the barrel walls and the upper plunger (21) can result in a small range of motion (e.g., “play”) between the two components, which can allow the barrels (11, 12) to bend substantially without interfering with the upper plunger (21). Furthermore, the length of the upper plunger (21) also enables the pump (10) to flex without resulting in high local forces being applied to the barrel walls, which can result in permanent deformation in the pump structure. During pump lowering through the tubing string (5) or during operation, especially in a deviated wellbore, contact between the upper plunger (21) and the upper barrel (11) walls can result. Such contact can introduce high forces and stresses in the upper barrel (11) walls that can cause permanent deformation thereof. A longer plunger (21) contains a larger surface area that contacts the walls of the upper barrel (11), which results in a greater distribution of lateral or bending forces between the two parts along a larger surface area of contact. Greater distribution of contact forces result in smaller stresses between the upper barrel (11) and upper plunger (21), decreasing the chances of permanent damage to the pump (10). Lastly, a larger surface area of contact between the upper plunger (21) and upper barrel (11) also allows for improved sealing, which can prevent fluids from leaking between the two parts. Larger surface area between the upper barrel (11) and the upper plunger (21) result in increased sealing area, which in turn results in a lesser amount of fluids leaking between the two parts. Larger surface area between the two components also provides more space for additional sealing elements, which improve the ability to prevent fluid leakage. In the embodiment depicted, each plunger (21, 22) is two feet in length, though other lengths are usable in other embodiments.
Referring again to
During the upstroke phase of pump operation, the pressure of the balancing fluid column is exceeded by the pressure in the tubing string (5), as generated by the surface pump (not shown). Specifically, production fluid is communicated into the central cavity (53) through the annular ports (13), and the balancing fluid is pushed out of the upper cavity (51) and upwell, into the conduit (15). As the fluid in the conduit (15) rises above the surface (2), the pressure of the balancing fluid at the pump (10) raises, and an imbalance between the hydrostatic pressure in the central cavity (53) and the hydrostatic pressure in the upper cavity (51) is formed. As the plunger assembly (20) reaches its upper most position, the surface pump is disconnected from the tubing string (5) and the pressure generated by the pump is released. As the hydrostatic pressure of the fluid column in the fluid conduit (15) is greater than the hydrostatic pressure of the fluid column in the tubing string (5), the plunger assembly (20) is forced in the downwell direction. The upper plunger (21) forms a barrier between the production fluid in the central cavity (51) and the balancing fluid in the upper cavity (53); however, some transfer of fluid between the two cavities (51, 53) may occur as some fluids may leak past the upper plunger (21). As the plunger assembly (20) moves upwell and downwell within the pump (10), it draws production fluids into the lower barrel (12) from the reservoir (3) on the upstroke and forces it out into the tubing string (5) on the downstroke.
A more detailed operation of the pump system is described below. This process, as shown in
While various embodiments usable within the scope of the present disclosure have been described with emphasis, it should be understood that within the scope of the appended claims, the present invention can be practiced other than as specifically described herein.
Claims
1. A pump assembly positioned within and in fluid communication with production tubing extending between a subsurface fluid reservoir and a well surface, the pump assembly comprising:
- an upper barrel connected to a fluid conduit that extends between the upper barrel and the well surface;
- a lower barrel connected to the upper barrel and in fluid communication with the subsurface fluid reservoir; and
- a plunger assembly comprising: an upper plunger movably disposed within the upper barrel; and a lower plunger connected by a shaft to the upper plunger and movably disposed within the lower barrel,
- wherein the plunger assembly draws fluid from the subsurface fluid reservoir into the pump assembly and pushes fluid out of the pump assembly into the production tubing in response to fluid pressure changes within the production tubing.
2. The pump assembly of claim 1, wherein the fluid conduit is filled with balancing fluid, wherein the fluid within the production tubing moves the plunger in a first direction as fluid pressure within the production tubing increases, and wherein the balancing fluid in the fluid conduit moves the plunger in a second direction as fluid pressure within the production tubing is released.
3. The pump assembly of claim 1, further comprising sealing elements located on the upper plunger, wherein the sealing elements allow the upper plunger to move laterally within the upper barrel while maintaining sealing action.
4. The pump assembly of claim 1, wherein the upper plunger has an outside diameter that is sized to permit axial movement within the upper barrel when the upper barrel is compressed or bent by an external force.
5. The pump assembly of claim 1, wherein the plunger assembly moves at least 18 feet or more within the pump assembly.
6. The pump assembly of claim 1, wherein the upper plunger is greater than 20 inches in length.
7. A pump assembly for pumping fluid from a subsurface fluid reservoir comprising:
- an upper barrel connected to a lower barrel and a fluid conduit, wherein the lower barrel is in fluid communication with the subsurface fluid reservoir, and wherein the fluid conduit extends from the upper barrel to a surface of a well; and
- a plunger assembly movably disposed within the upper barrel and the lower barrel,
- wherein fluid pressure within a production tubing external to the fluid conduit moves the plunger assembly in a first direction to draw fluid into the lower barrel, wherein fluid pressure within the fluid conduit moves the plunger assembly in a second direction to push fluid into the production tubing, and wherein the pump assembly prevents fluid flow from the production tubing into the fluid reservoir.
8. The pump assembly of claim 7, wherein the plunger assembly further comprises:
- a lower plunger movable within the lower barrel; and
- an upper plunger movable within the upper barrel, wherein the upper plunger has an outside diameter that is smaller than an inside diameter of the upper barrel for permitting axial movement of the upper plunger within the upper barrel when the upper barrel is compressed or bent by an external force, and wherein sealing elements on the upper plunger prevent fluid flow through an annulus between the upper barrel and the upper plunger.
9. The pump assembly of claim 8, wherein the pump assembly is configured for insertion into the production tubing, wherein the pump assembly further comprises a mating area configured for attachment to the production tubing, and wherein the mating area prevents fluid communication between the production tubing and the fluid reservoir through an annular space between the production tubing and the pump assembly.
10. The pump assembly of claim 8, wherein the sealing elements comprise piston ring seals, lip-seals, cup seals, or combinations thereof, and wherein the sealing elements permit lateral movement of the upper plunger within the upper barrel.
11. The pump assembly of claim 8, wherein the sealing elements permit axial movement of the upper plunger within the upper barrel when the upper barrel is compressed or bent by an external force.
12. The pump assembly of claim 8, wherein the upper plunger is greater than 20 inches in length.
13. The pump assembly of claim 8, wherein the upper and lower plungers are configured to move more than 18 feet within the upper and lower barrels respectively.
14. A pump assembly, comprising
- an upper barrel connected to a lower barrel, wherein the upper barrel is fluidly connected to the lower barrel, and wherein the upper barrel is fluidly connectable to a fluid conduit;
- the lower barrel fluidly connectable to a fluid reservoir;
- a plunger assembly comprising an upper plunger movable within the upper barrel and a lower plunger movable within the lower barrel, wherein the upper plunger and the lower plunger are connected,
- wherein the plunger assembly is movable in a first direction to draw fluid from the fluid reservoir into the lower barrel responsive to a pressure increase external to the pump assembly, and
- wherein the plunger assembly is movable in a second direction to push fluid out of the pump assembly responsive to a pressure decrease external to the pump assembly.
15. The pump assembly of claim 14, wherein the pump assembly is configured for insertion into a production tubing, wherein the pump assembly further comprises a mating area configured for attachment to the production tubing, and wherein the mating area prevents fluid communication between the production tubing and the fluid reservoir through an annular space between the production tubing and the pump assembly.
16. The pump assembly of claim 14, wherein the pump assembly further comprises:
- a check valve, wherein the check valve prevents fluid from flowing from the lower barrel to the fluid reservoir.
17. The pump assembly of claim 14, wherein the upper plunger has an outside diameter that is smaller than an inside diameter of the upper barrel for permitting axial movement of the upper plunger within the upper barrel when the upper barrel is compressed or bent by an external force, and wherein the upper plunger comprises sealing elements which seal an annular area between the upper plunger and the upper barrel.
18. The pump assembly of claim 17, wherein the sealing elements comprise piston ring seals, lip-seals, cup seals, or combinations thereof, and wherein the sealing elements permit axial movement of the upper plunger within the upper barrel when the upper barrel is compressed or bent by an external force
19. The pump assembly of claim 14, wherein the upper plunger is greater than or equal to 20 inches in length.
20. The pump assembly of claim 14, wherein the upper and lower plungers are configured to move at least 18 feet or more within the upper and lower barrels respectively.
Type: Application
Filed: Dec 21, 2012
Publication Date: Jun 26, 2014
Inventor: John Bradford, JR. (Houston, TX)
Application Number: 13/694,683
International Classification: F04B 7/00 (20060101);