US20140178225A1

US20140178225A1 - Tubing inserted balance pump

Info

Publication number: US20140178225A1
Application number: US13/694,683
Authority: US
Inventors: John Bradford, JR.
Original assignee: Individual
Current assignee: Individual
Priority date: 2012-12-21
Filing date: 2012-12-21
Publication date: 2014-06-26

Abstract

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.

Description

FIELD

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.

BACKGROUND

Presently, 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.

BRIEF DESCRIPTION OF THE DRAWINGS

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:

FIG. 1 is a cross-sectional conceptual view of an embodiment of a pump usable within the scope of the present disclosure as it is positioned within the production tubing and the well bore, with the plunger assembly at the lowest position of a pump stroke

FIG. 2 is a cross-sectional close-up view of the upper plunger assembly of the pump of FIG. 1.

FIG. 3 is a cross-sectional close-up view of the upper plunger assembly and the mounting section of the pump of FIG. 1.

FIG. 4 is a cross-sectional view of the pump of FIG. 1, with the plunger assembly moving in the upwell direction in response to the application of pressure from a surface pumping unit to the fluid in the tubing string.

FIG. 5 is a cross-sectional view of the pump of FIG. 1, as the plunger assembly reaches the top of an upstroke.

FIG. 6 is a cross-sectional view of the pump of FIG. 1, with the plunger assembly moving in a downwell direction in response to a release of pressure introduced by the surface pumping unit to the fluid in the tubing string, and the application of hydrostatic pressure from balancing fluid contained in the fluid conduit.

DETAILED DESCRIPTION OF THE EMBODIMENTS

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 FIG. 1, a cross-sectional view of an embodiment of a subsurface pump (10) usable within the scope of the present disclosure is shown. The subsurface pump, as depicted, is mounted within a tubing string (5) (e.g., production tubing) which extends to the surface (2) of the wellbore (4) within which the tubing string (5) is positioned. At the surface (2), the tubing string (5) can be fluidly connected to a surface pumping unit (not shown), which is usable to force fluids down the tubing string (5), e.g., by applying pressure to the fluid in the tubing string (5) to actuate the subsurface pump (10). As further depicted in FIG. 1, the pump includes an upper barrel (11), a lower barrel (12), and a plunger assembly (20), which includes an upper plunger (21), a lower plunger (22), and a connecting shaft (23) extending therebetween. The plunger assembly (20) is movably disposed within the upper and lower barrels (11, 12), as described in more detail below.
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 FIGS. 1 and 3, the subsurface pump (10) includes a tube mounting section (30) at the lower end of the pump (10). The tube mounting section (30) can securely attach the pump (10) to a seating nipple (35) formed and/or mounted in the lower end of the tubing string (5). The seating nipple (35) can be a standard type commonly used for rod pump installation. Thus, the subsurface pump (10) can replace a sucker rod pump, typically used in a standard rod pump system, without requiring removal and/or retrieval of the tubing string (5) for installing special seating nipples (35). The tube mounting section (30) can be configured to include rubber o-ring seals (32) or similar sealing members to prevent fluids from breaching the seal (e.g., bypassing the pump) when the tube mounting section (30) is engaged with a corresponding seating nipple (35). It should be understood that the manner of sealing the pump (10) against the seating nipple (35) can include any type, configuration, number, and/or combination of sealing elements, including elastomeric seals, metal-to-metal seal, or other types of sealing. FIG. 1 also depicts the tube mounting section (30) having a chamfered end (34), which aids insertion into the seating nipple (35) by guiding the tube mounting section (30) into the engaged position.
At the upwell end of the pump (10), FIG. 1 further depicts a fluid conduit (15) (e.g. a fluid passageway), which is connected to the pump (10) at the upwell end of the upper barrel (11). The fluid conduit (15), along with the tubing string (5), communicates fluids between the surface (2) of the wellbore (4) and the pump (10). Specifically, the depicted pumping system utilizes two fluid passageways from the surface of the well, one being the aforementioned tubing string (5) and the second being the fluid conduit (15) that contains a hydrostatic pressure balancing fluid. FIG. 1 depicts the upper barrel (11) being adapted for connecting to the fluid conduit (15), while production fluid flows through the annulus (7), between the tubing string (5) and the conduit (15)—pump (10) assembly. The conduit (15) is positioned within the tubing string (5) and is connected to a surface source of balancing fluid, which is discussed in further detail below. The tubing string (5) can be connected to a surface pumping unit (not shown), such as a hydraulic pump having a timed cycle for controlling the upstroke and downstroke of plunger assembly (20). The combination of the fluid conduit (15) and the fluid contained therein eliminates the need for use of a downhole gas chamber, normally required to push the production fluid to the surface (2). It should be understood that the manner in which the fluid conduit (15) is connected to the upper barrel (11) can include any means known in the art. For example, the two components can be engaged to one another using a threaded connection, by welding, by crimping, using a forced or interference fit, using one or more fasteners, or by using any other means of attachment known in the art.
As shown, the downwell end of the pump (10) includes a lower barrel (12). As depicted in FIGS. 1 and 3, the inside diameter of the lower barrel is preferably smaller than the inside diameter of the upper barrel (11). At the downwell end of the pump, an inlet port (33) is located, which communicates production fluid from the reservoir (3) into the lower barrel (12). A standing check valve (42) is shown positioned at the inlet port (33), below the plunger assembly (20), and provides selective fluid communication between the production fluid in the reservoir (3) and the lower barrel (12). As explained in more detail below, the standing check valve (42) allows production fluid from the reservoir (3) to flow into the lower barrel (12) and prevents the flow of fluid from within the lower barrel (12), outwardly, into the reservoir (3).
FIGS. 1 and 2 depict a transition portion (14) located between the upper barrel (11) and the lower barrel (12), which allows the larger diameter upper barrel (11) to connect to a smaller diameter lower barrel (12). The transition section (14) can contain a plurality of fluid ports or annular ports (13), which allow fluid communication between the tubing string annulus (7) and the central cavity (53), which is a volumetric area that will be described in more detail below. It should be understood that while the annular ports (13) are shown within the transition portion (14) of the upper barrel, such ports are preferably located below the lowermost position of the upper plunger (21) and above the uppermost position of the lower plunger (22). The annular ports (13) can provide fluid communication between the production fluid in the tubing string annulus (7) and the central cavity (53), allowing the pressurized fluid to enter the pump (10), to lift the plunger assembly (20), and to exit the pump (10) as the plunger assembly (20) is forced down.
Referring specifically to the plunger assembly (20), FIG. 1 depicts a plunger assembly comprising an upper plunger (21), a shaft (23), a lower plunger (22), and a traveling valve (41). The plunger assembly (20) is movably positioned within the pump (10). Specifically, the upper plunger (21) moves within the space inside the upper barrel (11), and the lower plunger (22) moves within the space inside the lower barrel (12). The upper and lower plungers (21, 22) are connected by a shaft (23). The plunger assembly (20) may be of unitary construction or of various connected assemblies, and may be formed from any suitable material (e.g., metal or a metal alloy), preferably a material that is corrosion resistant, especially against salt water.
As further depicted in FIG. 1, several volumetric areas exist within the pump (10). The area within the upper barrel (11), formed upwell of the upper plunger (21) and below the fluid conduit (15), is termed the upper cavity (51). The area within the lower barrel (12), formed downwell of the lower plunger (22) and above the standing check valve (42), is termed the lower cavity. The area within the upper and lower barrels (11, 12), formed between the upper plunger (21) and the traveling check valve (41) is termed the central cavity (53). As the plunger assembly (20) moves upwell and downwell within the pump (10), these volumetric areas are simultaneously enlarged or reduced.
Referring again to the plunger assembly (20) depicted in FIGS. 1 and 2, in an embodiment, the upper plunger (21), located on the upwell end of the plunger assembly (20), can be a solid cylindrical member, and can include sealing elements on the outside surface to prevent fluids from breaching the seal during pump operation. Usable sealing means are described in more detail below.
The lower plunger (22), depicted in FIGS. 1 and 3, can include a cylindrical member located at the downwell end of the plunger assembly (20). Unlike the upper plunger (21), the lower plunger (22) is configured to allow production fluids to bypass the lower plunger (22) at specific stages of pump operation. Consequently, the lower plunger (22) may have a fluid passageway through at least a portion of its length. A traveling check valve (41) is shown at the bottom of the lower plunger (22) for providing selective fluid communication between the lower cavity (52) and the central cavity, (53) through the fluid passageway of the lower plunger (22). Specifically, the traveling valve (41) is a flow control valve, which prevents fluid flow in the downwell direction and allows fluid to pass in the upwell direction, as the plunger assembly (20) is moving in the downwell direction. The traveling check valve (41) can be of any type, including a valve having a gravity actuated flow restricting element, such as a ball (as depicted in FIG. 1), such that gravity can retain the flow restricting element on the valve seat. The traveling check valve (41) could also include a spring assisted check valve, wherein a spring retains the flow restricting element on the valve seat, or other types of valves known in the art.
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 FIG. 2, may be provided as a single piece, as multiple pieces, or spring backed. For optimal operation, the seals can be sized to close the space between the upper barrel (11) and the upper plunger (21) and possess the ability to adjust in height as the upper plunger (21) shifts positions relative to the upper barrel (21) during operation. This can be achieved, for example by incorporating sealing elements, comprising flexible material, which are then compressed as the upper plunger moves relative to the barrel walls. Another example is a sealing ring (26) that floats in a deep groove having a smaller diameter than the inside diameter of the sealing ring (26). As depicted in FIG. 2, the sealing rings (26) are pushed by the upper barrel (11) wall into the grooves on one side of the upper plunger (21) and extend out of the groove on the other side, as the upper plunger (21) moves radially, within the upper barrel (11), relative to the longitudinal axis of the upper barrel (11). In still another embodiment, the sealing ring (26) may be centered about the upper barrel (11) by a spring. It should be understood that the sealing means described can include any type and/or combination of sealing elements and any arrangement thereof, to optimize performance of the pump. It should be understood that either the upper plunger (21), or both plungers (21, 22), may include the clearance and sealing configuration, as described above. In an embodiment, the lower plunger can contain little to no clearance and no additional sealing elements, and can rely only on metal-to-metal sealing between the lower plunger (22) and lower barrel (12).
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 FIGS. 1 and 2, the length and the thin walls of the pump barrels (11, 12), the large clearance fit (25) between the upper barrel (11) and the upper plunger (21), as well as the long length of the plungers (21, 22), enable the pump (10) to flex and withstand significant bending in the wellbore while maintaining fluid sealing, which further allows the pump (10) to be lowered through tight corners and to properly operate to pump fluids, while positioned within deviated wells.
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 FIG. 1, in a common oilfield application, the pump (10) would be connected to the bottom of a tubing string (5), within the reservoir (3) fluid to be produced. A pressure source, such as a hydraulic pump (not shown), would be connected at the surface to the tubing string (5) so as to selectively apply pressure into the tubing string (5), which actuates the downhole pump (10). The conduit (15) can be positioned within the tubing string (5) to allow communication of the balancing fluid with the upper cavity (51). A balancing fluid, which may comprise fluids such as salt water or other fluid, is contained within the upper cavity (51) and the conduit (15). Typically, the balancing fluid inside the upper cavity (51) is not externally pressurized and relies upon the hydrostatic column pressure, determined by the height of the fluid in the upper cavity (51) and the conduit (15) between the pump (10) and the surface of the well (2). When the plunger assembly (20) is in the lowest (e.g., downwell) position, there is a substantial balance of the hydrostatic pressures in the tubing string and the conduit.
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 FIGS. 4 through 6 is discussed below, can be repeated for extended periods of time to produce a well.
FIG. 1 shows the plunger assembly (20) in its lowermost position with the well fluid and the balancing fluid being static. When the pump is positioned as shown in FIG. 1, only hydrostatic pressure is present about the upper plunger (21). The standing valve and the traveling valve are both closed and no fluid communication takes place.
FIG. 4 shows the plunger assembly (20) moving upward. As the surface unit (not shown) is activated, fluid is pumped down the tubing string (5) (as shown by the arrows) into the annulus (7) surrounding the upper barrel (11), and through the annular ports (13) ports into the central cavity (53), between upper and lower plungers (21, 22); moving the plunger assembly (20) upward, due to the larger diameter of the upper plunger (21) as opposed to the diameter of the lower plunger (22). At substantially the same time, the balancing fluid is forced out of the upper cavity (51) and upward into the conduit (as shown by the arrows). The traveling valve (41) remains closed, and the standing valve (42) opens to allow production fluid (e.g., hydrocarbons) from the reservoir (3) to be drawn through the inlet port (33), and into the lower barrel (12) (as shown by the arrows).
FIG. 5 shows the plunger assembly (20) at the uppermost part of the upstroke. The surface unit (not shown) is still pressurizing the tubing string (5), maintaining the position. The upper barrel, which now comprises most of the central cavity, is filled with the pressurized fluid from the tubing string (5), while the lower barrel (12), which now comprises most of the lower cavity (52), is filled with fluid drawn from the reservoir (3). The fluid from the upper cavity (51, shown in FIGS. 4 and 6) has been forced upwell into the fluid conduit (15). Both the traveling valve (41) and the standing valve (42) are closed.
FIG. 6 shows a plunger assembly (20) moving in a downwell direction in response to pressure from the balancing fluid against the upper plunger (21). After the plunger assembly (20) reaches the top of its stroke within the pump (10), as depicted in FIG. 5, the surface pump unit (not shown) is disconnected from the tubing string (5), releasing the pressure that it generated. The hydrostatic pressure of the fluid column in the fluid conduit (15) is now greater than the hydrostatic pressure of the fluid column in the tubing string (5). As a result, the plunger (20) assembly is forced in a downwell direction by the pressure differential about the upper plunger (21). The standing valve (42) is closed, preventing fluid in lower cavity (52) from escaping into the reservoir (3). At the same time, the traveling valve (41) opens, allowing fluid to communicate from the lower cavity (52) into the central cavity (53). The fluid in the central cavity (53) is then forced out of the pump (10) into the annulus (7) of the tubing string (5) through the annular ports (13) (as shown by the arrows) to be produced at the surface.
FIG. 1 shows the plunger assembly (20) at the bottom of the downstroke. Once the upper plunger (21) makes contact with the bottom of the upper barrel (11), the cycle can start again, as described above.
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

What is claimed is:

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.