Patent Application
20160265521
The present invention relates to pump assemblies and more particularly to pump systems including one or more positive displacement pumps. Such pump systems may be used, for example, in chemical industries, such as the oil and gas industry, and in others as are known by those of skill in the art. The pump systems and methods of using the same disclosed herein may be particularly suitable for creating artificial lift in oil and/or gas wells, as well as for general well pumping, mining, industrial processes, reverse osmosis, chemical processing, and others.
In certain oil wells, the reservoir may not have enough pressure to push the oil up the well bore to the surface. Even in productive wells, insufficient pressure in the reservoir becomes an increasingly serious problem over the well's production life. As a consequence, the fluids produced by the well may need to be pumped to the surface. There are several methods for pumping this fluid to the surface, which are often referred to as “artificial lift” methods.
For example, gas wells may produce both gas and liquid. Generally, when a well is first drilled, it produces enough gas at sufficient pressure such that liquids are swept out of the well by the gas flow. As the reservoir pressure depletes, however, the gas flow rate declines. Eventually, the gas flow rate declines such that the velocity of gas is insufficient to sweep out the liquid from the well. Some gas may still escape in a bubble flow state for a period of time. However, as the liquid column rises, the pressure caused by the liquids in the well bore will eventually cause the gas flow to cease. Thereafter, fluids, including water and oil, have to be lifted up the well to the surface to create a clear passage for the gas to escape from the well.
Pumping fluid from horizontal gas wells may be particularly challenging. Horizontal wells are generally vertical up to a certain depth after which the bore turns and continues more or less horizontally. The lowest point of the turn may be referred to as the well “heel.” It is common for the horizontal portion of these wells to have a slight upward inclination (or “toe up”), which may cause pooling of fluids in the heel of the well. Consequently, the deviated geometry of the well may make evacuation of fluid from the well very challenging.
One form of artificial lift system is the “sucker-rod” pumping system, which may be used in both oil and gas wells. The sucker-rod pumping system uses a down-hole pump powered by a surface actuation system. The actuation system and pump are connected by a rod that runs down the well. The traditional sucker-rod pumping system has a “standing valve” and a “traveling valve.” The traveling valve reciprocates up and down while the standing valve remains stationary. The actuation system typically has a system of counterweights that counterbalance the weight of the rod. However, as described in U.S. Pat. No. 90,157 (“Devirs”), the sucker-rod pumping system suffers from a number of problems. For example, because sucker-rod pumping systems require a rod that runs down the well, they can only be used in straight wells. Sucker-rod pumps, therefore, cannot be used effectively in horizontal or tortuous wells (i.e. any well that substantially deviates from a straight path) because the pump cannot overcome the frictional losses of the rod against the production tube. Further, the use of sucker-rod pumping systems in mildly deviated wells can result in failure of the production tube and/or the rod because the rod requires a straight path to avoid contacting the production tube. Additionally, the sheer mass of material in both the rod and counterweights creates high installation and servicing costs.
Gas lift is another method of artificial lift used in gas wells that produce a large volume of fluid. In gas lift methods, compressed gas, also known as “lift gas,” is pumped into the liquid in the well where it is absorbed by the liquid and causes bubbles in the liquid. This lightens the liquid inside the well, allowing gas flowing from the reservoir to more readily bring the liquid to the surface. Once at the surface, the lift gas can be recycled. Gas lift requires relatively little surface equipment and can be implemented in deviated and horizontal wells. However, gas lift is only effective in relatively shallow wells with substantial reservoir pressure.
Plunger lift is yet another method of artificial lift. For example, U.S. Pat. No. 2,676,547 (“Knox”) describes systems and methods for plunger lift wherein plungers are inserted into the well to create a seal and thus increase the efficiency of sweeping fluid from the well. The plunger is propelled by reservoir pressure, sweeping liquid in its path. Plunger lift relies on reservoir pressure to function, however, and is therefore less effective for deeper wells. As such, plunger lift methods become ineffective as the reservoir pressure declines.
Chemical foaming is yet another method of artificial lift used in gas wells that produce small volumes of liquid (primarily water). As described in U.S. Pat. No. 8,950,494 (“Nguyen et al”) a chemical foaming agent, often in the form of a soap stick, may be introduced to the well while it is in a bubbling production condition. The liquid then becomes foam, which is much less dense and which can be swept out of the well by gas flowing at lower velocity than would otherwise be possible. Similar to plunger lift, chemical foaming relies on reservoir pressure, and will therefore be less effective for deeper wells because chemical foaming stops working as reservoir pressure declines. In addition, chemical foaming does not produce foam in wells of certain chemistry.
Gas lift, plunger lift and chemical foaming each suffer from a common disadvantage: they each require reservoir energy to remove liquids from the well. As the well depletes, the reservoir energy becomes insufficient to sweep liquid from the well using these methods. Once this occurs, additional energy is required to pump the fluid from the well.
Artificial lift may also be provided in the form of an electric submersible pump (“ESP”). An ESP typically includes an electric motor that drives a turbine. An armored electrical cable may provide power to the motor from the surface. ESPs are typically used for lifting large volumes of liquid and are able to operate in deviated and horizontal wells. However, ESPs suffer from several disadvantages. For example, they are costly and prone to turbine erosion and cavitation. Turbine erosion and cavitation are exacerbated in wells with multi-phase characteristics (the presence of gas and/or liquids and/or solids). Consequently, these wells often require the use of complex gas separator and/or filtration systems. Further, ESPs are not only costly to install, but they also have high servicing costs because they need frequent rotor replacements.
Progressive cavity pumps (“PCPs”) are another type of positive displacement pump used in artificial lift. A PCP consists of a helical rotor and a twin helical rubber stator. The rotor and stator seal tightly together forming a series of fixed volume cavities between the rotor and stator that progress along the pump as the rotor turns. In this way, liquid contained in these cavities is pushed through the pump. PCPs are typically powered from the surface via a rotating rod; however they can also be driven electrically once down the well. Electric drive of these pumps allows them to be used in deviant wells (i.e. wells that do not follow a straight path). Further, PCPs are particularly well-suited to pumping a mixture of solids and liquids. However, PCPs are expensive and can only generate enough pressure to operate in relatively shallow wells.
As described in U.S. Pat. No. 8,955,599 (“Quigley”) and U.S. Pat. No. 8,726,981 (“Berry”), PCPs can be configured in series to create greater pressure; however such an arrangement is very costly and may increases the service costs of the well due to pump failure. In such arrangements, if any pump in the series fails, the remaining pump(s) will not be able to generate enough pressure to lift fluids from the well.
A hydraulic pump may also be used to provide artificial lift. Hydraulic pumps are similar to sucker-rod lifter pumps, except that they are powered by hydraulic fluid from the surface rather than a rod actuation method, as described in U.S. Pat. No. 8,276,658 (“Cox”), U.S. Pat. No. 8,235,107 (“Fesi”), and U.S. Pat. No. 4,861,239 (“Simmons”). Hydraulic pumps can therefore be used in deviant and horizontal wells. However, hydraulic pumps still have the disadvantage of being energy inefficient because of both frictional losses of hydraulic fluid traveling down the well bore and the need to lift the spent hydraulic fluid back to the surface.
As described above, known methods of artificial lift suffer from a number of problems and disadvantages. Industry use of deviant and horizontal wells in gas production has become more common, and those wells will eventually go into decline and need artificial lift in order to stay productive. Due to the recent emergence of declining deviant and horizontal gas wells, and the technical challenges posed by these wells, no pumping system presently exists that is well-suited to deliquification of these wells. Therefore, described herein are systems and methods capable mitigating or obviating problems and disadvantages of known deliquification methods and systems.
In a first embodiment, a pump system comprises: a first pump assembly, comprising: a first electric motor configured to actuate a first pump; a first inlet valve configured to draw fluid from a first low-pressure conduit and into the first pump; and a first outlet valve configured to expel the fluid from the first pump and into a first high-pressure conduit; and a second pump assembly, comprising: a second electric motor configured to actuate a second pump; a second inlet valve configured to draw fluid from a second low-pressure conduit and into the second pump; and a second outlet valve configured to expel the fluid from the second pump and into a second high-pressure conduit, wherein the first low-pressure conduit is in fluid connection with the second low-pressure conduit, and wherein the first high-pressure conduit is in fluid connection with the second high-pressure conduit.
In some embodiments, the first pump and the second pump are positive displacement pumps.
In some embodiments, the first pump and the second pump are progressive cavity pumps.
In some embodiments, the first pump and the second pump are electric submersible pumps, each of the first pump and the second pump comprising at least one turbine.
In some embodiments, the first pump comprises a first piston and a first cylinder, the second pump comprises a second piston and a second cylinder, the first inlet valve is configured to draw fluid from the first low-pressure conduit into the first cylinder when the first piston moves in a first direction within the cylinder, the second inlet valve is configured to draw fluid from the second low-pressure conduit into the second cylinder when the second piston moves in the first direction within the cylinder, the first outlet valve is configured to expel fluid from the first cylinder into the first high-pressure conduit when the first piston moves in a second direction within the cylinder, opposite the first direction, and the second outlet valve is configured to expel fluid from the second cylinder into the second high-pressure conduit when the second piston moves in the second direction within the cylinder.
In some embodiments, the pump system further comprises: a first screw mechanism coupled to the first electric motor and to the first piston, wherein rotation of the screw mechanism by the first electric motor is configured to causes motion of the piston within the first chamber.
In some embodiments, the first screw mechanism comprises an axial channel.
In some embodiments, the pump system further comprises: a speed reduction mechanism coupling between the electric motor and the first screw mechanism.
In some embodiments, the first low-pressure conduit is located outside the first pump assembly, and wherein the second low-pressure conduit is located outside of the second pump assembly.
In some embodiments, the first low-pressure conduit is located inside the first pump assembly, and wherein the second low-pressure conduit is inside of the second pump assembly.
In some embodiments, the first high-pressure conduit is located outside the first pump assembly, and wherein the second high-pressure conduit is located outside of the second pump assembly.
In some embodiments, the first high-pressure conduit is located inside the first pump assembly, and wherein the second high-pressure conduit is inside of the second pump assembly.
T In some embodiments, the first high-pressure conduit is located outside the first pump assembly, and wherein the second high-pressure conduit is located outside of the second pump assembly.
In some embodiments, the first high-pressure conduit is located inside the first pump assembly, and wherein the second high-pressure conduit is inside of the second pump assembly.
In some embodiments, the pump system further comprises: a manifold connected to the second pump assembly.
In some embodiments, the pump system further comprises: a production tube connected to the manifold.
In some embodiments, the production tube is a coiled tube.
In some embodiments, the first electric motor comprises a first rotor and a first stator, and wherein the first stator comprises a plurality of axial stator channels configured to carry the fluid.
In some embodiments, the plurality of axial channels in the first stator are in fluid connection with the first high-pressure conduit.
In some embodiments, the first rotor comprises a plurality of axial rotor channels, and wherein the plurality of axial rotor channels are in fluid connection with the first low-pressure conduit.
In some embodiments, the first electric motor is a brushless permanent magnet type motor, and wherein the second electric motor is a brushless permanent magnet type motor.
In some embodiments, the first pump assembly and the second pump assembly are arranged in series.
In some embodiments, the first pump assembly and the second pump assembly are installed within a well bore.
Embodiments of improved pump systems may include several advantageous features, including: one or more pump assemblies that are capable of pumping multiphase fluids found in various types of wells, wherein each pump assembly may be joined in parallel resulting in both higher system reliability (through redundancy) and more flexible flowrate and pressure capabilities than prior art pump systems. Embodiments described herein are particularly well suited to down-hole well pumping applications with tight well bore geometric constraints, and where well production characteristics are highly variable, which requires both competitive pump economics and variable capacity for different wells. Furthermore, systems including modularly joined pumps may allow for utilization of fewer pump types while being able to operate in an increased number of well types with a wide range of flowrate and pressure requirements.
These and other benefits will become apparent from a consideration of the ensuing description and accompanying drawings.
For example, as piston (6) moves in a first direction within cylinder (12), the volume within chamber (13) increases and causes inlet valve (10) to open. When inlet valve (10) opens, it allows fluid to be drawn into chamber (13). In some embodiments, contents flow into chamber (13) through inlet valve (10) from adjacent low-pressure cavity (14).
When piston (6) moves in a second, opposite, direction, inlet valve (10) closes and outlet valve (9) opens and the contents of the chamber (13) are expelled through outlet valve (9). In some embodiments, contents within chamber (13) flow through outlet valve (9) into a radial channel (15) in cylinder (12), and thereafter into an annular cavity (16) in stator (1), which is connected to one or more axial stator channels (17) (not shown in
When piston (6) moves axially in a reciprocating fashion within cylinder (12), fluid is displaced from the low-pressure conduit (in this example, rotor (21), channels (20), annular space (19), axial rotor channels (18) and low-pressure cavity (14)) to a high-pressure conduit (here, axial stator channels (17)).
In some embodiments, rotor (2) and stator (1) may form an electric motor. The electric motor formed by rotor (2) and stator (1) may be, for example, a brushless permanent magnet type motor where the permanent magnets (8) in the rotor are propelled by the magnetic fields of the induction coils (11) in the stator (1). Other embodiments may use different motor types, including, for example: open frame servo motors, induction motors, direct current brushed motors, standard frame servo motors, and stepper motors. In some embodiments, “off-the-shelf” motors with industrial application may offer significant cost advantages compared to low volume, highly specialized motors that are typically used for subterranean oil field applications, such as for ESPs. “Open Frame” servo motors (i.e. servo motors with an open architecture including a hollow, un-mounted rotor (2)) may be particularly well suited for embodiments of pump systems as described herein because of their high power density, and the ability to flow fluid through the center of rotor (2).
In the embodiment depicted in
In some embodiments, piston (6) may be moved axially by means of a screw mechanism. For example, in the embodiment depicted in
Rotor (2) may be controlled by various means, including, for example by a programmed active feedback system or by a switching system which causes piston (6) to reciprocate in cylinder (12). When piston (6) reciprocates within cylinder (12) fluid is displaced from the low-pressure conduit (here, rotor (21), channels (20), annular space (19), axial rotor channels (18) and low-pressure cavity (14)) to the high-pressure conduit (here, axial stator channels (17)).
A motor control system can be located down hole or on the surface. For embodiments with downhole controls, the controls can either be integrated into the pump or can be located separately. Further, electrical power may be supplied to the motor control system from the surface. When power is supplied, the motor control system may be activated and the motor may begin to reciprocate. If several programs are required for different functions, a signal to change programs may be transmitted from the surface by electrical connection to the surface or through sonographic communication through the fluid column to the surface. Motor controls have various levels of sophistication, for example, from encoder based active feedback controls to hall-effect amplification with limit switch initiated phase shift. Down-hole controls may have several advantages, including fewer fragile electrical connections in the well bore and simplified pump design.
In embodiments with surface controls both power and control signals may be supplied from the surface, for example, by electrical connection. Surface controls may have several advantages, including the ability to perform diagnostic tests, the ability to readily load new pump control programs, and the ability to replace faulty control hardware.
The volume and pressure generated by embodiments of pump assembly (100) may be governed by several factors, including, for example, the torque characteristics of rotor (2), the pitch of screw (24), the rotational velocity of rotor (2), and the bore radius of cylinder (12).
The pressure and flowrate generated by each pump might be calculated with the following equations:
Where T is continuous rotor (2) operating torque, R is bore radius of cylinder (12) (assuming a cylindrical bore), E is the screw efficiency factor, “Pitch” is the linear distance traveled for each revolution of the screw (24) and M is the rotational velocity of rotor (2).
For example an embodiment of the pump assembly with a ⅜ inch cylinder bore diameter, employing a 13/64 inch pitch ball screw with a screw efficiency factor of 0.9 and a continuous motor operating torque of 3.6 Nm may be able to generate 8000 psi of pressure. Further, if the rotor velocity M is 50 revolutions per second then the pump assembly should flow approximately 33 liters per hour or 5 barrels per day.
In the embodiment depicted in
The one or more axial stator channels (17) in stator (1) are depicted in
When piston (40) moves repeatedly in a first direction followed by a second direction, i.e., in a reciprocating fashion, within cylinder (36), fluid is displaced from inlet valve (37) to outlet valve (43).
In some embodiments, piston (40) may be moved axially by means of a screw mechanism. In other embodiments, for example, a belt and cone mechanism may be used.
In the embodiment depicted in
In the embodiment depicted in
As rotor (26) is rotated, ball screw (32) is rotated and ball nut (33), piston anchor (35) and piston (40) move axially. The axial motion of piston (40) causes a change in volume of chamber (41). Thus, as the piston (40) is reciprocated, fluid is displaced through inlet valve (37) to outlet valve (43).
In the embodiment depicted in
In further embodiments, particularly where the screw and rotor are separate components, a reduction mechanism may be placed between the screw and the rotor. A reduction mechanism may take the form of planetary gears or a belt and cone system reducer (such as those produced by RISE ROBOTICS™).
In further embodiments, the piston and screw may be controllably connected with a hydraulic reducer.
In further embodiments, the screw may pass through the rotor allowing for a double actuating pump with a piston and cylinder mechanism mounted to each end of the screw.
An exemplary multi-pump embodiment is depicted in
As depicted in
Alternate embodiments may contain more than two pump assemblies, for example: three or more pump assemblies. Each pump assembly in such a pump system may pump with enough pressure to lift a fixed volume of fluid to the surface at a particular flowrate. Therefore, each additional pump that is added to a pump system may contribute additional flowrate to the pump system. Consequently the volume flowrate of the pump system may be varied by altering the number of pumps in the system rather than by varying the design of the pump. This has the advantage of being able to use standard pumping modules to size pumping systems appropriately to wells with varying production characteristics. Furthermore, using standard pumping modules may have operational advantages including limiting the number of stock keeping units and increasing the number of inventory turns compared to other methods known in the art.
Schematics of alternate embodiments of multi-pump systems using parallel low-and high-pressure conduits are shown in
A pump system, such as those described above, may be deployed on the end of a production tube. The production tube can be, for example, of the threaded type (commonly used in oil and gas applications) or a continuous tube, often referred to as “coiled tubing.” Coiled tubing is a long continuous length of tubing that can be coiled up and stored on a reel. This method of deployment has several advantages, including faster and more economical pump deployment compared to other deployment methods.
Notably, the preceding description only describes certain, exemplary embodiments of pump systems and methods for using the same. One skilled in the art, without departing from the spirit and scope of the preceding description, may make various changes and modifications of the pump system and to adapt it to various components and configurations. The preceding specifically described embodiments are, therefore, to be construed as merely illustrative, and not limiting the remainder of the disclosure in any way whatsoever, and that it is intended to cover various modifications and equivalent arrangements included within the scope of the appended claims.
This application claims the benefit of U.S. Provisional Application No. 62/131,997, filed Mar. 12, 2015, the entire content of which is hereby incorporated by reference in its entirety.
| Number | Date | Country | |
|---|---|---|---|
| 62131997 | Mar 2015 | US |
