Downhole Pump

Abstract

A pump for stimulating production from a well comprising: tubing with a power tube extending therethrough; a surface unit with a surface pump hydraulically connected to the power tube and to a power fluid reservoir; a downhole unit having a body (preferably cylindrical) received within the tubing and defining therein a power chamber hydraulically connected to the power tube, a pump chamber and a suction chamber each hydraulically connected to the production fluid and to each other a port from the body hydraulically connected to the tubing; and a seal hydraulically separating the tubing above the downhole unit from the tubing below the downhole unit. The chambers defined between a series of moving pistons and fixed dividers.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

[0001] This application is a continuation-in-part of application Ser. No. 19 / 034,122 filed Jan. 22, 2025.FIELD OF THE INVENTION

[0002] The present invention relates generally to pumping assemblies used for oil well production stimulation applications.BACKGROUND

[0003] Artificial lift pumps are essential for increasing the flow of fluids, such as oil or water, from production wells when natural reservoir pressure is insufficient. These pumps enhance the productivity of wells that, for example, are no longer able to produce fluids at economic rates due to declining reservoir pressure. By mechanically lifting fluids to the surface, they enable continued extraction from wells that would otherwise be non-productive. Various types of artificial lift pumps, including sucker rod pumps and hydraulic pumps, are employed based on specific well conditions and fluid characteristics. These systems are designed to handle different production rates, fluid viscosities, and well configurations, ensuring optimal recovery from the reservoir. They play a role in maintaining the economic viability of oil and water production operations, effectively extending the life of wells and maximizing resource extraction.

[0004] Artificial lift pumps are essential for increasing the flow of fluids, such as oil or water, from production wells when natural reservoir pressure is insufficient. Two common types of these pumps are sucker rod pumps and hydraulic pumps.Sucker Rod Pumps

[0005] Sucker rod pumps, also known as beam pumps, are mechanical lift systems commonly used in oil wells. A surface unit, or pumpjack, converts rotary motion into vertical reciprocating motion. This motion is transmitted downhole via a series of connected rods called the sucker rod string. At the bottom, the sucker rod string connects to a downhole pump assembly located in the production tubing, consisting of a plunger and barrel. The upstroke of the plunger creates a vacuum, drawing fluid into the pump chamber through a one-way valve and simultaneously pushes production fluid out of the well. The downstroke then reloads the production chamber with production fluid to be pushed out on the next upstroke. Sucker rod pumps are versatile and can handle a range of production rates and fluid characteristics. They are widely used due to their simplicity, durability, and effectiveness in lifting oil.

[0006] Hydraulic pumps use pressurized fluid to power downhole pumps, providing an alternative to mechanical lifting systems. A surface pump sends pressurized hydraulic power fluid, which can be oil or water, down the well through a separate conduit. This fluid operates a downhole hydraulic motor, driving the pump mechanism, which can be a piston pump, jet pump, or other types of hydraulic pumps. The downhole pump lifts the production fluid to the surface. Hydraulic pumps are suitable for wells with high depths and deviated or horizontal wellbores. They can handle wells with high sand content or other solids that might wear down mechanical parts. These systems are flexible and can be adjusted to different production rates and fluid properties by modifying the surface pump's pressure and flow rate.

[0007] However, sucker rod pumps present several significant challenges. Health, Safety, and Environmental (HSE) concerns are paramount due to the large swinging weights and suspended loads involved in their operation. The constant movement of these weights poses serious risks to personnel, and stuffing boxes are prone to leakage, presenting environmental hazards and maintenance challenges.

[0008] Economically, sucker rod pumps are an expensive option for the final lift method in most wells. The high cost is not only due to the initial installation but also because of ongoing maintenance. The rods within the system tend to wear out the tubing over time, leading to frequent replacements of both rods and tubing, which is costly and time-consuming.

[0009] Deviation in wellbore paths exacerbates the wear and parting of the rods. When wells are not perfectly vertical, the rods experience increased friction and stress, accelerating wear of both rods and tubing and increasing the likelihood of rod failure. Deviations complicate the maintenance process and increases operational costs.

[0010] The physical footprint of sucker rod pumps presents another challenge. In locations where wellheads are closely spaced, finding adequate space to install and work on these pumps can be difficult. The large surface equipment required for these pumps takes up significant space, making it challenging to operate efficiently in fields with limited surface area.

[0011] In addition to their footprint, sucker rod pumps have to have as much travel on the surface as takes place inside the pump downhole. For example, Rotaflex advertises its “long stroke pumping unit” as having stroke lengths up to 366 in. (9.3 m). That is a structure more than 30 feet tall. Such a structure is expensive to transport and set up as well as potentially dangerous given the heights, and it requires substantial clearance overhead. Surface owners may view this towering object as an eye sore on their land. The stroke length of a sucker rod pump is thus limited, or at least must take careful account of what that stroke length will require in terms of equipment above ground on the well pad.Hydraulic Pumps

[0012] Hydraulic pumps, while offering an alternative to mechanical lifting systems, also come with several significant challenges. One major concern is related to health, safety, and environmental issues. Hydraulic pumps often operate at high pressures on the surface, which can pose significant risks if not properly managed. This high-pressure environment necessitates stringent safety protocols to prevent accidents and equipment failure.

[0013] Hydraulic pumps typically use a power fluid that is eventually exhausted into the production stream and must be separated out again. This process can complicate production operations and reduce overall efficiency. Furthermore, the power fluid must be free of solids to prevent erosion of the pump parts. If the power fluid contains solids, it can cause significant wear and tear on the pump components, leading to increased maintenance and replacement costs.

[0014] Similar to rod pumps, hydraulic pumps also face issues with sand and debris. These materials can cause blockages and damage to the pump mechanisms, reducing their operational lifespan and reliability. Effective filtration and regular maintenance are essential to mitigate these issues, but they add to the operational complexity and cost.

[0015] As such, there is a need to address the previously discussed challenges.DRAWINGS

[0016] To describe the manner in which the above-recited and other advantages and features of the disclosure can be obtained, a more particular description of the principles briefly described above will be rendered by reference to specific embodiments thereof which are illustrated in the appended drawings. Understanding that these drawings depict only exemplary embodiments of the disclosure and are not therefore to be considered to be limiting of its scope, the principles herein are described and explained with additional specificity and detail through the use of the accompanying drawings in which:

[0017] FIG. 1 shows a system according to the present invention with the pump on an upstroke according to some aspects of the disclosure.

[0018] FIG. 2 shows a system according to the present invention with the pump on a downstroke according to some aspects of the disclosure.

[0019] FIG. 3 shows a downhole unit according to the present invention with the pump on the upstroke according to some aspects of the disclosure.

[0020] FIG. 4 shows a downhole unit according to the present invention with the pump on the downstroke according to some aspects of the disclosure.

[0021] FIG. 5 illustrates various aspects of the casing / tubing and formations according to some aspects of the disclosure.

[0022] FIG. 6 illustrates an alternative embodiment of the downhole unit according to another aspect of the present invention with the pump on the upstroke.

[0023] FIG. 7 illustrates an alternative embodiment of the downhole unit according to another aspect of the present invention with the pump on the downstroke.

[0024] FIG. 8 illustrates an alternative embodiment of the downhole unit with a flexible power tube section disposed within the pump's body.

[0025] FIG. 9 illustrates a simplified embodiment of the downhole unit in an upstroke.

[0026] FIG. 10 illustrates a simplified embodiment of the downhole unit in a downstroke.DETAILED DESCRIPTION

[0027] Various examples of the disclosure are discussed in detail below. While specific implementations are discussed, it should be understood that this is done for illustration purposes. A person skilled in the relevant art will recognize that other components and configurations can be used without parting from the spirit and scope of the disclosure. Thus, the following description and drawings are illustrative and are not to be construed as limiting. Numerous specific details are described to provide a thorough understanding of the disclosure. However, in certain instances, well-known or conventional details are not described in order to avoid obscuring the description.

[0028] The terms used in this specification generally have their ordinary meanings in the art, within the context of the disclosure, and in the specific context where each term is used. Alternative language and synonyms can be used for any one or more of the terms discussed herein, and no special significance should be placed upon whether or not a term is elaborated or discussed herein. In some cases, synonyms for certain terms are provided. A recital of one or more synonyms does not exclude the use of other synonyms. The use of examples anywhere in this specification including examples of any terms discussed herein is illustrative and is not intended to further limit the scope and meaning of the disclosure or of any example term. Likewise, the disclosure is not limited to various embodiments given in this specification.

[0029] Additional features and advantages of the disclosure will be set forth in the description that follows, and in part will be obvious from the description, or can be learned by practice of the herein disclosed principles. The features and advantages of the disclosure can be realized and obtained by means of the instruments and combinations particularly pointed out in the appended claims. These and other features of the disclosure will become more fully apparent from the following description and appended claims or can be learned by the practice of the principles set forth herein.Overview

[0030] The present disclosure includes embodiments of pump systems and methods for enhancing production from a well. The descriptions in this overview are illustrative of some of the aspects and techniques relating to the present invention and should not be read as limiting.

[0031] The invention may relate to a pump for stimulating production of oil and / or gas from an underground formation. The invention is expected to be used in a well having tubing with a power tube extending therethrough containing a production fluid with a surface unit near a wellhead including a surface pump hydraulically connected to the power tube and to a power fluid reservoir. There will also be a downhole unit which preferably has a cylindrical body sized to be received within the tubing and further defining therein a power chamber hydraulically connected to the power tube, a pump chamber and a suction chamber both hydraulically connected to the production fluid and to each other, the power chamber defined between a fixed divider, and a first piston slidingly and sealingly disposed within the cylindrical body, the pump chamber located adjacent to the power chamber and defined between the fixed divider, and a second piston slidingly and sealingly disposed within the cylindrical body and preferably connected to the first piston end at a fixed distance so that they move in tandem and having a first check valve disposed therein. Further, it is expected that the suction chamber may be located adjacent to the pump chamber and defined between the second piston, and a fixed lower divider defining a second check valve therein. An outlet from the cylindrical body hydraulically connects it to the wellhead, and a seal hydraulically separates the tubing above the downhole unit from the tubing below the downhole unit so that when production fluid is forced out of the pump chamber, it proceeds up the tubing toward the wellhead.

[0032] Alternatively, the invention may relate to a pump for stimulating production from an underground formation with the various components described above arranged in a different order. For example, the downhole unit may be disposed closer to the wellhead than the production zone having a cylindrical body sized to be received within the tubing and further defining therein a power chamber hydraulically connected to the power tube, a pump chamber and a suction chamber both hydraulically connected to the production fluid and to each other may have the following alternative arrangement. The power chamber may be defined between a fixed upper divider, and a first piston slidingly and sealingly disposed within the cylindrical body; the pump chamber located adjacent to the power chamber and defined between the first piston, and a fixed lower divider having a first check valve disposed therein; and the suction chamber located adjacent to the pump chamber and defined between the fixed lower divider, and a second piston slidingly and sealingly disposed within the cylindrical body and connected to the first piston at a fixed distance so that they move in tandem and having a first check valve disposed therein. The remaining components may be assembled consistent with the description immediately above.

[0033] Alternatively, the invention may relate to a method for pumping fluid using a hydraulic pump disposed within a wellbore. The method may comprise forcing power fluid from a reservoir tank using a surface pump at a wellhead; pumping the power fluid into a power fluid chamber within the pump forcing it to expand from a first volume to a larger second volume; simultaneously compressing a production fluid chamber operating in tandem with the power fluid chamber's expansion forcing a production fluid within the production fluid chamber toward the wellhead; preventing the production fluid from backflowing; and returning the power fluid chamber to its first volume.Exemplary Embodiments

[0034] Additional features and advantages of the disclosure will be set forth in the description which follows, and in part will be obvious from the description, or can be learned by practice of the herein disclosed principles. The features and advantages of the disclosure can be realized and obtained by means of the instruments and combinations particularly pointed out in the appended claims. These and other features of the disclosure will become more fully apparent from the following description and appended claims, or they can be learned by the practice of the principles set forth herein.A. FIG. 1—Pump Stroke (Upstroke)

[0035] FIG. 1 illustrates a pump 100 according to the present invention. A pump 100 for stimulating production from an underground formation including a production zone 136, the pump comprising a well 122 having production tubing 124 with a power tube 106 extending therethrough to the production zone 136 containing a production fluid. A production casing 108 is in contact with the ground structure. Perforations 156 allow production fluid to flow into the production tubing 124. A surface unit 126 is preferably located near a wellhead 128 including a surface pump 102 hydraulically connected to the power tube 106 and to a power fluid reservoir 104.

[0036] A downhole unit 130 is disposed downhole within the tubing 124. The downhole unit 130 preferably has a cylindrical body 132 sized to be received within the tubing 124. Defined within the body 132 are a power chamber 112 hydraulically connected to the power tube 106. An upper chamber 110, a lower pump chamber 111, and a suction chamber 134 are all hydraulically connected to the production fluid from the production zone 136 and to each other.

[0037] The power chamber 112 is defined between a fixed divider 120 and a first piston 138 slidingly and sealingly disposed within the cylindrical body 132. The lower pump chamber 111 is located adjacent to the power chamber 112 and defined between the fixed divider 120, and a second piston 140 slidingly and sealingly disposed within the cylindrical body 132 and connected to the first piston 138 end at a fixed distance so that they move in tandem. As shown, the two cylinders are connected by a connector tube 142, but they may be connected by other means such as at least one connection member affixed at each end thereof to one of the cylinders. The second cylinder 140 has defined therein a first check valve 144. The upper chamber 110 is defined between the top 154 and the first piston 138. The upper chamber is in fluid communication with the tubing 124 through a port 116.

[0038] The suction chamber is 134 located adjacent to lower pump chamber 111 and defined between the second piston 140, and a fixed lower divider 146 defining a second check valve 148 therein.

[0039] A port 116 from the cylindrical body 132 is hydraulically connected to the tubing 124. A seal 150 hydraulically separates the tubing 124 above the downhole unit 130 from any tubing 124 below the downhole unit. The seal could be a hold down, and several types of hold downs are known, any of which should work with the present invention. Known hold downs include a mechanical bottom lock, a mechanical top lock, and a cup-type hold down.

[0040] Stops 152 may be provided to prevent the first 138 and second 140 pistons from traveling beyond them. Additionally, the power tube 106 may extend through the first cylinder 138 with the cylinder moving relative to the power tube in a sliding and sealing fashion. The stops prevent damage to the components that might be caused by excessive travel of components, and they prevent a fluid lock from occurring in the instance where one of the cylinders 138 and 140 might come into very close contact with the fixed divider 120.

[0041] During the pump or upstroke, the surface pump 102 pumps power fluid into the power chamber 112, causing it to expand as the first cylinder 138 is forced up. The second cylinder 140 moves in tandem with the first cylinder 138 which simultaneously causes both the upper chamber 110 and the lower pump chamber 111 to decrease in volume associated with the synchronized upward movement of the first cylinder 138 and the second cylinder 140. When the upper and pump chambers decrease in volume, they force production fluid up and out of the downhole unit 130 into the tubing 124 and thence out of the well. At the same time, as the second cylinder 140 moves upwardly, it increases the volume of the suction chamber 134 drawing production fluid into the suction chamber 134 through the second check valve 148.B. FIG. 2—Suction Stroke (Downstroke)

[0042] FIG. 2 illustrates a suction stroke or downstroke. During the suction stroke, the surface pump 102 reduces the pressure in the power fluid chamber 112, causing it to contract. This may be accomplished by using a piston pump as the surface pump 102 which during this phase pulls power fluid out of the power tube 106. Alternatively, the suction stroke may be accomplished by allowing the weight of the components of the pump and the relative densities of the production and power fluids to move the first 138 and second 140 pistons in a downward direction. As the power fluid chamber 112 contracts, the upper chambers 110 and pump chamber 111, which operate in tandem with it, expand by downward movement of the first piston 138 in tandem with the second piston 140. This downward movement causes the upper chamber 110 and pump chamber 111 to refill with production fluid. Production fluid flows into the pump chamber 111 from the suction chamber 134 through the first 144 check valve. The second check valve 148 prevents production fluid from moving back into the production zone 136 out of the suction chamber 134.

[0043] The first check valve 144 and fixed divider 120 play roles in maintaining the efficiency of this phase. The first check valve 144 opens to allow the production fluid to enter the lower pump chamber 111, while the second check 148 prevents the production fluid from flowing back into the production zone 136. As the lower pump chamber 111 refills, it prepares for the next upstroke, ensuring a continuous cycle of fluid lifting. The suction stroke resets the system for the next cycle and maintains a consistent flow of fluids to the surface.

[0044] In an example involving a 10,000 feet true vertical depth (TVD and MD) well and a 30-foot pump length, the pump operates efficiently under specific conditions. The power fluid, with a density of 8.34 pounds per gallon (ppg) drives the system. The production fluid, comprising a 50% water cut with a water density of 8.33 ppg and oil with a 42.5 API gravity, flows alongside the production fluid.

[0045] Thus, the surface pump needs to generate a pressure of 2,500 psi to overcome the hydrostatic delta and friction within a 0.84″ internal diameter (I.D.) power fluid tube. This pressure ensures the hydraulic fluid can travel down the wellbore, expanding the power fluid chamber and enabling the efficient lifting of the production fluid.

[0046] The estimated daily fluid production is 100 barrels, achieved with an 80% pump efficiency. This high level of efficiency is crucial for maintaining consistent and effective fluid extraction. Additionally, the pump system can utilize the same jewelry below the pump, as used in sucker rod pumps, for sand and gas separation.C. FIGS. 3 and 4—Detailed Illustration of Pump and Suction Stroke

[0047] FIG. 3 and FIG. 4 depict the downhole unit 130 in greater detail during the pump stroke (upstroke) and suction stroke (downstroke) respectively.

[0048] FIG. 3 shows seals comprised of Viton® or similar for sliding and sealing engagement of moving parts in the downhole unit 130. A first seal 302 is disposed around a periphery of the first cylinder 138 where it engages the cylindrical body 132. Similarly, a second seal 304 is disposed around a periphery of the second cylinder 140 where it engages the cylindrical body 132. A third seal 306 is disposed within the fixed divider 120 where it engages the connecter tube 142. In like fashion, a fourth seal 308 is also present (except in an implementation as shown in FIGS. 6 and 7) which engages the power tube 106 where it passes through the first cylinder 138.

[0049] In one embodiment, as power fluid enters the downhole unit 130 the power tube 106 directs it into the power chamber 112. For stability purposes, the power tube is preferably connected to the fixed divider 120 at a terminal end. At least one exit port is defined in the power tube at a point within the power chamber 112, preferably closely adjacent to the fixed divider 120 so that the motion of the first cylinder 138 does not impair flow therethrough.

[0050] As the second cylinder 140 moves up it pushes production fluid out of the lower pump chamber 111 through at least one opening defined 310 in the connector tube 142. Any openings in the connector tube are preferably adjacent to where it connects to the second cylinder 140 so that they are not obstructed by the fixed plate 120 as the second cylinder approaches it.

[0051] The upward movement of the second cylinder 140 also draws production fluid into the suction chamber 134 through the second check valve 148. The filling of the suction chamber 134 reloads the downhole unit 130 for the next pump cycle.

[0052] A pump bypass 312 is preferably defined into the cylindrical body 132 of the downhole unit 130. The pump bypass 312 operates in a malfunction or problem condition when the first piston moves too far upwards and prevents damage to the downhole unit 130. The bypass 312 allows power fluid to pass into an upper portion of the cylindrical body and eventually into the tubing 124 if excess power fluid continues to be pumped down the hole. The bypass also facilitates initial operation of the downhole unit 130 when initially installed to prevent fluid lock, but the downhole unit 130 may be filled with fluid on the surface, in which case the bypass may not be needed.

[0053] FIG. 4 shows the suction stroke or downstroke in which power fluid passes from the pump chamber 112 into the power fluid tube 106 through at least one opening defined therein 402. At the same time, production fluid passes through the first check valve 144 and into the lower pump chamber 111 by passing through at least one opening defined in the connector tube 142. The upper chamber 110 is also refilled with production fluid, at least in part, by fluid being drawn back into the downhole unit 130 from the tubing 124 through the port 116.

[0054] The downhole unit 130 is configured to facilitate an efficient upstroke and downstroke process within the well. The pump inlet is engineered with a minimal amount of moving parts, enhancing reliability and reducing the complexity of maintenance. The configuration ensures there is no exhaust fluid, only reciprocating fluid, thereby eliminating fluid waste and enhancing operational efficiency.

[0055] FIG. 4 also illustrates one of the chambers, in this embodiment the pump chamber 111 and suction chamber 134, having a different cross section from the other chamber(s). In the embodiment shown in FIG. 4, the pump chamber 111 and suction chamber 134 have smaller cross sections than the power chamber 112. The inner wall 404 is disposed within and has a smaller diameter than the cylindrical body 132

[0056] Moreover, the pump avoids rod and tubing wear and tear on the tubing 124, significantly extending the lifespan of the well components and reducing maintenance costs. Tubing wear is of particular concern on offset wells where the tubing has significant bends that are in frictional contact with sucker rods. There are no limitations concerning deviation or depth, making this pump inlet adaptable to various well configurations, including those with significant deviations and depths. The system's flexibility allows for altering the power fluid weight and stroke length from the surface, providing operators with the ability to fine-tune the system based on specific well conditions and requirements.

[0057] The pump operates with a mid-pressure surface pump, depending on the power fluid's weight, ensuring a balanced and efficient fluid transfer process. Additionally, the small footprint on the surface makes it ideal for wells with limited space, allowing for more efficient use of the available area. The design also supports the use of multiple pumps with a single prime mover, optimizing resource use and further enhancing operational efficiency.

[0058] In some examples, the pump can be optimized by changing the relative diameters of the power chamber, the pump chamber and the suction chamber. These modifications may result in a lower surface pressure required to lift the entire column of fluid. Additionally, the adjustments can accommodate different water cuts and production rates, allowing for greater flexibility and efficiency in various operational conditions. Varying the relative diameters approximates the use of gears. For example, if the diameter of the power chamber is smaller than the diameter of the pump chamber, a smaller volume of power fluid can pump a larger volume of production fluid.

[0059] In some examples (ignoring friction effects) the hydrostatic pressure of the power fluid can apply a force of 6,041 lbf plus the surface pump psi, ensuring efficient movement of the power fluid. Concurrently, the production fluid hydrostatic pressure applies a force of 6,735 lbf, enabling the effective pump operation. During the downstroke, a pound force (lbf) of 6,735 lbf is generated in the power chamber 112, where there is a 1.681 square inch reduction caused by the dip tube power tube 106 and the production tube connecter tube 142. This downstroke action increases the force within the power fluid chamber 112 to 6,041 lbf. The interaction between these forces ensures the efficient movement of fluids through the system, allowing for the continuous and effective operation of the pump.D. FIG. 5—Well Components

[0060] FIG. 5 illustrates some of the relevant component of a well that may be present in the environment in which the pump 100 is used. In an example, the pump is installed within a production formation 136, which encompasses an unconsolidated formation 522 and a freshwater zone 502. The installation involves multiple casing / tubing structures that function either as power fluid delivery or as channels for fluid flowing up the casing / tubing.

[0061] Cement is usually pumped around the outer annulus of each casing. Most of those casings thus cannot be pumped into or flowed out of when the pump is in operation.

[0062] The casings most often present are the conductor, surface and production casings. Intermediate is also common depending on the depth and formations the well passes through.

[0063] The production tubing 124 may be encapsulated by an intermediate casing 516, providing an additional layer of containment and structural integrity. Surrounding the intermediate casing 516 is typically a surface casing 518. The outermost layer is the conductor casing 520. The production casing 108 is in direct contact with the various ground structures potentially including the unconsolidated formation 522 and freshwater zone 502 as well as the production zone 136.

[0064] Each component of the casing system plays a different role in maintaining the integrity and functionality of the well. The production tubing 124 protects the pumps and facilitates fluid flow. The intermediate casing 516 provides additional structural support through any unconsolidated zones 522, while the surface casing 518 protects any freshwater zones 502. The conductor casing 520 adds structural support. This comprehensive installation setup is designed to optimize the performance of the pump 100 within the varied geological conditions of the ground structure.E. FIGS. 6 and 7—Second Embodiment

[0065] A second embodiment of the downhole unit 130 is illustrated in FIGS. 6 and 7. In this embodiment, the power fluid is delivered to the power chamber 112 by a different path. Generally, the components not discussed in reference to FIGS. 6 and 7 remain the same as in the first embodiment.

[0066] Instead of delivering power fluid to the power chamber 112 via the power fluid tube 106 after it passes through the first cylinder 138, power fluid is delivered via ports 602 defined in an outer wall 604 of the power fluid chamber 112. An annular space is defined between the cylindrical body 132 and the outer wall 604. Power fluid passes through the annular space, and thence through the ports 602 and thus into the power chamber 112.

[0067] As shown in FIG. 7, power fluid passes out of the power chamber 112 through the ports 602 and thence into the annular space defined between the cylindrical body 132 and the outer wall 604.F. FIG. 8—Flexible Power Tube

[0068] FIG. 8 shows and embodiment where the power tube 106 has a flexible section 802 disposed within between the top 154 and the first piston 138. As the first piston 138 moves up and down during operation, the flexible section 802 lengthens and contracts to maintain fluid communication with the power chamber 112.G. FIGS. 9 and 10—Simplified Downhole Unit

[0069] FIGS. 9 and 10 illustrate a simplified downhole unit 130. In this embodiment, the downhole unit 130 only has one check valve 148. The power chamber 112 is in direct communication with the surface unit 126 via the power tube 106. The operation of this configuration depends on the substantially incompressible nature of the fluids within the wellbore. The surface unit 126 delivers power fluid through the power tube 106 to the power chamber 112 in the upstroke. This forces the piston 902 down and concurrently forces the production fluid up and out of the lower downhole unit 130 through the port 116. The check valve 148 prevents the production fluid from re-entering the surrounding formation.

[0070] The piston 902 is disposed within and in sliding and sealing engagement with a second cylindrical body 904 which is, in turn, disposed within the cylindrical body 132. A channel 906 is defined between the cylindrical body 132 and the second cylindrical body 904. As shown, the channel 906 is disposed toward one side of the cylindrical body 132, but it may be a uniform annular space around the second cylindrical body 904. The cylindrical body 132 and the second cylindrical body 904 are fixed in place one relative to the other.

[0071] In the downstroke, as shown in FIG. 10, power fluid is sucked upward out of the formation through the check valve 148 by the surface unit 126 pulling the piston 902 up and concurrently pulling production fluid from the production zone 136 through the check valve 148 into the suction chamber and into the pump chamber 111. A check valve located at the surface unit 126 prevents production fluid from reentering the well after being produced on the upstroke.Interpretation

[0072] The above specification and examples provide a complete description of the structure and use of illustrative embodiments. Although certain embodiments have been described above with a certain degree of particularity, or with reference to one or more individual embodiments, those skilled in the art could make numerous alterations to the disclosed embodiments without departing from the scope of this invention. As such, the various illustrative embodiments of the methods and systems are not intended to be limited to the particular forms disclosed. Rather, they include all modifications and alternatives falling within the scope of the claims, and embodiments other than the one shown may include some or all of the features of the depicted embodiment. For example, elements may be omitted or combined as a unitary structure, and / or connections may be substituted. Further, where appropriate, aspects of any of the examples described above may be combined with aspects of any of the other examples described to form further examples having comparable or different properties and / or functions and addressing the same or different problems. Similarly, it will be understood that the benefits and advantages described above may relate to one embodiment or may relate to several embodiments. For example, embodiments of the present methods and systems may be practiced and / or implemented using different structural configurations, materials, ionically conductive media, monitoring methods, and / or control methods.

[0073] The claims are not intended to include, and should not be interpreted to include, means-plus- or step-plus-function limitations, unless such a limitation is explicitly recited in a given claim using the phrase(s) “means for” or “step for,” respectively.

Claims

1. A pump for stimulating production from an underground formation including a production zone, the pump comprising:a. a well having tubing with a power tube extending therethrough;b. a surface unit near a wellhead including a surface pump hydraulically connected to the power tube and to a power fluid reservoir;c. a downhole unit having a cylindrical body sized to be received within the tubing and further defining therein a power chamber hydraulically connected to the power tube, a pump chamber and a suction chamber each hydraulically connected to the production fluid and to each otheri. the power chamber defined between1. a fixed divider, and2. a first piston slidingly and sealingly disposed within the cylindrical body;ii. the pump chamber located adjacent to the power chamber and defined between -1. the fixed divider, and2. a second piston slidingly and sealingly disposed within the cylindrical body and connected to the first piston end at a fixed distance so that they move in tandem and having a first check valve disposed therein; andiii. the suction chamber located adjacent to the pump chamber and defined between -1. the second piston, and2. a fixed lower divider defining a second check valve therein;iv. a port from the cylindrical body hydraulically connected to the tubing; andv. a seal hydraulically separating the tubing above the downhole unit from the tubing below the downhole unit.

2. The pump of claim 1 further defining stops preventing the first and second pistons from traveling beyond them.

3. The pump of claim 1 further defining the power tube extending through the first cylinder and the cylinder moving relative to the power tube in a sliding and sealing fashion.

4. The pump of claim 1 further defining enlarged section of the cylindrical body around which power fluid can pass at an upper limit of its travel.

5. The pump of claim 1 in which the power fluid is less dense than the production fluid whereby the difference in densities causes the power fluid to be forced out of the power chamber when the surface pump is disengaged.

6. The pump of claim 1 in which the surface pump action is switchable to force the pressure fluid into the power tubing or to pull it out by a vacuum whereby on an upstroke the surface pump forces the power fluid into the power chamber thus both pushing production fluid from the pump chamber up the production tube and pulling production fluid into the suction chamber and on the downstroke the surface pump pulls the power fluid out of the power chamber returning the pump to a first position.

7. The pump of claim 6 where the switching from pressure to vacuum is accomplished by reversing the operation of the pump.

8. The pump of claim 6 where the switching from pressure to vacuum is accomplished by operation of valves.

9. The pump of claim 6 where the surface pump is a reciprocating pump that pushes power fluid into the power tubing on a pressure stroke and pulls it out of the power tubing on a suction stroke.

10. The pump of claim 1 in which the cross-sectional area of at least one chamber is different than the cross section of at least one other chamber.

11. The pump of claim 10 in which the cross-sectional area of the power chamber is less than the cross-sectional area of the suction chamber whereby each unit of power fluid pumped into power chamber causes a larger volume of production fluid to be moved into the suction chamber.

12. The pump of claim 10 in which the cross-sectional area of the power chamber is greater than the cross-sectional area of the suction chamber whereby each unit of power fluid pumped into power chamber causes a smaller volume of production fluid to be moved into the suction chamber.

13. The pump of claim 1 in which the check valves are selected from ball, disc, dual plate waver, duckbill, lift, non-slam, piston, spring-loaded, swing, tilting waver, top-hinged, and spring-loaded.

14. The pump of claim 1 in which the power tube has a flexible section between a top of the body and the first piston accommodating the up and down motion of the first cylinder in operation.

15. A pump for stimulating production from an underground formation comprising:a. a well having tubing with a power tube extending therethrough;b. a surface unit near a wellhead including a surface pump hydraulically connected to the power tube and to a power fluid reservoir;c. a downhole unit having a body sized to be received within the tubing and further defining therein a power chamber hydraulically connected to the power tube, a pump chamber and a suction chamber both hydraulically connected to the production fluid and to each otheri. the power chamber defined between1. a fixed upper divider, and2. a first piston slidingly and sealingly disposed within the cylindrical body;ii. the pump chamber located adjacent to the power chamber and defined between -1. the first piston, and2. a fixed lower divider having a first check valve disposed therein; andiii. the suction chamber located adjacent to the pump chamber and defined between -1. the fixed lower divider, and2. a second piston slidingly and sealingly disposed within the cylindrical body and connected to the first piston at a fixed distance so that they move in tandem and having a first check valve disposed therein;iv. an outlet from the cylindrical body hydraulically connecting the wellhead; andv. a seal hydraulically separating the tubing above the downhole unit from the casing below the downhole unit;vi. stops preventing the first and second pistons from traveling beyond them; andvii. the power tube extending through the first cylinder and the cylinder moving relative to the power tube in a sliding and sealing fashion.

16. A pump for stimulating production from an underground formation including a production zone, the pump comprising:a. a well having tubing with a power tube extending therethrough;b. a surface unit near a wellhead including a surface pump hydraulically connected to the power tube and to a power fluid reservoir, the surface unit further having a check valve preventing production fluid from back flowing into the well tubing;c. a downhole unit having a cylindrical body sized to be received within the tubing and further defining therein a power chamber hydraulically connected to the power tube, a pump chamber and a suction chamber each hydraulically connected to the production fluid and to each otheri. the power chamber defined between a second cylindrical body and a piston slidingly and sealingly disposed within the second cylindrical body;ii. the pump chamber located adjacent to the power chamber and defined between the second cylindrical body and the piston;iii. the suction chamber located adjacent to the pump chamber and defined between the second cylindrical body and a fixed divider defining a check valve therein allowing production fluid to enter the suction chamber;d. a port from the cylindrical body hydraulically connected to the tubing; ande. a seal hydraulically separating the tubing above the downhole unit from the tubing below the downhole unit.

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