DOWNHOLE OIL RECOVERY SYSTEM AND METHOD OF USE

Abstract

An oil recovery system may comprise a generally hollow pump housing having an interior space, a downstroke powerline and an upstroke powerline, a power piston disposed in the interior space of the pump housing, a connecting rod having a first end attached to the power piston, a production piston attached to a second end of the connecting rod, a seal disposed between the production piston and the power piston, an oil inlet in fluid communication with a reservoir, and an oil inlet valve in fluid communication with the oil inlet. The power piston may be movable between a first position and a second position by power fluid delivered through the upstroke powerline or the downstroke powerline.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a continuation-in-part of U.S. application Ser. No. 11/762,627, filed on Jun. 13, 2007, which is a continuation-in-part of PCT/US2005/045305, filed Dec. 13, 2005, which is a continuation-in-part of U.S. application Ser. No. 11/010,641, filed Dec. 13, 2004, now U.S. Pat. No. 7,165,952, and this application is a continuation-in-part of U.S. application Ser. No. 11/293,039, filed Dec. 2, 2005, which is a continuation-in-part of U.S. application Ser. No. 10/945,562, filed Sep. 20, 2004, which is a continuation-in-part of U.S. application Ser. No. 10/945,530, filed Sep. 20, 2004, which is a continuation-in-part of U.S. application Ser. No. 10/884,376, filed Jul. 2, 2004, the disclosures of which are incorporated herein by reference.

FIELD

The system and method described herein generally relate to downhole oil recovery.

SUMMARY

An oil recovery system may comprise a generally hollow pump housing having an interior space, a downstroke powerline and an upstroke powerline, a power piston disposed in the interior space of the pump housing, a connecting rod having a first end attached to the power piston, a production piston attached to a second end of the connecting rod, a seal disposed between the production piston and the power piston, an oil inlet in fluid communication with a reservoir, and an oil inlet valve in fluid communication with the oil inlet. The power piston may be movable between a first position and a second position by power fluid delivered through the upstroke powerline or the downstroke powerline.

BACKGROUND

Conventional oil recovery systems are hampered by limitations on both the depth and volume of oil that can be recovered. Conventional oil recovery systems are relatively short-lived and require a high level of maintenance. In the past, fitting system components and powerlines within coil tubing has proven to be too difficult.

Common oil recovery systems also present significant problems at the surface. Surface pumps are loud, cumbersome, visually offensive, dangerous, and environmentally unfriendly. As such, restrictions are placed on both where and when these systems can be used. Prohibitive zoning restrictions are often based on the way the pumps look, how they sound, and the inconvenience they cause to people in their proximity. Further, it is widely known in the art that conventional surface pumps are prone to leaking both oil and hazardous fumes. As such, environmental concerns are very high and periodic maintenance is required, while the cost of operation increases and efficiency decreases.

Surface pumps are also dangerous; each year, there are several injuries and deaths that result from the operation of such pumps. These casualties often involve children who make their way to the pumps, drawn by curiosity, only to get caught in the moving parts. In view of the limitations and hazards associated with traditional oil recovery systems, and the defects in those systems, a great need exists for a system that can operate efficiently and safely.

BRIEF DESCRIPTION OF THE DRAWINGS

Applicant's system and method may be further understood from a description of the accompanying drawings, wherein unless otherwise specified, like reference numerals are intended to depict like components in the various views.

FIG. 1 is a cross-sectional view of one embodiment of a downhole unit of a downhole oil recovery system.

FIGS. 2A-2B are cross-sectional views of an alternative embodiment of a downhole unit of a downhole oil recovery system.

FIG. 3A is a cross-sectional schematic view of one embodiment of a downhole oil recovery system as used in connection with an oil well.

FIG. 3B is a cross-sectional schematic view of an alternative embodiment of a downhole oil recovery system as used in connection with an oil well.

FIG. 4 is a perspective view of one embodiment of a downhole unit of a downhole oil recovery system.

FIGS. 5A-5B are cross-sectional views of the downhole unit of FIG. 4.

FIG. 6 is a schematic cross-sectional view of an alternative embodiment of a production tube and powerlines of a downhole oil recovery system.

FIG. 7 is a schematic cross-sectional view of another alternative embodiment of a production tube and powerlines of a downhole oil recovery system.

FIG. 8 is a schematic cross-sectional view of yet alternative embodiment of a production tube and powerlines of a downhole oil recovery system.

FIG. 9 is a schematic cross-sectional view of still another alternative embodiment of a production tube and powerlines of a downhole oil recovery system.

FIG. 10 is a schematic cross-sectional view of one embodiment of a downhole unit of a downhole oil recovery system.

FIG. 11 is a schematic cross-sectional view of an alternative embodiment of the downhole unit of a downhole oil recovery system.

FIG. 12 is a cross-sectional view of an alternative embodiment of a downhole unit of a downhole oil recovery system.

FIG. 13 is a cross-sectional view of another alternative embodiment of a downhole unit of a downhole oil recovery system.

FIG. 14 is a cross-sectional view of a portion of the downhole unit of FIG. 13.

FIG. 15 is a perspective view of a portion of a downhole unit of a downhole oil recovery system.

FIG. 16 is a cross-sectional view of an alternative embodiment of a production tube and powerlines of a downhole oil recovery system.

DETAILED DESCRIPTION

As used herein, the following terms should be understood to have the indicated meanings:

When an item is introduced by “a” or “an,” it should be understood to mean one or more of that item.

“Additive” means any gas, liquid or solid of a molecule, chemical, macromolecule, compound, or element, alone or in combination.

“Alloy” means a substance composed of two or more metals, or of a metal or metals with a non-metal.

“Anti-corrosive” means having an ability to decrease the rate of, prevent, reverse, stop, or a combination thereof, corrosion.

“Component” means any part, feature, or element, alone or in combination.

“Comprises” means includes but is not limited to.

“Comprising” means including but not limited to.

“Contamination” means the presence of foreign materials, including but not limited to microorganisms, chemicals, or a combination thereof.

“Controller” means any programmable machine capable of executing machine-readable instructions. A “controller” may include but is not limited to a general purpose controller, microprocessor, computer server, digital signal processor, programmable logic controller, computer, or a combination thereof. A “controller” may comprise one or more processors, which may comprise part of a single machine or multiple machines.

“Corrosion” means a state of at least partial damage, deterioration, or alteration, or a combination thereof.

“Corrosive” means having the effect of at least partially damaging, deteriorating, or altering, or a combination thereof, including but not limited to by chemical or biological action.

“Fastened” means, with respect to two or more components that are attached to each other, attached in any manner including but not limited to attachment by one or more bolts, screws, nuts, pins, stitches, staples, brads, rivets, adhesives, straps, attaching by tack welding, bracing, strapping, welding, or using a fitting or a combination thereof.

“Fluid” means any substance that may be caused to flow, including but not limited to a liquid or gas or slurry, or a combination thereof. “Fluid” may include but is not limited to water, oil, hydrocarbons, gas or a combination thereof. A fluid may or may not have one or more solid particles therein.

“Having” means including but not limited to.

“Inhibitor” means a substance that at least partially decreases the rate of, prevents, counteracts, or stops a chemical reaction. An “inhibitor” may include but is not limited to any gas, liquid or solid of a molecule, chemical, macromolecule, compound, or element, alone or in combination.

“Inhibit” means to at least partially decrease the rate of, prevent, counteract, or stop.

“Metal” means having at least one of any of a class of elementary substances which are at least partially crystalline when solid. “Metal” may include but is not limited to gold, silver, copper, iron, steel, brass, nickel, zinc, aluminum, or a combination thereof, including but not limited to an alloy.

“Piston” means a component at least partially fitting within a housing, adaptable to compress, move or restrict the movement of a fluid or solid. A “piston” may be made of any desired material and may have any desired shape, size, strength, stiffness, or other attribute.

“Rupture disk” includes, but is not limited to, an initially closed device which may relieve the inlet static pressure in a system through the bursting of a barrier at a predetermined pressure. A “rupture disk” may be made of any desired material and may have any desired shape, size, strength, stiffness, or other attribute.

“Seal” means any device that at least partially obstructs, prevents, occludes, restricts or directs the movement, expansion or flow of a liquid, gas or solid, or a combination thereof.

With reference to FIG. 1, FIGS. 2A-2B, and FIGS. 3A-3B, an embodiment of a downhole oil recovery system is identified generally by the reference numeral 10. In some embodiments, system 10 may include a surface unit 12. In an alternative embodiment (not shown), the surface unit 12 may be installed subterranean, or below the surface. Surface unit 12 may send power fluid 14 through upstroke powerline 16 during one cycle and may send power fluid 14 through downstroke powerline 18 in a following downstroke cycle. Surface unit 12 may reversibly engage with powerlines 16 and 18 so as to form a fluid-tight connection, such connection being formed by standard tube fittings known in the art or other suitable fittings. In some embodiments, surface unit 12 may comprise a pressure pump, modified to comprise a “switch off pressure sensor” 13 which reads the pressure at surface unit 12 on both the upstroke and downstroke. At the point each stroke is carried out, pressure increases beyond a preset “switch off” point where sensor 13 sends a signal to surface unit 12 to begin the next stroke. Further, surface unit 12 may transfer power fluid 14 by alternating pressure on both upstroke powerline 16 and downstroke powerline 18, and such pressure change may be carried out in a number of ways.

Referring to FIGS. 3A-3B, FIG. 6, FIG. 7, FIG. 8, FIG. 9, FIG. 12, and FIG. 13, both upstroke powerline 16 and downstroke powerline 18 may extend from surface unit 12 to a downhole unit 11 and follow along the length of removable production tube 20, all within the casing 23 of a wellbore.

Referring to FIG. 1, FIGS. 2A-2B, FIG. 4. FIGS. 5A-5B, FIG. 12, FIG. 13, and FIG. 15, upstroke powerline 16 leads to upstroke reservoir 22 and may be connected thereto by upstroke fitting 24. Downstroke powerline 18 leads to downstroke reservoir 26 and may be connected thereto by downstroke fitting 28. In some embodiments, both fitting 24 and fitting 28 may be standard tube fittings as known in the art. Fitting 24 and fitting 28 may be shielded by a protective guard or housing (not shown) to protect fitting 24 and fitting 28 from damage. In some embodiments, upstroke powerline 16 and downstroke powerline 18 may be able to support their weight by connecting to inlet fittings that may be near the surface, and upstroke fitting 24 and downstroke fitting 28, and possibly by other fittings intermediate between the surface and downhole unit 11. In an alternative embodiment, there may not be a fitting 24 or a fitting 28, and instead one or more of the components of downhole unit 11, including, but not limited to upstroke powerline 16 and downstroke powerline 18, and pump housing 25, may be molded or cast.

In an alternative embodiment, as surface unit 12 sends power fluid 14 through upstroke powerline 16, power fluid 14 fills upstroke reservoir 22 such that its fluid volume increases, thereby actuating power piston 30 in an upward direction so that the fluid volume of downstroke reservoir 26 decreases. Likewise, as surface unit 12 sends power fluid 14 through downstroke powerline 18, power fluid 14 fills downstroke reservoir 26 such that its fluid volume increases, thereby actuating power piston 30 in a downward direction, so that the fluid volume of upstroke reservoir 22 decreases.

Referring to FIG. 1, FIGS. 2A-2B, FIG. 4, FIGS. 5A-5B, FIG. 12, and FIG. 13, power piston 30 may be actuated between a top position and a bottom position, where power piston 30 reaches a position just above upstroke fitting 24 at the completion of the downstroke in the bottom position; and where power piston 30 reaches a position just below downstroke fitting 28 at the completion of the upstroke in the top position. The pressure change in powerlines 16 and 18, and resulting fluid volume change in upstroke reservoir 22 and downstroke reservoir 26, respectively, is the mechanism responsible for actuating power piston 30. In some embodiments, power piston 30 may be a “spray metal” piston, or made of some suitable alloy, and may be shaped so as to form a tight fit with the pump housing 25.

Connecting rod 32 is attached to power piston 30 and extends therefrom. Connecting rod 32 is of such length that connecting rod 32 extends beyond a pump barrel seal 38 during both the downstroke and the upstroke. Connecting rod 32 is actuated between a top position and a bottom position where its top portion rests just above pump barrel seal 38 in a bottom position, at the completion of a downstroke; and where its bottom portion rests just below pump barrel seal 38 in a top position, at the completion of an upstroke.

While some alternative embodiments shown in FIG. 1, FIGS. 5A-5B, and FIG. 12 show first reservoir 40 and second reservoir 42 as being positioned above power piston 30, other useful embodiments are envisioned where first reservoir 40 and second reservoir 42, and their respective inlets, are positioned below power piston 30 such as the embodiment shown in FIGS. 2A-2B. In such cases, the general relationship between the components remains the same, and the effectiveness of system 10 substantially remains the same.

Referring to FIG. 1, FIGS. 5A-5B, FIG. 12, and FIG. 13, production piston 46 is connected to and rests just above connecting rod 32 and may be of a generally solid cylindrical form or other suitable shape. Production piston 46 is actuated between a top position and a bottom position where production piston 46 rests just above pump barrel seal 38 at the completion of a downstroke in a bottom position, and piston 46 reaches just below one-way valve 52 at the completion of an upstroke, in a top position. As previously mentioned in the specification, the volume of both production piston 46 and power piston 30 may be changed with respect to one another. This change in ratio between production piston 46 and power piston 30 has particular applicability in a low production energy context. Immediately above pump barrel seal 38 is first reservoir 40, into which extends the production piston end of connecting rod 32, which is in turn connected to production piston 46.

Referring to the embodiments shown in FIGS. 2A-2B, production piston 46 is connected to and rests just below connecting rod 32 and may be of a generally solid cylindrical form or other suitable shape. Production piston 46 is actuated between a top position and a bottom position where production piston 46 rests just below pump barrel seal 38 at the completion of an upstroke in a top position; and piston 46 reaches just above one-way valve 45 at the completion of a downstroke, in a bottom position. As previously mentioned in the specification, the volume of both production piston 46 and power piston 30 may be changed with respect to one another. This change in ratio between production piston 46 and power piston 30 has particular applicability in a low production energy context. Immediately above pump barrel seal 38 is upstroke reservoir 22, into which extends the power piston end of connecting rod 32, which is in turn connected to power piston 30.

Immediately above oil inlet 41 in the embodiment shown in FIGS. 2A-2B, is first reservoir 40. First reservoir 40 is in fluid communication with a first inlet 41. In one embodiment, first inlet 41 may have a one-way valve 45 that allows production fluid 62 to flow into first reservoir 40 during an upstroke, but does not allow backflow. During an upstroke, production fluid 62 (oil, gas, or other fluid from a standard type as known in the production zone of the subject well) is drawn into system 10 through first inlet 41 where it travels through and fills first reservoir 40. During a downstroke, production fluid 62 is pushed from first reservoir 40 by production piston 46, and flows through adjacent shaft 48, through one-way valve 49, and into upper reservoir 53. With this configuration, production of oil may be approximately doubled, yet there is no significant increase in energy consumption in view of some systems that only pump oil during the upstroke.

Immediately above pump barrel seal 38 in the embodiments shown in FIG. 1, FIGS. 5A-5B, FIG. 12, and FIG. 13 is first reservoir 40 in fluid communication with a first inlet 41. During an upstroke, production fluid 62 (oil, gas, or other fluid from a standard type as known in the production zone of the subject well) is drawn into system 10 through first inlet 41 where it travels through and fills first reservoir 40. During a downstroke, production fluid 62 is pushed from first reservoir 40 by production piston 46, and flows through adjacent shaft 48, through one-way valve 49, and into upper reservoir 53 (upper reservoir 53 is not shown in FIGS. 5A-5B). With this configuration, production of oil may be approximately doubled, yet there is no significant increase in energy consumption in view of some systems that only pump oil during the upstroke.

Second reservoir 42 is positioned between production piston 46 and one-way valve 52. Second reservoir 42 is in fluid communication with a second inlet 43. In some embodiments, second inlet 43 may have a one-way valve that allows production fluid 62 to flow into second reservoir 42 during a downstroke, but does not allow backflow. During a downstroke, production fluid 62 is drawn into system 10 through second inlet 43 where it travels through and fills second reservoir 42. During an upstroke, production fluid 62 is pushed from second reservoir 42 by production piston 46, and flows through one-way valve 52 into upper reservoir 53. This pumping of production oil during the upstroke complements pumping of oil to the surface during the downstroke so that oil travels to the surface in a continuous or near continuous manner. Again, by virtue of pumping production fluid 62 to the surface during both the upstroke and downstroke, production of production fluid 62 may be approximately doubled, yet there is no significant increase in energy consumption.

In some alternative embodiments shown in FIGS. 10-11, the production piston 46 may comprise softer material such as non-metallic material to enable debris in production fluid 62 to slip by production piston 46 during operation of the downhole unit 11. In one alternative embodiment, production piston 46 may comprise metal spacers and fiber rings to allow production piston 46 to flex and allow debris to pass from first reservoir 40 or second reservoir 42. In other alternative embodiments, the power piston 30 and production piston 46 may comprise various alloys, be of various lengths, and may have various clearances between the pistons 30, 46 and the pump housing 25. As shown in FIG. 12, the clearance between power piston 30 or production piston 46 and pump housing 25 may be altered to allow power fluid 14 to leak around power piston 30 and production piston 46 and through pump barrel seal 38. Of course, such clearance may be kept at a minimum to prevent inefficiency from pressure loss in system 10. Even so, leakage may have some beneficial effects. For example, power piston 30 or production piston 46 may have about a 3/1000^th inch clearance from pump housing 25. Such leakage may cause power fluid 14 to bleed out of upstroke reservoir 22 and downstroke reservoir 26 such that power fluid 14 may need to be replaced periodically to replenish power fluid 14, add any additives to power fluid 14, prevent or counteract contamination of the components of system 10, and allow used power fluid 14 to be replaced. In some embodiments, leakage of power fluid 14 between power piston 30 or production piston 46 and pump housing 25 may be desirable so that power fluid 14 does not become stagnant and thereby cause contamination with microorganisms or other contaminants. In the embodiments shown in FIG. 1, FIG. 5A-5B, FIG. 12, FIG. 13, and FIG. 14, downstroke reservoir 26 may leak more past pump barrel seal 38 in comparison to upstroke reservoir 22. The composition of production piston 46 may be altered to allow for more or less leaking of power fluid 14. For example, and not by limitation, production piston 46 may be coated with Teflon™ or Kevlar™ material to allow more power fluid 14 to leak. Such an embodiment may be especially applicable when production fluid 62 comprises a high amount of solids. A softer alloy may allow more leakage while a harder alloy may allow less leakage.

In other alternative embodiments shown in FIGS. 2A-2B, upstroke reservoir 22 may leak more past pump barrel seal 38 in comparison to downstroke reservoir 26. The composition of production piston 46 may be altered to allow for more or less leaking of power fluid 14. For example, and not by limitation, production piston 46 may be coated with Teflon™ or Kevlar™ material to allow more power fluid 14 to leak. Such an embodiment may be especially applicable when production fluid 62 comprises a high amount of solids. A softer alloy may allow more leakage while a harder alloy may allow less leakage.

In another alternative embodiment, production piston 46 may comprise a larger diameter than power piston 30, providing an increase in the amount of production fluid 62 produced per day. In another embodiment, production piston 46 may comprise a smaller diameter than power piston 30, providing less pressure to lift the production fluid 62 thereby decreasing the amount of production fluid 62 produced per day. For example, a downhole unit 11 pumping at a depth of 3700 feet, with a power fluid 14 flow rate of 10 gallons per minute, comprising a production piston 46 with a diameter of 2.25 inches, and a power piston 30 with a diameter of 1.25 inches, wherein the pump housing 25 clearance between pistons 30, 46 may be between approximately 1/1000^th and 3/1000^ths of an inch, may produce about 1001 barrels of production fluid 62 per day, with about 5,935 psi of pressure in production flow line 60. A downhole unit 11 pumping at a depth of 15,000 feet, with a power fluid 14 flow rate of 2 gallons per minute, comprising a production piston 46 with a diameter of 1.5 inches, and a power piston 30 with a diameter of 1.5 inches, wherein the pump housing 25 clearance between pistons 30, 46 may be between approximately 1/1000^th and 3/1000^th of an inch, may produce about 61.2 barrels of production fluid 62 per day, with about 599.4 psi of pressure in production flow line 60. A downhole unit 11 pumping at a depth of 8,500 feet, with a power fluid 14 flow rate of 1 gallon per minute, comprising a production piston 46 with a diameter of 1.5 inches, and a power piston 30 with a diameter of 1.5 inches, wherein the pump housing 25 clearance between pistons 30, 46 may be between approximately 1/1000^th and 3/1000^ths of an inch, may produce about 30.6 barrels of production fluid 62 per day, with about 124.1 psi of pressure in production flow line 60. Of course, many other variables including but not limited to temperature and pressure may alter the relative amount of production fluid 62 produced.

In other alternative embodiments, the pump housing 25 may be of a heavy wall nature such that it may support the components and operation of downhole unit 11.

Seal

The combination of connecting rod 32 and pump barrel seal 38 may form a fluid-tight seal; as such, downstroke reservoir 26 in the embodiments shown in FIG. 1 and FIGS. 5A-5B may remain sealed from first reservoir 40 and second reservoir 42 during both the upstroke and downstroke of downhole unit 11. In other alternative embodiments, pump barrel seal 38 may be a metal-to-metal seal.

In the alternative embodiments shown in FIGS. 2A-2B, the combination of connecting rod 32 and pump barrel seal 38 may form a fluid-tight seal; as such, upstroke reservoir 22 may remain sealed from first reservoir 40 and second reservoir 42 during both the upstroke and downstroke of downhole unit 11. In other alternative embodiments, pump barrel seal 38 may be a metal-to-metal seal.

In an alternative embodiment, shown in FIG. 12, FIG. 13, and FIG. 14, the combination of connecting rod 32 and pump barrel seal 38 may form a leaking seal whereby a pump barrel seal gap 39 is formed; as such, power fluid 14 from downstroke reservoir 26 in the embodiments shown in FIG. 1 and FIGS. 12-13 may leak into first reservoir 40 and second reservoir 42 during both the upstroke and downstroke of power piston 30 and connecting rod 32, through pump barrel seal gap 39. In some alternative embodiments, shown in FIGS. 12-13, connecting rod 32 and pump barrel seal 38 are fitted so that approximately a 5/10,000^th (0.0005) inch pump barrel seal gap 39 is found between connecting rod 32 and pump barrel seal 38. This may be accomplished in such embodiments by making the diameter of connecting rod 32 be 1/1000^th (0.001) inch less than the diameter of the inner interior cavity of pump barrel seal 38. In other alternative embodiments, an approximately 15/10,000^th (0.0015) inch pump barrel seal gap 39 may allow more leakage of power fluid 14 while approximately a 5/100,000^th (0.00005) inch pump barrel seal gap 39 may allow less leakage of power fluid 14. For example, approximately a 5/10,000^th (0.0005) inch pump barrel seal gap 39 may be utilized with a 1 1/16 inch outside diameter (OD) connecting rod 32, wherein system 10 may leak approximately 20 gallons of power fluid 14 per day. This fit may allow connecting rod 32 to freely move between its top and bottom positions while substantially preventing production fluid 62 from leaking between connecting rod 32 and pump barrel seal 38 due to a pressure differential as described further below. Such an alternative embodiment may allow power fluid 14 to be injected with additives to protect the downhole unit 11 and system 10 components against corrosion or contamination that may damage the downhole unit 11 and system 10 components.

In one alternative embodiment, the connecting rod 32 may comprise a metal, and pump barrel seal 38 may comprise a metal to form a metal-to-metal seal. The sealing mechanism lifespan between failures in this alternative embodiment may be greater than two and one half years. Depending on the application, the metal-to-metal seal may be configured to vary the amount of power fluid 14 that may leak from downstroke reservoir 26 or from upstroke reservoir 22, into first reservoir 40 and second reservoir 42 during both the upstroke and downstroke of power piston 30 through pump barrel seal gap 39. The pump barrel seal 38 may be spaced around the connecting rod 32 such that the pump barrel seal gap 39 allows zero of the power fluid 14 to leak into the first reservoir 40 and second reservoir 42, but excessive friction issues between the pump barrel seal 38 and connecting rod 32 may minimize the effectiveness of the downhole unit 11 in such embodiments.

In another alternative embodiment, the pump barrel seal 38 may be spaced around the connecting rod 32 such that the pump barrel seal gap 39 allows for approximately twenty gallons per day of power fluid 14 to leak from downstroke reservoir 26 or from upstroke reservoir 22, into first reservoir 40 and second reservoir 42 during the upstroke and downstroke of power piston 30 and connecting rod 32 through pump barrel seal gap 39. Various changes of the pump barrel seal 38 spacing around connecting rod 32 may produce other pump barrel seal gap 39 configurations to increase or decrease the amount of power fluid 14 to leak from downstroke reservoir 26 or from upstroke reservoir 22, into first reservoir 40 and second reservoir 42 during the upstroke and downstroke of power piston 30 through pump barrel seal gap 39.

In one alternative embodiment, the amount of power fluid 14 to leak into the first reservoir 40 and second reservoir 42 may be controlled by the length of the pump barrel seal 38. For example, a four foot length pump barrel seal 38 with an approximately 15/10,000^th (0.0015) inch pump barrel seal gap 39 between the connecting rod 32 and pump barrel seal 38 allows less power fluid 14 to leak than a three foot length pump barrel seal 38 with an approximately 15/10,000^th (0.0015) inch pump barrel seal gap 39 between the connecting rod 32 and pump barrel seal 38.

The power side of the pump barrel seal 38, namely the upstroke reservoir 22 and downstroke reservoir 26, will generally have more pressure than the production side of pump barrel seal 38, namely the first reservoir 40 and second reservoir 42, so the power fluid 14 will generally leak from the upstroke reservoir 22 and downstroke reservoir 26 to the first reservoir 40 and second reservoir 42 through the pump barrel seal gap 39. The power fluid 14 may keep the connecting rod 32 clean by clearing any debris that may enter the production side of the pump barrel seal 38. Also due to this pressure differential, the production fluid 62 may not contaminate the power fluid 14 due to the one-way direction of power fluid 14 leak. Another benefit of the pressure differential is that chemical treatment may be applied directly into the production side of the pump barrel seal 38 through the power fluid 14.

In one alternative embodiment, since a metal-to-metal seal may allow power fluid 14 to escape from the upstroke reservoir 22 and downstroke reservoir 26, the power fluid 14 may be at least partially replenished. A commercial chemical truck may be used that would have the capability to replenish power fluid 14 supply on a periodic basis, such as a daily, weekly, monthly, or other desirable basis. In another embodiment (not shown), a closed loop system of power fluid 14 may exist because a metal-to-metal seal may not allow power fluid 14 to escape from the upstroke reservoir 22 and downstroke reservoir 26. However, because the power fluid 14 may be contaminated or may wear down with time, another alternative embodiment may allow for the power fluid 14 to be replenished or replaced in a closed loop system. In other alternative embodiments, power fluid 14 may be recycled through upstroke powerline 16 and downstroke powerline 18 back to surface unit 12.

Referring to FIG. 12, the pump barrel seal 38 may be designed for the environment in which the downhole unit 11 is placed. For example, in one alternative embodiment, the pump barrel seal 38 may comprise an alloy specifically designed to work in high H₂S environments, or the pump barrel seal 38 may comprise an alloy specifically designed to work in high CO₂ environments. Further, pump barrel seal 38 and connecting rod 32 may comprise a softer alloy if more leakage of power fluid 14 is sought, or a harder alloy if less leakage of power fluid 14 is sought.

In another alternative embodiment, the pump barrel seal 38 may function to stabilize the connecting rod 32. The connecting rod 32 may be, for example, but not limited to, in excess of eighty feet long. In such embodiments, the connecting rod 32 may be stabilized by pump barrel seal 38 in the center of the downhole unit 11 and pump housing 25 to prevent excessive wear on the connecting rod 32.

The connecting rod 32 and pump housing 25 may be comprised of metal. In one embodiment, the pump barrel seal 38 may be comprised of Kevlar™ material or may be comprised of an alloy with Teflon™ coating. In some embodiments pump barrel seal 38 may be comprised of fibrous rings in combination with an alloy.

In yet another alternative embodiment, connecting rod 32 may comprise fabricated dimples, holes, or other recesses to trap fluid to increase leakage of power fluid 14. Such dimples, holes, or other recesses may allow controlled leakage of power fluid 14.

Power Fluid

Referring to FIGS. 1, 2A, 2B, 12, 13, and 15, power fluid 14 may comprise various different compositions. The composition of power fluid 14 may be altered depending on the conditions in well 15. Water-based power fluid 14 may have low viscosity, which may minimize pressure and power loss due to friction of power fluid 14 on the inner surface area of upstroke powerline 16, downstroke powerline 18 and components of system 10. Water-based power fluid 14 may be a good carrier of additives and may have a low compressibility factor. Water-based power fluid 14 may also minimize the effects of water contamination of the surface unit 12 from rain, snow, and moisture, as water from rain, snow or other moisture dripping into surface unit 12 may simply combine with water-based power fluid 14 without significantly changing the composition of water-based power fluid 14. Water-based power fluid 14 may also be plentiful at local supplies and the acquisition cost may be low.

Power fluid 14 may also be petroleum-based, wherein the fluid has a low viscosity. Such petroleum-based power fluid 14 may be adaptable for use in low temperature environments, for example but not limited to in below zero degrees Celsius environments, as petroleum-based power fluid 14 may have a relatively lower freezing point than water-based power fluid 14 and thus petroleum-based power fluid 14 is less likely to freeze than water-based power fluid 14. Similarly, petroleum-based power fluid 14 may be used in high temperature wells 15, as petroleum has a lower boiling point than water. In an alternative embodiment, power fluid 14 may be air-based. Air-based power fluid 14 may comprise a combination of oxygen and other inert gases. Additives for air-based power fluid 14 may comprise various gases or fine solids instead of liquids or heavy solids, such that the additives are more likely to form a heterogeneous mixture with power fluid 14. Air-based power fluid 14 may be combined with liquid at high temperature to create steam, wherein the temperature of the air-based power fluid 14 is high relative to a cold well 15 or a well 15 in a cold weather environment.

Additives

In another embodiment, the power fluid 14 may include additives directed to meet the specific operating environment of well 15, for example to reduce friction between production fluid 62 or the power fluid 14 and components of system 10, thereby conserving power, or to prevent corrosion of components of system 10. When pump barrel seal 38 at least partially leaks, this may allow these additives to travel to the various components of the system 10 such that additives may be effective in various areas of system 10. Additives may include, but are not limited to, corrosion inhibitors, scale inhibitors, bactericides, friction reducers or surfactants, anti-foam agents, anti-freeze agents, anti-boil agents, agents that increase or decrease viscosity, hydrogen sulfide or carbon dioxide scavengers, and pH control additives. As mentioned previously, each well 15 may utilize a different power fluid 14 composition. Similarly, each well 15 may be assessed individually to determine what additives to put in power fluid 14. Also, the pH of power fluid 14 may be controlled in order to prevent acidic conditions or basic conditions from causing corrosion of components of system 10. In various embodiments, at least a corrosion inhibitor, a friction reducer, and a scale inhibitor may be used. Some of the variables that may be used to determine power fluid 14 composition and additives to use include the depth of well 15, the rate of production fluid 62 produced, the production fluid 62 characteristics such as salinity of the water (i.e. the amount of salts in the water), the density of hydrocarbons in production fluid 62, the characteristics of any contaminants present, the surface temperature, the downhole temperature, the wellbore diameter (which in turns affects pressure), the presence of any solids in production fluid 62, and the presence of corrosion and scale producing agents in production fluid 62.

For example and not by way of limitation, a deep well 15 (generally deeper than 12,000 feet) is more likely to have relatively high temperatures, relatively high pressure, relatively high levels of CO₂ and relatively low levels of H₂S. An embodiment of system 10 adaptable for such a deep well 15 may include a petroleum-based or water-based power fluid 14 having the following additives: corrosion inhibitors, friction reducers (because production fluid 62 and power fluid 14 have greater friction to overcome in order to move in a higher pressure environment), anti-boil agents, anti-foam agents, carbon dioxide scavengers, and a bactericide targeted to bacteria that live in high temperature, high CO₂ environments. The concentration of additives depends on the rate of production fluid 14 produced, the amount of bacteria, and other variables. Conversely, a shallow well may have relatively lower temperatures, relatively high levels of H₂S and relatively low levels of CO₂ and additives such as anti-freeze agents may be used.

In an environment having a large amount of bacteria, a bactericide may be used to kill bacteria. Bactericide may include but is not limited to a disinfectant, an antiseptic or an antibiotic, or a combination thereof. A bactericide may be chosen based on the type of bacteria present in well 15 and production fluid 62. For example, a sulfate reducing bactericide may be useful for the type of bacteria that may attack components of system 10 and thereby often are a cause of corrosion. If aerobic or anaerobic bacteria are present, the bactericide may be chosen to target either aerobic or anaerobic bacteria.

In an environment having a large amount of solids in the production fluid 62, a friction reducer may be used to help prevent solids from damaging components of system 10 or to help power fluid 14 flow through the powerlines. A friction reducer may keep hydraulic pressure low and may include but is not limited to a surfactant or guar gum. Of course, various other friction reducers are known in the art. In an environment having a large amount of scale forming components in the production fluid 62, such as calcium carbonate, a scale inhibitor may be used. A scale inhibitor may at least partially prevent or counteract the formation of scale on components.

For example, in one alternative embodiment of the power fluid 14, at a west Texas well where the downhole unit 11 is pumping from 4200 feet, producing 200 barrels of water per day (BWPD), producing 20 barrels of oil per day (BOPD), and 15 thousand cubic feet (MCF) of gas, there may be 120 parts per million (PPM) of hydrogen sulfide (H₂S) and some calcium sulfate scale-forming tendencies present. Production fluid 62 may comprise a combination of water, oil, and gas. In this embodiment, power fluid 14 may include a corrosion inhibitor, a scale inhibitor, a bactericide and a H₂S scavenger to prolong and protect the system 10.

In another alternative embodiment of power fluid 14, at a Wyoming well where the downhole unit 11 is pumping from 12,500 feet, producing 40 BWPD, 3 BOPD, and 450 MCF, there may be six percent CO₂ in production fluid 62. In this alternative embodiment, the power fluid 14 may include a corrosion inhibitor, a scale inhibitor, a CO₂ scavenger, a friction reducer, and an anti-freeze agent to prolong and protect system 10.

Power fluid 14 may be filtered before using power fluid 14 in system 10 to remove as many contaminants as possible. In one alternative embodiment (not shown), power fluid 14 may recycle itself during the operation of the downhole unit 11 and surface unit 12. In another alternative embodiment (not shown), a user may monitor certain parameters such as the quality of power fluid 14 by using a controller or by manually testing power fluid 14, and the user may then change power fluid 14, including additives in the power fluid, in the field if power fluid 14 is not within the desired parameters.

Production Tube, Upstroke Powerline and Downstroke Powerline

In some alternative embodiments, upstroke powerline 16 and downstroke powerline 18 may comprise coil tubing. Powerlines made of this material allow some alternative embodiments of the present system to be particularly useful in deviated oil wells. In other alternative embodiments, upstroke powerline 16 and downstroke powerline 18 may comprise hydraulic hose or other suitable conduits.

In various embodiments, production tube 20 may comprise jointed steel pipes that are screwed together to form a continuous conduit to downhole unit 11. In another embodiment, production tube 20 may comprise coil tubing that is installed in the casing 23 of the wellbore on a continuous section of steel pipe from a surface spool. In other alternative embodiments, production tube 20 may comprise non-ferrous pipes such as fiberglass, Kevlar™ wrapped polyvinylchloride, or other non-ferrous materials. Production tube 20 may be a conduit for production fluid 62 from the downhole unit 11 discharge to production flow line 60, or in an alternative embodiment (not shown), from downhole unit 11 discharge directly to a production facility.

Referring to FIG. 9 and FIG. 3B, in the alternative embodiments where production tube 20 is comprised of jointed steel pipes that are screwed together, upstroke powerline 16 and downstroke powerline 18 may be fastened to the outside of production tube 20 from the surface and run down through the casing 23 of the wellbore. In one alternative embodiment, upstroke powerline 16 and downstroke powerline 18 may comprise high pressure hydraulic hose or Kevlar™ wrapped polyvinylchloride and may be fastened to the outside of the production tube 20 to support the weight of upstroke powerline 16 and downstroke powerline 18, as the tensile strength of high pressure hydraulic hose is limited. In this alternative embodiment, as surface unit 12 operates, it sends power fluid 14 through upstroke powerline 16 and downstroke powerline 18, causing the powerlines to straighten out and stiffen. When surface unit 12 cycles, it stops sending power fluid 14 through either upstroke powerline 16 or downstroke powerline 18, and this may cause upstroke powerline 16 and downstroke powerline 18 to flex or slacken. This flexing, straightening out, and slacking of upstroke powerline 16 and downstroke powerline 18 causes friction that may eventually cause a rupture in upstroke powerline 16 and downstroke powerline 18. Therefore, upstroke powerline 16 and downstroke powerline 18 may be fastened to the outside of production tube 20 to ensure minimal movement of upstroke powerline 16 and downstroke powerline 18 during operation of surface unit 12.

Referring to FIG. 7 and FIG. 3A, in the alternative embodiments where production tube 20 may comprise coil tubing, upstroke powerline 16 and downstroke powerline 18 may be fastened to the inside of the production tube 20. In one alternative embodiment, upstroke powerline 16 and downstroke powerline 18 may also be made of coil tubing that may be preinstalled inside production tube 20 and installed in casing 23 of the wellbore on a continuous section of steel pipe from a surface spool. In another alternative embodiment, upstroke powerline 16 and downstroke powerline 18 may comprise high pressure hydraulic hose or Kevlar™ wrapped polyvinylchloride and may be fastened to the inside of production tube 20 to support the weight of upstroke powerline 16 and downstroke powerline 18, as the tensile strength of high pressure hydraulic hoses is limited. In this alternative embodiment, as surface unit 12 operates, it sends power fluid 14 through upstroke powerline 16 and downstroke powerline 18, and upstroke powerline 16 and downstroke powerline 18 may flex and straighten out. When surface unit 12 cycles, it stops sending power fluid 14 through either upstroke powerline 16 or downstroke powerline 18, and this may cause upstroke powerline 16 and downstroke powerline 18 to flex or slacken. This flexing, straightening out, and slacking of upstroke powerline 16 and downstroke powerline 18 causes friction that may eventually cause a rupture in upstroke powerline 16 and downstroke powerline 18. Therefore, upstroke powerline 16 and downstroke powerline 18 may be fastened to the inside of the production tube 20 to ensure minimal movement of upstroke powerline 16 and downstroke powerline 18 during operation of surface unit 12.

Referring to FIG. 8, in one alternative embodiment upstroke powerline 16 and downstroke powerline 18 may comprise high pressure hydraulic hose or Kevlar™ wrapped polyvinylchloride, and run inside of production tube 20. In this alternative embodiment, the upstroke powerline 16 and downstroke powerline 18 may be of a diameter that produces a tight fit inside of production tube 20 to ensure minimal movement of upstroke powerline 16 and downstroke powerline 18 during operation of surface unit 12 as previously discussed in the specification. This alternative embodiment does not require upstroke powerline 16 and downstroke powerline 18 to be fastened inside of production tube 20 to prevent upstroke powerline 16 and downstroke powerline 18 from rupturing.

Referring to FIG. 6, in one alternative embodiment upstroke powerline 16 and downstroke powerline 18 may be concentric or otherwise nested one within the other wherein upstroke powerline 16 may be run within downstroke powerline 18 from surface unit 12 to downhole unit 11. In this alternative embodiment, upstroke powerline 16 and downstroke powerline 18 may be run inside of production tube 20. Of course, downstroke powerline 18 may be run inside of upstroke powerline 16 in an embodiment (not shown). In one alternative embodiment, production tube 20, upstroke powerline 16, and downstroke powerline 18 may be made of coil tubing that may be preinstalled inside the production tube 20 and installed in the casing 23 of the wellbore on a continuous section of steel pipe from a surface spool. In another alternative embodiment, the downstroke powerline 18 may have a greater area than the upstroke powerline 16 to compensate for the friction between the power fluid 14 and the exterior of the concentric or nested upstroke powerline 16.

Referring to FIG. 16, in yet another alternative embodiment pump housing 25 may be substantially enclosed by an upstroke pump housing 66 and a downstroke pump housing 67 to protect the components of downhole unit 11, such as upstroke fitting 24 and downstroke fitting 28. In such an alternative embodiment, the upstroke powerline 16 may be enclosed by upstroke pump housing 66, and downstroke powerline 18 may be enclosed by downstroke pump housing 67. In this alternative embodiment, the diameter of downstroke pump housing 67 and upstroke pump housing 66 may allow the entire downhole unit 11 to fit inside of production tube 20. This configuration may also protect the entire downhole unit 11 while lowering it down into well 15.

Referring to FIG. 13 and FIG. 14, another alternative embodiment may include a conical wiper 37 that is in sliding relationship with connecting rod 32, which may be useful when downhole unit 11 operates in a high solid environment and wherein production fluid 62 comprises a large amount of debris or contaminants, for example. Conical wiper 37 may be installed above pump barrel seal 38 on the production side of the pump barrel seal 38. Conical wiper 37 may be utilized to clean debris that may enter the production side of the pump barrel seal 38 and clean debris from the connecting rod 32 during the upstroke and downstroke to protect pump barrel seal 38 from solids contamination. In an alternative embodiment, conical wiper 37 may be made of Teflon™ material. In another alternative embodiment, conical wiper 37 may be placed two to three inches above pump barrel seal 38 on the production side of the pump barrel seal 38.

In an alternative embodiment, conical wiper 37 may be positioned in sliding relationship with connecting rod 32 such that any debris or contamination that is cleaned from the production side of the pump barrel seal 38 during a downstroke is pushed from first reservoir 40 by production piston 46 through one-way valve 49, then flows through adjacent shaft 48.

Referring now to FIG. 12, as connecting rod 32, power piston 30, and production piston 46 cycle to the maximum stroke during an upstroke, production piston 46 may strike top surface 70 of pump housing 25 at a high velocity, and during a downstroke, production piston 46 may strike bottom surface 71 of pump housing 25 at a high velocity, possibly causing damage to downhole unit 11; this is also referred to as “bumping.” Similarly, power piston 30 may strike surfaces on pump housing 25 as connecting rod 32 cycles to the maximum stroke during a downstroke or upstroke possibly causing bumping to downhole unit 11. To counteract or prevent bumping, connecting rod 32, power piston 30, or production piston 46, or a combination thereof, may have a stop that may comprise Teflon™ material or other suitable material.

In another alternative embodiment shown in FIG. 10, the pump housing 25 may be partially housed within production tube 20 to allow production fluid 62 to flow from upper reservoir 53 (see FIG. 1) directly into production tube 20.

In another alternative embodiment shown in FIG. 11 and FIGS. 2A-2B, interior space of pump housing 25 is in fluid communication with production tube 20, where first reservoir 40 and second reservoir 42, and their respective inlets, are positioned below power piston 30. In this embodiment, a smaller production transport tube 17 may be positioned close to the production side of the pump barrel seal 38. The smaller production transport tube 17 may channel the production fluid 62 from the production side of the pump barrel seal 38 to the production tube 20.

In some embodiments, one-way valve 52 may be of a standard type as known in the art, that is, a ball and seat valve wherein a ball 51 rests upon a grooved slot. Referring specifically to the embodiments shown in FIG. 1 and FIG. 12, during an upstroke, ball 51 becomes unseated and allows production fluid 62 to flow from second reservoir 42, through one-way valve 52, and into upper reservoir 53. Production fluid 62 easily flows into upper reservoir 53 as ball 51 becomes unseated and production fluid 62 is pushed into upper reservoir 53. During a downstroke, ball 51 remains seated as fluid flows into upper reservoir 53 from adjacent shaft 48. As system 10 completes a pumping cycle, production fluid 62 may be continuously pushed through upper reservoir 53 and adjoining reservoirs, possibly separated by other one-way valves, until production fluid 62 reaches the surface.

While alternatives may be employed, one-way valves depicted in some embodiments may be a standard ball valve type as are known by those skilled in the art. These essentially comprise a loosely-seated metal ball or bearing resting upon a complementarily contoured orifice. When the ball is fully seated, little or no fluid may pass through the orifice. When pressure is exerted from below the ball or bearing, it is unseated, and fluid may pass through the orifice. However, when pressure is exerted from above the ball, it is forced even more into a sealed configuration, and little or no fluid may pass.

Safety Fluid Dump

After completion of operations of oil recovery, downhole unit 11 may be desired to be retrieved from the casing 23 of the wellbore. Due to various factors, including but not limited to the depth of well 15 or the lengths of powerlines 16, 18 or production tube 20, it may be difficult to remove powerlines 16, 18 or production tube 20 that may contain relatively large volumes of power fluid 14 or production fluid 62. Referring now to FIG. 15, in one alternative embodiment, a safety fluid dump 34 may be installed to facilitate pulling or removal of the powerlines 16, 18 from the casing 23 of the wellbore. The safety fluid dump 34 may be pressure activated by pressurizing the powerlines 16, 18 to a prescribed pressure that may shear the safety fluid dump 34 and empty the powerlines 16, 18 of power fluid 14 into the annulus of well 15, thus possibly decreasing the weight of powerlines 16, 18 which may facilitate easier pulling or removal of powerlines 16, 18 from the casing 23 of the wellbore.

In another alternative embodiment (not shown), a safety fluid dump may be installed to facilitate pulling or remove of the production tube 20 from the casing of the wellbore. The safety fluid dump may be pressure activated by pressurizing the production tube 20 to a prescribed pressure that may shear the safety fluid dump and empty the production tube 20 of production fluid 62 into the annulus of well 15, thus possibly decreasing the weight of production tube 20 which may facilitate easier pulling or removal of production 20 from the casing 23 of the wellbore.

In various embodiments, a safety fluid dump 34 that communicates with the annulus of well 15 may be installed to facilitate pulling or removal of upstroke powerline 16 or downstroke powerline 18 having a fluid dump 34 from the casing 23 of the wellbore. The safety fluid dump 34 may be pressure activated by pressurizing the desired upstroke powerline 16 or downstroke powerline 18 to a prescribed pressure that may shear the safety fluid dump 34 and empty the upstroke powerline 16 or downstroke powerline 18 of power fluid 14 into well 15. In some embodiments, a fluid dump 34 may be a rupture disk as known in the art.

Surface Unit—Controller

In an alternative embodiment (not shown), surface unit 12 may comprise a controller. A controller may electronically configure the maximum stroke of the connecting rod 32, power piston 30, and production piston 46 during an upstroke or downstroke based on the mechanical maximum stroke of downhole unit 11. In one alternative embodiment, the controller may activate downhole unit 11 to its mechanical maximum stroke based on data received from various transducers in system 10. The controller may then configure surface unit 12 to move connecting rod 32, power piston 30, and production piston 46 at an electronic maximum stroke that may be less than the mechanical maximum stroke to reduce any bumping to downhole unit 11. In another alternative embodiment, the controller may continuously monitor data from transducers in system 10. The controller may then continuously configure the electronic maximum stroke of surface unit 12.

In various embodiments, the controller may have a soft start feature that allows surface pump unit 12 to operate slower for a few strokes and after a predetermined time, and gradually operates at a faster speed up to the maximum speed of the surface pump unit 12. In such an embodiment, downhole unit 11 may be powered at reduced power settings to minimize any damage caused by debris or contamination in downhole unit 11. In some alternative embodiments the controller may start the downhole unit 11 on an upstroke so power fluid 14 lubricates connecting rod 32 and production piston 46. A controller may use a differential pressure transducer to determine the level of production fluid 62 being produced from a production flow line 60. As the level of production fluid 62 decreases, the required pressure and volume of power fluid 14 will be increased appropriately according to the prescribed degree of submersion of downhole unit 11 in order to achieve a desired amount of production. When downhole unit 11 of the hydraulic downhole oil recovery system 10 may be at a prescribed submersion, a controller may vary the power fluid 14 volume in upstroke powerline 16 and downstroke powerline 18 to maintain the desired production fluid 62 level in well 15. The downhole unit 11 may continuously run as surface unit 12 may continue to run, thereby maximizing oil reservoir drawdown and inflow rate from downhole unit 11 pump suction.

In some alternative embodiments, a controller may equalize upstroke powerline 16 and downstroke powerline 18 at the completion of an upstroke or downstroke of power piston 30 and production piston 46. For example, upstroke powerline 16 may contain 3000 psi of power fluid 14, while downstroke powerline 18 may be open to a return tank (not shown) with 0 psi of power fluid 14. This alternative embodiment allows equalization to speed up and reduces wear on system 10. Without this alternative embodiment, upstroke powerline 16 may have to be bled from 3000 psi of power fluid 14 to 0 psi of power fluid 14 while downstroke powerline 18 will have to be pressurized from 0 psi to 3000 psi of power fluid. Persons of ordinary skill in the art will recognize that the pressure of power fluid 14 in upstroke powerline 16 and downstroke powerline 18 depends on many variables and may vary depending on the application or operating environment of system 10.

In another alternative embodiment, a controller may be equipped with an alarm panel. An alarm panel may shut down the surface unit 12 if the pumping parameters change significantly. For example, a surface leak might develop that may result in a greater draw down of production fluid 62 in well 15, or a leak might develop in upstroke powerline 16 or downstroke powerline 18. The controller may sense the increased fluid loss of production fluid 62 or power fluid 14 from various transducers and shut down surface unit 12. An alarm panel may also be wired to a “call out” unit. For example and not by way of limitation, when the controller senses that the pumping parameters have changed significantly, the alarm panel may send a signal to the “call out” unit to alert maintenance personnel that there is an alarm.

In yet another alternative embodiment, a controller may be equipped with a history panel. The history panel may have a screen and an interface for a user to access the history panel. The history panel may archive data including, but not limited to, past run times of the downhole unit 11, volume of production fluid 62 being produced by downhole unit 11, or volume of power fluid 14 being used. A user may access the archived data by utilizing the interface. In some alternative embodiments, the history panel may also display or archive other data from various transducers that may be installed on system 10, such as power fluid 14 temperature, production fluid 62 temperature, power fluid 14 gallons per minute (GPM), strokes per day or strokes per minute of the downhole unit 11, and other data that may be configured depending on the application.

In another alternative embodiment, one controller may operate several surface units 12. In other alternative embodiments, one surface unit 12 may have the capability to provide the desired power fluid 14 pressure to a plurality of wells 15 and several downhole units 11. The surface unit 12 may comprise any type of pump that is capable of providing the pressure and volume of power fluid 14 desired to operate a downhole unit 11. Some types of pumps that may be utilized by surface unit 12, include, but are not limited to, gear pumps, progressive cavity pumps, duplex pumps, triplex pumps, or quintaplex pumps, or a combination thereof. In one alternative embodiment, surface unit 12 may be driven by a DC variable speed motor, but may also be driven by an AC variable speed motor.

Although the foregoing specific details describe certain embodiments of this invention, persons of ordinary skill in the art will recognize that various changes may be made in the details of this invention without departing from the spirit and scope of the invention as defined in the appended claims and considering the doctrine of equivalents. Therefore, it should be understood that this invention is not to be limited to the specific details shown and described herein.

Claims

1. An oil recovery system comprising:

a generally hollow pump housing having an interior space;

a downstroke powerline and an upstroke powerline in fluid communication with said interior space of said pump housing;

a power piston disposed in said interior space of said pump housing;

a connecting rod disposed in said interior space of said pump housing and having a first end attached to said power piston;

a production piston being attached to a second end of said connecting rod;

a seal disposed between said production piston and said power piston;

an oil inlet in fluid communication with a reservoir located in said interior space of said pump housing; and

an oil inlet valve in fluid communication with said oil inlet;

wherein said power piston is movable between a first position and a second position by power fluid delivered through said upstroke powerline or said downstroke powerline; and

wherein said seal allows at least a portion of said power fluid to pass through said seal.

2. The oil recovery system of claim 1 wherein said downstroke powerline and said upstroke powerline comprise coil tubing.

3. The oil recovery system of claim 1 wherein said pump housing comprises coil tubing.

4. The oil recovery system of claim 1 wherein said production piston is disposed at a bottom end of said connecting rod and said power piston is disposed at a top end of said connecting rod.

5. The oil recovery system of claim 1 wherein said production piston is disposed at a top end of said connecting rod and said power piston is disposed at a bottom end of said connecting rod.

6. The oil recovery system of claim 1 wherein said power fluid comprises water-based fluid.

7. The oil recovery system of claim 1 wherein said pump housing is removable.

8. The oil recovery system of claim 1 further comprising a surface pump unit having a sensor wherein said surface pump unit is connected to said downstroke powerline and said upstroke powerline.

9. The oil recovery system of claim 1 wherein said power piston moves upward when power fluid travels through said upstroke powerline and into an upstroke reservoir located in said interior space of said pump housing.

10. The oil recovery system of claim 1 wherein said power piston moves downward when power fluid travels through said downstroke powerline and into a downstroke reservoir located in said interior space of said pump housing.

11. The oil recovery system of claim 1 wherein said upstroke powerline and said downstroke powerline extend along a length of said pump housing.

12. The oil recovery system of claim 1 wherein said power piston and said production piston are shaped and sized such that production fluid is sucked through said oil inlet valve and into a first reservoir upon an upstroke of said power piston.

13. The oil recovery system of claim 1 further comprising a second oil inlet in fluid communication with a second reservoir located in said interior space of said pump housing.

14. The oil recovery system of claim 1 wherein said oil inlet is disposed in fluid communication with said seal.

15. The oil recovery system of claim 14 further comprising a valve disposed in fluid communication with said oil inlet valve.

16. The oil recovery system of claim 1, wherein said power fluid comprises at least one additive.

17. The oil recovery system of claim 16 wherein said at least one additive is selected to inhibit biological corrosion of at least one component of said oil recovery system.

18. The oil recovery system of claim 16 wherein said at least one additive is selected to inhibit chemical corrosion of at least one component of said oil recovery system.