DOWNHOLE COMPRESSOR FOR CHARGING AN ELECTRICAL SUBMERSIBLE PUMP

Abstract

Downhole Electric Submersible Pumps (ESP) in a production string often experience gas lock caused by free gas present in the production liquids which reduces the intake pressure below operating parameters of the ESP. A compressor is disclosed for compressing production fluid prior to feeding the production fluid into an ESP intake. The compression entrains or dissolves free gas into the production liquid, reducing the risk of gas lock of the ESP. The compression increases production fluid pressure to within the operating pressure of the ESP intake, to a selected pressure, or to above the free gas bubble point.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

None.

FIELD OF INVENTION

The disclosure generally relates to production of hydrocarbon-bearing fluids from a wellbore extending through a subterranean reservoir. More particularly, the disclosure addresses apparatus and methods for compressing produced fluids having both liquid and free gas components prior to intake into an electrical submersible pump.

BACKGROUND OF INVENTION

In the production of hydrocarbons from a wellbore extending through a hydrocarbon-bearing zone in a reservoir, a production string or tubing is positioned in the wellbore. A production string can include multiple downhole tools, pipe sections and joints, sand screens, flow and inflow control devices, etc. To pump production fluid to the surface, an electrical submersible pump (ESP), powered by an electric motor through a drive shaft, is positioned downhole in the wellbore. Electrical power is usually provided from a surface source by a power cable extending to the downhole electric motor. Additional tools used in conjunction with an ESP and electric motor include seal subassemblies, protectors, sensor assemblies, gas separators, additional pumps, standing valves, etc. The electric motor powers the pumps, separators, etc., via a drive shaft connected to the rotary elements of these devices.

A submersible pump can see dozens of shut-offs each year for various reasons. Unwanted and nuisance shut-offs include those caused by gas lock, a condition in pumping and processing equipment caused by induction of free gas. The presence of compressible gas interferes with operation of the pump, thereby preventing intake of production fluid. The production fluid often contains two or more fluids. Gas can be found dissolved in the production fluid or merely mixed, in a gaseous phase as free gas, with production liquids. The free gas can exist in situ in the reservoir or can evolve during production as pressure drops below the bubble point.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the features and advantages of the present invention, reference is now made to the detailed description of the invention along with the accompanying figures in which corresponding numerals in the different figures refer to corresponding parts and in which:

FIG. 1 is a schematic view of an exemplary well system utilizing an embodiment of a compressor assembly disclosed herein;

FIG. 2 is a schematic partial view of an exemplary tubing string having various downhole tools thereon, including a submersible pump and motor for use in conjunction with a compressor assembly according to the disclosure; and

FIG. 3 is a cross-sectional, schematic view of an exemplary compressor assembly according to an aspect of the disclosure.

It should be understood by those skilled in the art that the use of directional terms such as above, below, upper, lower, upward, downward and the like are used in relation to the illustrative embodiments as they are depicted in the figures, the upward direction being toward the top of the corresponding figure and the downward direction being toward the bottom of the corresponding figure. Where this is not the case and a term is being used to indicate a required orientation, the Specification will state or make such clear.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

While the making and using of various embodiments of the present disclosure are discussed below, a practitioner of the art will appreciate that the disclosure provides concepts which can be applied in a variety of specific embodiments and contexts. The specific embodiments discussed herein are illustrative of specific ways to make and use the disclosed apparatus and methods and do not limit the scope of the claimed invention.

As used herein, the words “comprise,” “have,” “include,” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps. It should be understood that, as used herein, “first,” “second,” “third,” etc., are arbitrarily assigned, merely differentiate between two or more items, and do not indicate sequence. Furthermore, the use of the term “first” does not require a “second,” etc.

The terms “uphole” and “downhole,” “upward” and “downward,” and the like, refer to movement or direction with respect to the wellhead, regardless of borehole orientation. The terms “upstream” and “downstream” refer to the relative position or direction in relation to fluid flow, irrespective of the borehole orientation. Although the description may focus on particular means for positioning tools in the wellbore, such as a tubing string, coiled tubing, or wireline, those of skill in the art will recognize where alternate means can be utilized. Directional terms, such as “above” and “below” may also be used with respect to the Figures as shown and so do not limit to the orientation of the assembly or tool in use.

FIG. 1 is a schematic illustration of a well system, indicated generally 10, having a gas compressor assembly according to an embodiment of the disclosure. A wellbore 12 extends through various earth strata, including at least one production zone 20. Exemplary wellbore 12 has a substantially vertical section 14 and a substantially deviated section 18, shown as horizontal, which extends through a hydrocarbon-bearing subterranean zone 20. As illustrated, the wellbore is cased with a casing 16 along an upper length. The wellbore is open-hole along a lower length. The disclosed apparatus and methods will work in various wellbore orientations and in open or cased bores.

Positioned within wellbore 12 and extending from the surface is a production tubing string 22. Typically the production tubing string is hung from or attached to the casing or wellhead. The production tubing string 22 provides a conduit for production fluids to travel from the formation zone 20 up to the surface. Positioned within the string 22 in various production intervals adjacent to the zone 20 are a plurality of production tubing sections 24. Annular isolation devices 26, such as packers, provide annular seals to fluid flow and differential pressure in the annulus defined between the production tubing string 22 and the casing 16. The areas between adjacent isolation devices 26 define production intervals.

In FIG. 1, the production tubing sections 24 include sand control capability such as sand control screen elements to allow production fluid to flow therethrough but filter particulate matter of sufficient size. Other tools and mechanisms can be used in conjunction with the production string along the production zone, such as flow control devices, autonomous flow control devices, check valves, protective shrouds, sliding sleeve valves, etc. Such elements are well known in the industry.

The production string allows production fluid to enter the string. The production fluid can have multiple components, such as oil, water, natural gas and other gases, in varying proportions. Further, the composition of the production fluid can vary between production intervals. The term “natural gas” as used herein means a mixture of hydrocarbons and varying quantities of non-hydrocarbons that exist in a gaseous phase at room temperature and pressure. The term does not indicate that the natural gas is in a gaseous phase at the downhole location of the inventive systems. Where it is intended to refer to a substance in a gaseous phase, the terms “free gas,” “gaseous phase,” or similar, is used. It is to be understood that at formation pressure and temperature, natural gas may exist dissolved in a liquid or mixed with a liquid. Such natural gas can evolve to a gaseous phase, for example, in the production string under lower pressures or temperatures. The disclosed apparatus and methods are useful to entrain or dissolve evolved free gas into the liquid components of the production fluid.

The production tubing string seen in FIG. 1 also includes an exemplary and schematic “tool stack” 28 or series of tools for managing production fluid downhole and pumping production fluid to the surface. The tools presented are exemplary, non-limiting, and are discussed with further respect to FIG. 2.

FIG. 2 is a schematic view in elevation of an exemplary tubing string having various downhole tools thereon, including a submersible pump and motor for use in conjunction with a gas compressor assembly according to the disclosure.

The tubing string 30 includes multiple downhole tools connected to one another and positioned below a string of tubulars 32 extending to the surface. The exemplary tubing string 30 includes a sensor assembly 34, an electric motor assembly 36, a seal subassembly 38, a protector assembly 40, a gas separator assembly 42, a gas compressor assembly 44, and an electrical submersible pump assembly 46. Additional tools can be employed, including multiple pumps, separators, and protectors. The tools are connected to one another using threaded connections or other connection mechanisms. Attached to and extending below the illustrated string is a production string extending through one or more production zones of the reservoir and typically having sand screens, flow control devices, inflow control devices, valves, and the like, and into which production fluid from the reservoir flows. The ESP assembly pumps the production fluid to the surface via tubulars 32.

The sensor assembly 34 can be of various types for measuring various downhole environmental or motor characteristics. Preferably the sensor assembly includes pressure and temperature sensors. Measurements are conveyed to the surface by wire or wirelessly, providing the motor operator data for use in controlling the motor. A preferred sensor assembly includes a surface transceiver module, a surface safety choke, downhole temperature and pressure sensors, and various adapters, connectors, and power sources. The sensors are connected to the ESP motor 50. A preferred sensor assembly includes a temperature sensor for measuring fluid temperature, a motor oil temperature sensor, and motor winding temperature sensor. A pressure sensor measures fluid pressure at the sensor location. Optionally, a vibration sensor, measuring vibration on three axes, is also present. The transceiver module provides power to and receives measurement data from the sensors. The measurements are conveyed to the surface. Preferably, the system automatically shuts down when measurements exceed a pre-determined and pre-programmed maximum. Sensor systems are commercially available, such as the sensor systems sold as Global or Halliburton Artificial Lift Sensor Systems, available from Halliburton Energy Services, Inc.

The electric motor assembly 36 includes a housing 48 and a rotary electric motor 50 having a drive shaft 52 extending therefrom. The electric motor is powered by electricity delivered along power cable 54 extending from the surface. The cable is typically disposed in a protective conduit and can run either along the interior or exterior of the string. Electric ESP motors are commercially available, for example, from Halliburton Energy Services, Inc. The motor specifications are selected based on operating and well conditions as will be understood by those of skill in the art. The ESP motor 50 is connected to the sensor system and is typically controlled by a motor operator and has selected automatic shut-offs based on sensor data. The drive shaft 52 extends from the upper end of the motor and drives the separators, compressors, and ESPs on the production string.

The seal sub 38 and protector 40, sometimes also referred to as a seal, can serve to prevent production fluid or contaminants from entering the ESP motor 36 by equalizing interior and exterior pressure, provide a dielectric or other acceptable motor oil reservoir, conduct heat away from the motor, and compensate for pressure to absorb thermal expansion. A thrust bearing accepts fluid column load upon start-up and absorbs axial load of the ESP pump 46. Protectors are available in varying sizes and weight specifications and varying configurations, including labyrinth, pre-filled, single, double and modular bag, or combinations arranged in series or parallel. Further, models are available for high-load thrust bearing and high-strength shaft. Protectors are commercially available from Halliburton Energy Services, Inc. One or multiple seals or protectors can be employed on an ESP production string.

The gas separator assembly 42 is positioned up-hole from the protector 40, and, like the protector, can be employed as a single unit or multiple stacked units. A gas separator typically imparts a rotation to the production fluid to liberate free gas from the production fluid. The free gas is then vented to the wellbore annulus via one or more outlets. This reduces produced free gas, disposal of unwanted gas production, workload of the ESP and ESP motor, and the volume of production necessary to produce a given quantity of oil. The separator is driven by the ESP motor 36 via drive shaft. Gas separators are known in the art and commercially available, for example, from Halliburton Energy Services, Inc.

The gas compressor assembly 44 is positioned between the separator 42 and ESP assembly 46. The gas compressor assembly 44 is discussed in detail below with reference to FIG. 3. Generally, the compressor receives production fluid through an intake and, via centrifugal forces, compresses it to reduce or eliminate free gas in the fluid. The compressor also raises fluid pressure prior to discharge into the ESP 46 such that the ESP intake is “pre-charged” or “charged” to a pressure within its operating range. The centrifugal force produced by the compressor entrains free gas into a gas-liquid mixture and dissolves gas into the production liquid. The compressor is preferably powered by the ESP motor via a drive shaft although alternative power sources can be applied. Production fluid entering the compressor proceeds through multiple compressor stages, with fluid pressure increased at each stage. Stages are arranged in series to produce a desired fluid pressure upon discharge to the ESP intake.

Further, the compressors provide increased fluid pressure without restricting fluid flow; that is, the compressor does not utilizing a restrictor plate, orifice plate, back-pressure device, diffuser, or other mechanism to restrict fluid flow. Where such mechanisms are used, the restriction becomes a high-wear point and is susceptible to failure due to erosion, especially when the production fluid a high sand content. Erosion can result in cutting of the tool in two, with a resultant loss of the lower portion of the tool and any tools connected below. A fishing trip to retrieve the dropped string is expensive and time consuming. Further, such restrictions tend to plug with debris, such as rubber from previously run units. The compressor 44 handles debris more easily, eliminates high-erosion points at restrictions, reduces the likelihood of failure due to erosion, and prolongs the useful life of the tool. The compressor design does not restrict or limit fluid flow, or hydrocarbon production, to increase fluid pressure, as will be seen in relation to FIG. 3.

The ESP assembly 46 pumps production fluid to the surface. The ESP intake receives fluid from the last sequential compressor 44 at a pressure within the operating limits of the ESP, eliminating or reducing the risk of gas lock. The ESP is preferably rotated by a drive shaft powered by the motor 36. Alternate power sources can be employed. For centrifugal ESPs, the number of stages determines the total lift provided and determines the total power required for operation. Sensors and instrumentation can be employed to provide operating condition data to the operator or for automatic operation. For example, automatic shut-down sensors can be used to limit potential damage from unexpected well conditions. ESP specifications include a minimum fluid pressure requirement at the pump intake. The compressor 44 (or multiple compressors in series) is selected to provide production fluid to the ESP intake within its operating range.

FIG. 3 is a cross-sectional schematic view of an exemplary compressor assembly according to an aspect of the disclosure. An exemplary compressor 60 is seen having three stages or sections 62a-c arranged in series. Each stage increases the pressure of the production fluid. As an example, the first compressor stage 62a increases pressure by 8 psi (55 kPa), the second compressor stage 62b further increases pressure by 16 psi (110 kPa), and the third compressor stage 62c further increases pressure by 24 psi (165 kPa), resulting in a total increase across the compressor of approximately 48 psi (331 kPa). Additional stages, or stages increasing the pressure by greater amounts, can be employed to achieve higher total increase of fluid pressure. For example, in a preferred embodiment, the pressure is raised by about 16 psi (110 kPa) to 65 psi (448 kPa), and more preferably by about 40 psi (276 kPa) to 60 psi (414 kPa). The stages are selected to increase the production fluid pressure to a pressure within the operating range of the ESP, thereby preventing gas lock. Additional or fewer stages can be employed based upon required ESP intake pressure.

A tubular compressor housing 68, preferably generally cylindrical as shown, is attached to a base assembly 70 and a head assembly 72 via lock plates 74. The lock plates can be replaced or supplemented with other connection mechanisms, such as threaded connectors, pins, welds, and the like. A compression tubular 76, made-up of a plurality of tubulars 76a-c, is positioned interior to the housing 68. The compressor, in this embodiment, has three compressor stages 62a-c, although fewer or more can be used. Above and below each stage 62 is preferably positioned a shaft support assembly 78 for supporting compressor shaft 80 which extends the length of the compressor 60. The compressor housing 68 is preferably made of corrosion-resistant material such as carbon steel or 9 chrome 1 molly. The compression tubular 76 is preferably made of stainless steel or other material having the strength required to prevent collapse of the tool assembly.

The base assembly 70 and head assembly 72 are each comprised of a generally tubular housing which can be connected to tools or additional tubulars, such as by bolt assemblies 82 and 84, respectively. Alternate connections can be used as are known in the art. The base assembly defines an interior passageway 86, forming an intake 88 for the compressor assembly, providing fluid communication with a tool below, such as gas separator 42. The base interior passageway 86 delivers fluid into the intake of the first compressor stage 62a. Similarly, the head assembly 72 defines interior passageway 90, having an intake for receiving fluid from the third compressor stage 62c. The head assembly forms a discharge outlet 92 for the compressor assembly, which delivers compressed fluid from the third compressor stage 62c to a tool or tubular positioned above, such as ESP assembly 46.

The rotary shaft 80 extends the length of the compressor assembly and causes rotation of each of the three stages 62a-c. The shaft is supported by multiple support assemblies 78a-d. At the upper and lower ends of the shaft are connections 94 for connection to similar shafts positioned in adjacent tools, such as gas separator 42 and ESP assembly 46. The shaft can be specialized for high-torque systems and is preferably of corrosion-resistant material. The shaft can be monolithic or formed of several connected shaft components. The shaft is driven by the drive shaft 52 of the electric motor 50.

The three stages 62a-c are of similar construction and design. The first stage 62a is discussed in detail, with the remaining stages having similar components and functions. The first stage 62a has a helical blade 100a extending radially outward from a compressor sleeve 102a. The sleeve 102a forms a tubular and is positioned about and attached to a section of the shaft 80. (Alternately, the helical blade can be formed about a portion of the shaft itself.) The rotary blade and sleeve can be formed of a plurality of adjacent units for ease of manufacture and assembly. Rotation of the shaft 80 results in rotation of the sleeve 102a and helical blade 100a. Production fluid received from the base assembly passageway 86 is received into the first stage, where the rotation of the helical blade 100a causes the fluid to rotate, thereby increasing the fluid pressure. Existent free gas in the production fluid is dissolved into or entrained with production liquids. The pressurized fluid is then output to a subsequent stage, such as stage 62b, for further treatment, or through the discharge head passageway 90 to a tool assembly positioned above, such as ESP 46. The fluid pressure is preferably increased by an incremental amount such that the stage remains relatively small. For example, an exemplary fist stage 62a is approximately four inches in diameter, twelve inches in length, and imparts a pressure increase of approximately 8 psi (55 kPa).

The helical blade 100a extends radially outward from the sleeve 102a (or shaft). The blade is “wrapped” about the sleeve, forming a helical shape. The blade appears to be wrapped although other manufacturing methods (e.g., casting) can be used to make the unit. The stage is specifically designed to increase fluid pressure, or add lift or head. To that end, the compressor helical blade 100a is positioned in the interior passageway 104a defined by the compression tubular 76a, with a relatively small clearance. For example, in a preferred embodiment where the compressor helical blade is inserted into a tube, the radial clearance is about 0.144 inches (0.366 cm) in a 3.75 inch (9.53 cm) diameter bore. In another preferred embodiment, the compressor blade is positioned in a honed bore, allowing for better tolerances and reduced clearances. For example, in a honed bore a preferred clearance is approximately 0.003 inches (7.62 mm) in a 3.75 inch (9.53 cm) diameter bore. The tight clearance reduces annular bleed-by of gaseous and liquid fluids which, if present, decreases the effectiveness and the head added to the fluid by the compressor helical blade. The increased effectiveness allows an equivalent amount of head to be added to the production fluid using a lower motor rate (rpm), thereby saving energy, reducing operating temperatures of the motor, decreasing burn-out, etc. In a preferred embodiment, the compressor blade is operated in a range of 3500 to 4500 rpm using an electric motor positioned downhole. In addition to reducing bleed-by due to excessive blade clearance, the blade is mounted in the only tubular through which the production fluid flows at this section of the string. That is, there is no annular space between the compression tube 76a and the housing 68 through which fluid may flow or bypass the compressor blade. Finally, the preferred embodiment is difficult to impossible to plug during use with coal fines, sand, etc. The helical compressor blade will elevate or move fines and the like during rotation. The tight radial clearance will not allow debris accumulation along the compression tube wall. Additionally, the helical blade 100 does not flatten out into substantially vertical, radially extending paddles at any point. Such paddles create a fluid vortex, agitate the fluid, and decreases the effectiveness of the blade in increasing fluid pressure or lift. For a cross-reference, see US Patent Application Publication 2012/0269614, to Bassett, which is hereby incorporated for all purposes.

The second stage 62b and third stage 62c operate in a similar fashion, each causing rotation of the production fluid, incrementally increasing the fluid pressure, and dissolving or entraining existent free gas. In an exemplary embodiment, the second stage imparts an additional 16 psi (110 kPa) and the third stage imparts an additional 24 psi (165 kPa) to the fluid. The production fluid is discharged to the ESP at approximately 48 psi (331 kPa) or greater and within the pressure requirements for the ESP intake.

Positioned above and below each stage are shaft support assemblies 78a-d. In use, the shaft support assemblies support the shaft 80, preventing axial bending of the shaft. The shaft support assemblies 78a and 78d are positioned, respectively, in the base 70 and head 72, while the shaft support assemblies 78b-c are positioned in the compression tubular 76. Alternate arrangements are possible as will be understood by those of skill in the art. For purposes of discussion, shaft support assembly 78c is considered in detail.

Shaft support assembly 78c has a bearing housing 110c with a support sleeve 112c and bushing 114c positioned therein. The bearing housing 110c is mounted within a support compression tubular 116c. The support compression tubular 116c forms part of the compression tubular 76. The design shown provides ease of assembly, however, other arrangements will be readily apparent to those of skill in the art. For example, the compression blades, support assemblies, etc., can be internally mounted into a single compression tubular. In a preferred embodiment, the support assembly, or portions thereof, is made of corrosion-resistant materials. For example, the support tubular 116 is preferably of a corrosion-resistant nickel alloy and the sleeve 112 and bushing 114 are of tungsten carbide. Alternate corrosion and erosion-resistant materials and methods will be readily apparent to those of skill in the art.

The compressor assembly, or charger, is designed for use with production tubing and mounted below one or more ESPs, although additional uses will be apparent to those of skill in the art. Preferably the compressor includes more than one stage, with each successive stage incrementally increasing the fluid pressure to a desired pressure range corresponding to the intake specifications of the ESP into which the fluid is discharged. Production fluid enters the wellbore annulus and, typically after flowing through screens or filters, into an interior passageway or bore in the production string. The fluid flows towards the surface, through a series of downhole tools. For example, in an exemplary production string, the production fluid flows through a sensor assembly, a motor assembly, one or more seal subs, one or more protectors, one or more gas separators, a gas charger of one or more stages as disclosed herein, and one or more ESPs, and thence to the surface. Preferably the motor powers, by a drive shaft connected to tool assembly shafts, the plurality of powered tools, including the gas separator, gas charger, and ESP, for example. The motor receives electrical power from the surface via cable in a preferred embodiment.

The compressor can be used at any well depth, typically ranging from 500 feet to over 13,000 feet deep. The gas charger is expected to be most effective in wells producing production fluid at or below 1250 barrels per day, and down to as little as 150 bpd. It is also anticipated that the compressor will be of greater use in wells producing larger volumes of free gas, where the compressor will entrain or dissolve the free gas into the production liquid. The compressor can vary in size. In a preferred embodiment, a compressor tool is approximately four inches in diameter and approximately 36 inches in length per section. Overall length, obviously, is dependent on the number of stages employed. The compressor design also reduces the likelihood of plugging due to debris in the production fluid. The helical design of the compressor blade 100 provides a greater flow area than alternative compressors having impellers and diffusers.

Among the preferred embodiments, various methods or processes are disclosed and addressed as steps. The steps are not exclusive and can be combined in various ways, with steps omitted, added, re-ordered, and/or repeated, as will be recognized by those of skill in the art. The methods are limited only by the claims as construed by applicable law. The following methods are numbered for ease of reference and are exemplary in nature. 1. A method of producing fluid from a subterranean well having a wellbore extending through a hydrocarbon-bearing formation, the method comprising the steps of: positioning at a downhole location in the wellbore a work string having an electric motor, a compressor assembly, and an Electric Submersible Pump (ESP); operating the compressor assembly and the ESP using the electric motor; pumping production fluid from the formation and into an interior passageway of the work string, the production fluid having both free gas and production liquid therein; compressing the production fluid using the compressor assembly, and entraining or dissolving at least a portion of the free gas into the production liquid; and feeding the compressed production fluid to an intake of the ESP. 2. The method of claim 1, wherein the step of compressing further comprises compressing the production fluid to an intake pressure within the operating range of the ESP intake. 3. The method of claims 1-2, wherein the step of compressing further comprises compressing the production fluid by between about 8 psi (55 kPa) and 60 psi (414 kPa). 4. The method of claims 1-3, wherein the step of compressing further comprises compressing the production fluid to a pressure above the free gas bubble point at the downhole location. 5. The method of claims 1-4, wherein the step of compressing further comprises compressing the production fluid in multiple stages in the compressor assembly, and wherein each of the multiple stages compresses the production fluid by between about 8 psi (55 kPa) and 32 psi (221 kPa). 6. The method of claims 1-5, wherein the compressor assembly is positioned in the string between the electric motor and the ESP. 7. The method of claims 1-6, further comprising the step of pumping the compressed production fluid to the surface. 8. The method of claims 1-7, wherein the compressor assembly includes a rotary compressor element attached to a compressor drive shaft, and further comprising the step of driving the rotary compressor drive shaft by a drive shaft of the electric motor. 9. The method of claims 1-8, further comprising the step of separating at least some free gas from the production fluid using a gas separator tool prior to the step of compressing the production fluid using the compressor assembly. 10. The method of claims 1-9, wherein the compressor assembly allows fluid flow therethrough without fluid flow restriction. 11. The method of claims 1-10, wherein the step of compressing further comprises the step of supporting a drive shaft of the compressor assembly with at least one bearing. 12. The method of claim 11, wherein the at least one bearing comprises a corrosion-resistant bushing.

Persons of skill in the art will recognize various combinations and orders of the above described steps and details of the methods presented herein. While this invention has been described with reference to illustrative embodiments, this description is not intended to be construed in a limiting sense. Various modifications and combinations of the illustrative embodiments as well as other embodiments of the invention, will be apparent to persons skilled in the art upon reference to the description. It is, therefore, intended that the appended claims encompass any such modifications or embodiments.

Claims

1. A method of producing fluid from a subterranean well having a wellbore extending through a hydrocarbon-bearing formation, the method comprising the steps of: positioning at a downhole location in the wellbore a work string having an electric motor, a compressor assembly, and an Electric Submersible Pump (ESP);operating the compressor assembly and the ESP using the electric motor;pumping production fluid from the formation and into an interior passageway of the work string, the production fluid having both free gas and production liquid therein;compressing the production fluid using the compressor assembly, and entraining or dissolving at least a portion of the free gas into the production liquid; andfeeding the compressed production fluid to an intake of the ESP.

2. The method of claim 1, wherein the step of compressing further comprises compressing the production fluid to an intake pressure within the operating range of the ESP intake.

3. The method of claim 1, wherein the step of compressing further comprises compressing the production fluid by between about 8 psi (55 kPa) and 60 psi (414 kPa).

4. The method of claim 1, wherein the step of compressing further comprises compressing the production fluid to a pressure above the free gas bubble point at the downhole location.

5. The method of claim 1, wherein the step of compressing further comprises compressing the production fluid in multiple stages in the compressor assembly, and wherein each of the multiple stages compresses the production fluid by between about 8 psi (55 kPa) and 32 psi (221 kPa).

6. The method of claim 1, wherein the compressor assembly is positioned in the string between the electric motor and the ESP.

7. The method of claim 1, further comprising the step of pumping the compressed production fluid to the surface.

8. The method of claim 1, wherein the compressor assembly includes a rotary compressor element attached to a compressor drive shaft, and further comprising the step of driving the rotary compressor drive shaft by a drive shaft of the electric motor.

9. The method of claim 1, further comprising the step of separating at least some free gas from the production fluid using a gas separator tool prior to the step of compressing the production fluid using the compressor assembly.

10. The method of claim 1, wherein the compressor assembly allows fluid flow therethrough without fluid flow restriction.

11. The method of claim 1, wherein the step of compressing further comprises the step of supporting a drive shaft of the compressor assembly with at least one bearing.

12. The method of claim 11, wherein the at least one bearing comprises a corrosion-resistant bushing.

13. The method of claim 1, wherein the step of compressing the production fluid using the compressor assembly, further comprises rotating a helical compressor blade within a compressor tubular.

14. The method of claim 13, wherein a clearance between the helical compressor blade and the compressor tubular is minimized.

15. The method of claim 13, wherein all production fluid in the interior passageway is compressed in the compressor assembly.

16. An apparatus for lifting production fluid from a subterranean wellbore extending through a hydrocarbon-bearing formation to the surface, the apparatus comprising: an Electrical Submersible Pump (ESP) having a fluid intake;a compressor having at least one compressor stage for compressing production fluid, the compressor stage having a fluid discharge in fluid communication with the ESP fluid intake, a generally helical compressor blade mounted for rotation in a generally cylindrical chamber, and wherein the compressor blade entrains or dissolves a free gas component of a production fluid into a liquid component of the production fluid; andan electrical motor for powering the ESP and compressor.

17. The apparatus of claim 16, further comprising a plurality of adjacent compressor stages arranged in series, with each compressor stage discharging fluid to an intake of an adjacent compressor stage or to the ESP intake.

18. The apparatus of claim 17, wherein the plurality of compressor stages, in combination, increase pressure of the production fluid to a pressure within the operating range of the ESP intake.

19. The apparatus of claim 16, wherein each compressor stage increases production fluid pressure by between about 8 psi (55 kPa) and 32 psi (221 kPa).

20. The apparatus of claim 16, wherein the one or more compressor stages increase production fluid pressure by between about 8 psi (55 kPa) and 60 psi (414 kPa).

21. The apparatus of claim 16, wherein a compressor stage further comprises at least one compressor shaft operably connected to a drive shaft of the electric motor, and at least one compressor shaft bearing.