You are an expert at summarizing long articles. Proceed to summarize the following text:

You are an expert at summarizing long articles. Proceed to summarize the following text: 
CROSS-REFERENCE TO RELATED APPLICATIONS 
       [0001]    None. 
       FIELD OF INVENTION 
       [0002]    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 reducing free gas in production fluid by separating free gas from production liquid and by compressing the production fluid to dissolve or entrain free gas. 
       BACKGROUND OF INVENTION 
       [0003]    In the production of hydrocarbons from a wellbore extending through a hydrocarbon-bearing zone in a reservoir, a production string or tubing is often 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 typically provided from a surface source by power cable extending to the downhole electric motor. Additional tools are used in conjunction with an ESP and electric motor, including one or multiple seal subassemblies, protectors, sensor assemblies, gas separators, additional pumps, standing valves, etc. The electric motor typically is used to power the pumps, gas separators, etc., via a drive shaft connected to the rotary elements of these devices. 
         [0004]    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, or free gas, interferes with operation of the pump, preventing intake of production fluid. Natural gas, and other naturally occurring gases, is often found entrained or dissolved in the production fluid. Where the gas is in a gaseous phase, mixed 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. 
         [0005]    Further, it is often undesirable to produce natural gas from wells having both gas and oil, for example. Consequently, downhole gas separators are used to separate the gaseous fluid from the liquid fluid of the production fluid at a downhole location, with the gaseous fluid vented back into the wellbore. The produced fluid at the surface is then composed of a larger percentage of the preferred liquid fluid. Free gas at the surface can still occur, for example, as the production fluid reaches the bubble point during pumping to the surface, however, a smaller amount of gaseous phase fluid occurs with the use of downhole separators. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0006]    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: 
           [0007]      FIG. 1  is a schematic view of an exemplary well system utilizing an embodiment of a gas compression separator assembly disclosed herein; 
           [0008]      FIG. 2  is a schematic partial view of an exemplary tubing string having various downhole tools thereon, including an electrical submersible pump and electrical motor for use in conjunction with a gas compression separator assembly according to the disclosure; 
           [0009]      FIGS. 3A-B  are cross-sectional views of a lower section of an exemplary gas compression separator assembly according to an aspect of the disclosure; 
           [0010]      FIGS. 4A-B  are cross-sectional views of an upper section of the gas compression separator assembly according to an aspect of the disclosure; and 
           [0011]      FIGS. 5A-B  are cross-sectional views of another exemplary embodiment of a gas compression separator according to an aspect of the disclosure. 
       
    
    
       [0012]    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 
       [0013]    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. 
         [0014]    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. 
         [0015]    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. 
         [0016]      FIG. 1  is a schematic illustration of a well system, indicated generally  10 , having a compressor and gas separator assembly according to an embodiment of the disclosure. A wellbore  12  extends through various earth strata, including at least one production zone. 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. 
         [0017]    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. 
         [0018]    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. 
         [0019]    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. 
         [0020]    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 , including gas compression separator assembly  42 . 
         [0021]      FIG. 2  is a schematic view in elevation of an exemplary tubing string having various downhole tools thereon, including an electrical submersible pump and electric motor for use in conjunction with a compressor and gas separator assembly according to the disclosure. 
         [0022]    The tubing string  30  includes multiple connected downhole tools 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 compression separator assembly  42   a - b , and an electrical submersible pump assembly  46 . The gas compression separator assembly  42  is divided into a lower section  42   a  and an upper section  42   b . The protector  40  is seen in partial tear-away to show an exemplary thrust bearing assembly  150 . The thrust bearing is discussed in greater detail below herein. 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 combined tubing and production strings can be referred to as a production string for ease of reference. The ESP assembly pumps the production fluid to the surface via tubulars  32 . 
         [0023]      FIGS. 3A-B  and  4 A-B are cross-sectional views of an exemplary gas compression separator assembly  42  according to an aspect of the disclosure.  FIGS. 3A-B  provide a cross-sectional view of the lower section  42   a  of the gas compression separator assembly  42 , and  FIGS. 4A-B  provide a cross-sectional view of the upper section  42   b  of the gas compression separator assembly  42 . The Figures are discussed in sequence, however, like parts on the sections are indicated by like numbers, typically with a distinguishing suffix. 
         [0024]    The gas compression separator  42  is designed to treat, at a downhole location, production fluid having both a free gas component and a liquid component. Generally, the exemplary gas separator assembly  42  is seen split into a lower section  42   a  and upper section  42   b . The division into sections is largely for ease of manufacture, assembly, and transport. As shown, the lower section  42   a  includes a first compression stage  50   a  and a second compressor stage  50   b , arranged in series, with each stage having two impellers and diffusers. Similarly, the upper section  42   b  has a third compressor stage  50   c  and a fourth compressor stage  50   d , also in series, and each having two impellers and diffusers. Each compressor stage acts on the production fluid to incrementally increase fluid pressure (typically measured in psi), decrease fluid volume, and reduce volumetric fluid flow rate (often measured in barrels per day, bpd). The stage capacities are carefully selected such that, at each stage, the production fluid is within the operating pressure range and flow rate range for that compressor stage. Similarly, each compressor stage provides compressed production fluid to the next compressor stage in the series at a pressure and flow rate within the operating range of the next stage. 
         [0025]    Generally, the compression stages receive production fluid and, via centrifugal forces, compress it to reduce free gas in the fluid. The compression stages raise fluid pressure prior to discharge. The centrifugal force entrains free gas into a gas-liquid mix and dissolves gas into the production liquid. The compressor is preferably powered by the electric motor via a drive shaft although alternative power sources can be applied. Production fluid entering the compressor proceeds through multiple compression stages, with fluid pressure increased at each stage. Stages are arranged in series to produce, for each stage and for a combined total, a target fluid pressure, a target production volume (e.g., in bpd), a target flow rate, etc. 
         [0026]    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, 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. The compression stages herein better handle debris, eliminate high-erosion points, reduce likelihood of erosive failure, and prolong useful life of the tool. The compressor design does not restrict or limit fluid flow, or hydrocarbon production, to increase fluid pressure. 
         [0027]    The system relies on a series of multiple compression stages, but the number, size, and capacity of stages is selected based on the application, formation pressure, formation depth, production rate, free gas to liquid mix, etc. Consequently, alternative embodiments can employ fewer or greater compression stages, with varying stage specifications, and fewer or more compression stages per section. The number of compression stages, impellers, diffusers, staging sections, and the specifications for each, provided herein are therefore exemplary and not limiting. 
         [0028]    Turning to  FIG. 3A-B , the lower section  42   a  is seen having compressors arranged as stages  50   a - b , a fluid chamber  52   a , a base assembly  54   a , a head assembly  56   a , and a gas separation assembly  58   a . A generally cylindrical housing  60   a  encloses the compression stages  50   a - b , fluid chamber  52   a , separation assembly  58   a , and portions of the base  54   a  and head  56   a  assemblies. Further, a compression tube  61  is formed along much of the length of the tool section, with compression tube sections  61   a - b  combining with diffuser bodies  118   a - d , and compressor bases  116   a - b  to form the compression tube. The section elements define an interior passageway  63  extending the length of the section  42   a , through which production fluid flows. 
         [0029]    Drive shaft  62   a  extends longitudinally through the assembly  42   a , having a keyway  64   a  for attachment of rotary elements to the shaft, upper and lower spline sections  66  for connecting the shaft to similar shafts above and below the tool. The shaft is powered, typically, by an electric motor having a rotary drive shaft and positioned downhole from the gas compression separator assembly  42   a . An exemplary shaft, for example, has an 11/16 inch (1.746 cm) diameter and is made of a high strength metal such as Inconel 718 (trade name). A preferable shaft design is rated for a maximum of 500 horsepower. 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 shaft components. 
         [0030]    The shaft is supported radially by a plurality of bearing assemblies  68   a - e  spaced along the shaft length. Bearing assemblies are known in the art and can preferably include associated sleeves, bushings, snap rings, pins, screws, or other attachment mechanisms. The bearings provide stability to the drive shaft during rotation. More or fewer bearings can be used depending on construction, materials, expected operating conditions, etc. Preferably the bearings are made of hardened materials, such as tungsten for example. 
         [0031]    Base bearing  68   a  has a tubular body  70 , bearing sleeve  72 , and bushing  74 . Preferably sleeves  76   a - e  oppose the bearings  68   a - e  or associated bushings, respectively. The sleeves  76  are preferably hardened, such as of hardened carbide, etc., as is known in the art. Spacing and attachment mechanisms, such as two-piece ring  78   a , spacer  80 , shims, etc., can be used as those of skill in the art will recognize. Additional bearings can be of alternate construction, or provided in whole or in part by another tool element, such as the impeller, diffuser and cross-over assemblies, for example. 
         [0032]    Base assembly  54   a  has a base body  82   a  threadedly or otherwise attached to the section housing  60   a . The base defines an interior passageway  63   a  which forms a portion of passageway  63 . The base has a fluid intake  84   a  for receiving fluid from a tool or tubing positioned below and a fluid outlet  86   a  for delivering fluid to a tool or tubing positioned above. In this instance, the outlet delivers fluid to the upper section  42   b . The base  82   a  houses bearing  68   a  and the lower end of the shaft  62   a , and has a coupling  88   a  for attachment to an adjacent tool or tubing. 
         [0033]    The head assembly  56   a  is of similar construction, having a head body  90   a  defining an interior passageway  63   f  which forms a portion of passageway  63 . The head houses bearing  68   e , sleeve  76   e , and the upper end of the shaft  62   a , and provides a tool coupling  92   a . The head also defines a fishing neck  94   a , as is known in the art. The head assembly  56   a  is a cross-over tool, providing for fluid, in this case separated free gas, to cross from the interior chamber  140   a  to the exterior of the lower tool  42   a . Most or all of the separated free gas is vented, through a plurality of vents  96   a , preferably to the wellbore or casing annulus defined between the tool section  42   a  and the wellbore or casing. The production liquid (and any remaining gas) flows through a plurality of interior ports  98   a  defined in the head body  90   a  and thence through head outlet  100   a . The head assembly is threadedly or otherwise attached to the section housing  60   a  and by lock plate  102   a.    
         [0034]    Fluid chamber  52   a  is defined between the first and second compression stages  50   a  and  50   b  and interior to compression tube  61   a . Shaft  62   a  extends through the fluid chamber. The chamber receives compressed fluid from the outlet of the first compressor assembly  50   a  and delivers fluid to the inlet of second compressor assembly  50   b . Fluid pressure, fluid volume, and fluid flow rate are static across the fluid chamber  52   a.    
         [0035]    The lower section  42   a  is seen having a plurality of compressor assemblies, namely,  50   a - b . Similarly, the upper section  42   b  has a plurality of compressor assemblies  50   c - e . The first compressor assembly  50   a  is discussed in detail, with the remaining compressor assemblies  50   b - e  only briefly described as they have many of the same features and construction. Compressor assemblies are generally known in the field, as those of skill in the art will recognize. Exemplary first compressor assembly  50   a  is comprised of, in order of fluid flow, impeller assembly  104   a , diffuser assembly  106   a , impeller assembly  104   b , and diffuser assembly  106   b.    
         [0036]    Impeller assembly  104   a  is discussed in detail, the description applying to the remaining impeller assemblies where like parts have like numbers with distinguishing suffixes in the figures. Impeller assembly  104   a  has an impeller body  108   a , a hub  110   a  which attaches to the shaft  62   a , and defines a plurality of radially and longitudinally extending impeller passageways  112   a  which are separated by a plurality of vanes. Impeller inlet  113   a  intakes fluid from the base outlet  86   a . Impeller outlets  114   a  emit production fluid to diffuser inlets  123   a . A compressor base  116   a  provides for mounting and stability of the impeller and diffuser assemblies. The remaining impeller assemblies  104   b - d  of the lower section  42   a  are of similar construction and function. Impeller outlets  114   b  of impeller assembly  104   c  emit fluid into the fluid chamber  52   a . Preferably the impellers and diffusers are made of corrosion-resistant material, such as tungsten alloy, nickel alloy, Ni-Resist, 9-chrome 1-molly, and the like, as are known in the art. Impeller design and use is known in the art to those of ordinary skill and will not be discussed in greater detail herein. 
         [0037]    Diffuser assembly  106   a  is discussed in detail, the description applying to the remaining diffuser assemblies where like parts have like numbers with distinguishing suffixes. Diffuser assembly  106   a  has a diffuser body  118   a , a hub  120   a  which also provides a bearing surface for the shaft  62   a  or the sleeve  76   b , and defines a plurality of radially and longitudinally extending diffuser passageways  122   a  which are separated by a plurality of vanes. Diffuser outlet  124   a  emits production fluid to the inlet  113   b  of impeller  104   b . The diffuser inlets  123   a  accept fluid from the outlets  114   a  of the impeller  104   a . Preferably the diffusers are made of corrosion-resistant materials, such as tungsten alloy, carbide, nickel alloy, and the like. Diffuser design and use is known in the art to those of ordinary skill and will not be discussed in greater detail herein. 
         [0038]    A compression nut assembly  130   a  is mounted to the shaft  62   a  above the compressor assembly  50   b . The exemplary compression nut assembly has a compression nut  132   a , compression sleeve  134   a , set screw  136   a , and two-piece ring  138   a . The compression nut assembly acts as a mounting or retainer for the compressor and bearing elements below the compression nut assembly. In a preferred embodiment, the compression nut assembly is fixedly attached to the shaft and provides a load-bearing face for mounting the below elements in compression. The compression nut assembly and two-piece ring  78   b  work to “sandwich” the intervening elements, maintaining them in compression. Compression nut assemblies and equivalents are known in the art. Further, a deflector or protective sleeve can be used to protect the compression nut assembly from direct impingement by sand-laden production fluid. 
         [0039]    The gas separation assembly  58   a  includes a plurality of vortex generators  142   a  mounted to the shaft  62   a  and positioned in a gas separation chamber  140   a . A pair of vortex generators is mounted to the shaft  62   a  to rotate with the shaft. The vortex generators have radially extending, vertical paddles  144   a  on a hub  146   a  supported by the shaft  62   a . The paddles stir passing production fluid in the chamber  140   a , creating a vortex, wherein the heavier liquid components are forced radially outward against the chamber wall  148   a  while free gas components gather near the vortex axis near the center of the chamber. The length of the chamber  140   a  is selected to provide sufficient dwell time to allow for adequate separation of free gas and liquids. The length of the chamber can, in part, be determined by the formation and production characteristics, such as the amount of produced gas and production pressure. Free gas is separated from the production liquid component and exits the chamber and the tool section through the cross-over head vents  96   a . The remaining production fluid is drawn through interior ports  98  and continues upward through the assembly. Other vortex generators are known in the art and can be used alone or in combination with the generators  142   a  shown. 
         [0040]    Turning to  FIG. 4A-B , the upper section  42   b  is seen having compressors arranged as stages  50   c - e , a fluid chamber  52   b , a base assembly  54   b , a head assembly  56   b , and a gas separation assembly  58   b . A generally cylindrical housing  60   b  encloses the compression stages  50   c - e , fluid chamber  52   b , separation assembly  58   b , and portions of the base  54   b  and head  56   b  assemblies. Further, a compression tube  61  is formed along much of the length of the tool section, with compression tube sections  61   c - d  combining with diffuser bodies  118   e - i , compressor bases  116   c - d , and diffuser bearing housings  119   a - b , to form the compression tube. The section elements, as those of the lower section, continue to define interior passageway  63  extending the length of the section  42   a , for production fluid flow. 
         [0041]    Drive shaft  62   b  extends longitudinally through the assembly  42   b , having a keyway  64   b  for attachment of rotary elements to the shaft, upper and lower spline sections  66  for connecting the shaft to similar shafts above and below the tool. The shaft is powered, typically, by an electric motor having a rotary drive shaft and positioned downhole from the gas compression separator assembly  42   b . An exemplary shaft, for example, has an 11/16 inch (1.746 cm) diameter and is made of a high strength metal such as Inconel 718 (trade name). A preferable shaft design is rated for a maximum of 200 horsepower (202.8 hp(M)). 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. 
         [0042]    The shaft is supported radially by a plurality of bearing assemblies  68   f - k  spaced along the shaft length. Bearing assemblies are known in the art and can preferably include associated sleeves, bushings, snap rings, pins, screws, or other attachment mechanisms. The bearings provide stability to the drive shaft during rotation. More or fewer bearings can be used depending on construction, materials, expected operating conditions, etc. 
         [0043]    Base bearing  68   f  is of similar construction to base bearing  68   a  described above herein and will not be discussed in detail. Preferably treated sleeves  76   f - k  oppose bearings  68   f - k  or their bushings, respectively. The sleeves are preferably made of hardened material, such as iron carbide, etc. Spacing, stabilizing, and attachment mechanisms, such as two-piece ring  78   b , spacers  80 , shims, etc., can be used as those of skill in the art will recognize. Additional bearings can be of alternate construction, or provided in whole or in part by other tool elements, such as a diffuser body, diffuser bearing housing, cross-over body, etc. 
         [0044]    Base assembly  54   b  has a base body  82   b  threadedly or otherwise attached to the section housing  60   b . The base defines an interior passageway  63   g  which forms a portion of passageway  63 . The base has a fluid intake  84   b  for receiving fluid from a tool or tubing positioned below and a fluid outlet  86   b  for delivering fluid to a tool or tubing positioned above. In this instance, the outlet  86   b  delivers fluid to the inlet of compressor assembly  104   e . The base  82   b  houses bearing  68   f  and the lower end of the shaft  62   b , and has a coupling  88   b  for attachment to an adjacent tool or tubing. 
         [0045]    The head assembly  56   b  is of similar construction, having a head body  90   b  defining an interior passageway  63   n  which forms a portion of passageway  63 . The head houses bearing  68   n , sleeve  76   n , and the upper end of the shaft  62   b , and provides a tool coupling  92   b . The head also defines a fishing neck  94   b , as is known in the art. The head assembly  56   b  is a cross-over tool, providing for fluid, in this case separated free gas, to cross from the interior chamber  140   b  to the exterior of the lower tool  42   b . Most or all of the separated free gas is vented, through a plurality of vents  96   b , preferably to the wellbore or casing annulus defined between the tool section  42   a  and the wellbore or casing. The production liquid (and any remaining gas) flows through a plurality of interior ports  98   b  defined in the head body  90   b  and thence through head outlet  100   b . The head assembly is threadedly or otherwise attached to the section housing  60   b  and by lock plate  102   b.    
         [0046]    Fluid chamber  52   b  is defined between the compression stages  50   c  and  50   d  and interior to compression tube  61   b . Shaft  62   b  extends through the fluid chamber. The chamber receives compressed fluid from the outlet of the compressor assembly  50   c  and delivers fluid to the inlet of compressor assembly  50   d . Fluid pressure, fluid volume, and fluid flow rate are static across the fluid chamber  52   b.    
         [0047]    The upper section  42   b  is seen having a plurality of compressor assemblies, namely,  50   c - d , similar in construction to those of the lower section  42   a . Since the compressor assembly  50   a  is discussed in detail above, the compressor assemblies  50   c - d  are only briefly described. Compressor assemblies are generally known in the field, as those of skill in the art will recognize Compressor assembly  50   c  is comprised of, in order of fluid flow, impeller assembly  104   e , diffuser assembly  106   e , impeller assembly  104   f , and diffuser assembly  106   f . The assembly further preferably includes a diffuser bearing  121   a  having a housing  119   a  and fluid passageways  123   a . The diffuser bearing  121   a  provides additional stability for the shaft  62   b  at bearing assembly  68   i  and sleeve  76   i , similar to those described above herein. Similarly, the compressor assembly  50   e  also includes, at its upper end, a diffuser bearing  121   b  having a housing  119   b  and defining fluid passageways  123   b . The diffuser bearing  121   b  provides additional stability for the shaft  62   b  at bearing assembly  68   m  and sleeve  76   m , similar to those described above herein. 
         [0048]    Impeller and diffuser assemblies  104  and  106  are discussed in detail above, with the description applying to the remaining impeller and diffuser assemblies, where like parts have like numbers with distinguishing suffixes. Impeller assemblies  104   e - j  and diffuser assemblies  106   e - j  are of similar construction and will not be discussed in further detail. 
         [0049]    A compression nut assembly  130   b  is mounted to the shaft  62   b  above the compressor assembly  50   d . The exemplary compression nut assembly has a compression nut  132   b , compression sleeve  134   b , set screw  136   b , and two-piece ring  138   b . The compression nut assembly is fixedly attached to the shaft and provides a load-bearing face for maintaining the elements below in compression between the compression nut assembly and two-piece ring  78   b.    
         [0050]    The gas separation assembly  58   b  includes a plurality of vortex generators  142   b  mounted to the shaft  62   b  and positioned in a gas separation chamber  140   b . A pair of vortex generators is mounted to the shaft  62   b  to rotate with the shaft. The vortex generators have radially extending, vertical paddles  144   b  on a hub  146   b  supported by the shaft  62   b . The paddles stir passing production fluid in the chamber  140   b , creating a vortex, wherein the heavier liquid components are forced radially outward against the chamber wall  148   b  while free gas components gather near the vortex axis near the center of the chamber. Free gas is separated from the production liquid component and exits the chamber and the tool section through the cross-over head vents  96   b . The remaining production fluid is drawn through interior ports  98   b  and continues upward through the assembly. 
         [0051]    Generally, the assembly can be implemented either in compression or as a “floater” design in accordance with various embodiments of the present disclosure. Preferably, the assemblies are assembled in compression. In the lower section  42   a , seen in  FIG. 3A-B , the compression nut assembly  130   a , at the upper end, and the two-piece split ring  78   a , at the lower end, serve to place into compression each of the impeller hubs  110   a - d , sleeves  76   b - d , and spacers. From the compression nut assembly  130   a  to the two-piece split ring  78   a , a continuous series of metal parts in metal-to-metal contact is provided. Similarly, in the upper section  42   b  seen in  FIG. 4A-B , the compression nut assembly  130   b , at the upper end, and the two-piece split ring  78   b , at the lower end, serve to place into compression each of the impeller hubs  110   e - h , sleeves  76   g - k , and spacers  80 . From the compression nut assembly  130   b  to the two-piece split ring  78   b , a continuous series of metal parts with metal-to-metal contact is provided. Similarly, in  FIG. 5A-B , compression nut assembly  330  and two-piece ring  278  act to maintain the intervening part in compression. 
         [0052]    During assembly of the gas compression separator assembly, the compression nut assembly is used to place substantial force (e.g., 50-60 ft-lbs) on the metal part stack (impellers, sleeves, spacers) to pull the parts into contact with one another and to place them in compression. 
         [0053]    A schematic view of a simplified, exemplary thrust bearing assembly  150  is seen in  FIG. 2 . To set the configuration in compression, a thrust bearing is provided to bear the thrust of the rotating portions of the sections. The thrust bearing can be positioned at the lower end of the lower section  42   a , or elsewhere along the drive shaft. In the exemplary embodiment, the thrust bearing assembly  150  is positioned at the lower end of the protector  40 . The thrust bearing assembly  150  includes a thrust bearing  152 , a two-piece split ring  154 , and spacer  156 , positioned about protector shaft  158 . The thrust bearing  150  is supported by a support block  160  which is an extension of or attached to the protector housing, for example. 
         [0054]    In practice, during assembly, the shaft of the gas compression separator assembly is lifted a small amount (e.g., 0.15 to 0.030 inches), such that the impellers are not supported by the diffusers. The weight of the impellers, sleeves, and shaft are then supported by the thrust bearing below. This prevents premature wear to the impellers and diffusers due to down-thrust because the impellers do not touch, or do not place weight upon, the diffusers or diffuser thrust pads Shims are used during assembly at the bottom end of the shaft to position the shaft correctly, supported by the shaft of a below protector or other tool, such that the proper spacing is provided between the impellers and diffusers and the impeller and shaft weight and down-thrust is borne by the thrust bearing rather than the diffusers. An exemplary shim raises bottom of the shaft in the range of about 0.015 to 0.030 inch. 
         [0055]    Returning briefly to  FIG. 2 , 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. 
         [0056]    The electric motor assembly  36  includes a housing  48  and an 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. 
         [0057]    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. 
         [0058]    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. 
         [0059]    In use, production fluid which enters the production string, typically through screen assemblies  24  positioned in the wellbore downhole from the electric motor assembly  36 . The production fluid is pulled upwards in response to the operation of the one or more ESPs. Production fluid flows past the electric motor  50  at assembly  36 , through the one or more seal subs  38  and protectors  40 , through the gas compression separator  42   a - b , and to the intake of ESP  46 . Fluid is pumped to the surface through tubing  32 . The operation and methods of the seal subs, protectors, ESP, electric motor, and sensors are known in the art and not described in detail here. Additional tools can be employed on the production string as well. 
         [0060]    The electric motor  50 , powered by an electric cable  54  from the surface, rotates a drive shaft  52 . The drive shaft  52  is connected to and powers the shafts of the gas compression separator  42  and the ESP  46 . The shaft is radially supported at various locations including in the gas compression separator at bearing assemblies  68   a - e.    
         [0061]    Turning to the gas compression separator, production fluid having liquid and gaseous components enters the gas compression separator lower section  42   a  at base assembly intake  84 . In lower section  42   a  and upper section  42   b , the production fluid flows through a series of compression stages  50   a - b  and  50   c - e , respectively, although a fewer or a greater number of stages can be employed. Each compression stage takes in a relatively large volumetric flow rate of production fluid and reduces, by compression, the volumetric flow rate. Each stage builds compression, increases fluid pressure, and reduces volumetric flow rate. As fluid pressure increases, free gas in the production fluid is dissolved or entrained into the production liquid. The division of the stages into upper and lower sections allows, among other things, for use of different shaft sizes. In one example, a larger ⅞ inch diameter shaft is used in the lower section to rotate relatively larger compression stages, while a smaller 11/16 inch diameter shaft is used in the upper section to rotate relatively smaller compression stages. 
         [0062]    The stages each preferably include two compressor assemblies which, in turn, have two impeller assemblies and two diffuser assemblies. The impellers are attached to the shaft and rotate as the shaft rotates. In a preferred embodiment, the electric motor rotates the impellers in the range of about 3000-5000 rpm, and more specifically between about 3500-4500 rpm. Preferably, at least the lower section is assembled in compression, eliminating stage damage from running out of the acceptable operating range of a comparable floater assembly. A thrust bearing carries the thrust forces and can be positioned at the lower end of the lower section  42   a  or in a lower tool assembly, such as the protector. Also preferably, at least some of the compression stages or compressor assemblies in the upper section  42   b  are configured in compression. With the assemblies, or portions thereof, in compression and weight and thrust carried by the thrust bearing, the system has a greater usable operation range. A floater configuration is designed for use without damage in an optimum range, for example, between 2500-3500 BPD. A similar system configured in compression can operate in a wider range, for example, between 1000-4000 BPD without mechanical damage to the impellers or diffusers. 
         [0063]    The stage capacities are selected to gradually reduce the volumetric fluid flow and correspondingly gradually increase the fluid pressure. In an exemplary embodiment of the disclosure, the first compressor stage  50   a  utilizes two nominal 4300 BPD (normal range 3000-5400 BPD) compressor assemblies arranged in series. At the second stage  50   b , two nominal 3000 BPD (normal range 2000-3600 BPD) compressor assemblies are utilized in series. The third stage  50   c , in the upper section, utilizes two compressors capable of about 2200 BPD, in an exemplary embodiment. The fourth stage  50   d  utilizes two compressor assemblies with a capacity of about 1750 BPD, and the fifth stage utilizes compressor assemblies of about 850 BPD. 
         [0064]    Other arrangements can be used. In further exemplary embodiments, the following stage capacities and characteristics can be used as seen in Chart  1  in which figures are in barrels per day (BPD) and represent the capacities of the compressor assemblies in each exemplary stage in order of fluid flow. 
         [0000]    
       
         
               
               
             
               
               
               
               
               
               
             
               
               
               
               
               
               
             
           
               
                   
                 CHART 1 
               
             
             
               
                   
                   
               
               
                   
                 Stage 
               
             
          
           
               
                   
                 1 
                 2 
                 3 
                 4 
                 5 
               
               
                   
                   
               
             
          
           
               
                 Example 1 
                 6000/6000 
                 4300/4300 
                 2200/2200 
                 2200/2200 
                 1750/1750 
               
               
                 Example 2 
                 4300/4300 
                 3000/3000 
                 1750/1750 
                 1250/1250 
                 1250/1250 
               
               
                 Example 3 
                 4300/4300 
                 3000/3000 
                 850/650 
                 850/650 
                 850/650 
               
               
                   
               
             
          
         
       
     
         [0065]    Compressor capacities are listed as nominal values but are designed to safely operate within an operational flow rate range. Flow rate maximums and minimums are known for a given compressor assembly. For example, a compressor assembly listed at 650 BPD has an operational range of 415 to 867 BPD. In this example, the lower end of the standard operational range (415 BPD) is approximately 36 percent below the nominal flow rate (650 BPD). The operating ranges, however, are provided on the assumption that the compressor assemblies are mounted in floater configuration on the drive shaft. Compressors in floater configuration are not as tolerant of rate variations or extreme operational ranges as compressors assembled in compression. In the preferred embodiment, however, at least one stage of compressor assemblies are mounted in compression as explained elsewhere herein. This allows the compressor assemblies configured in compression, as in the preferred embodiment, to run in a much expanded operational range. When a 650 BPD compressor assembly is mounted in compression, for example, its lower end operational range is extended to around about 200 BPD. (Caution should be taken at these lower rates to insure adequate flow for cooling of the electric motor.) The lower end (200 BPD) of the modified operational range, in this example, is approximately 69 percent below the nominal flow rate (650 BPD). 
         [0066]    Production fluid compressed in the first two stages flows into the chamber  140   a  and is stirred into a vortex by the rotation of the paddles  144   a  mounted to the drive shaft  62   a . Centrifugal force pushes the heavier liquid component of the production fluid toward the compression tube wall  148   a  while the lighter gaseous component of the production fluid moves towards the vortex axis near the shaft. The free gas flows up the vortex axis and into the vents  96   a  defined in the head assembly  56   a . The free gas is ported to the exterior of the lower section  42   a , typically into an annulus formed between the section and the casing or wellbore. The liquid component, as well as any remaining free gas, flows upwards into and through the interior ports  98   a  defined in the head assembly. The production fluid passes out of the lower section through outlet  100   a  and into the upper section  42   b.    
         [0067]    Briefly, the compression and separation processes are repeated in the upper section  42   b . Production fluid, compressed and with lowered gas content, from the lower section  42   a  is received into inlet  84   b  of the base assembly  54   b  and passes into the third compressor stage  50   c . The impellers  104   e - f  compress the production fluid resulting in higher fluid pressure, dissolving and entraining of free gas, and a reduction in volumetric fluid flow rate. Exemplary compressor sizes are provided above in Chart  1 . Production fluid leaving the third stage passes through fluid passageways  123   a  of diffuser bearing  121   a . Fluid flows through chamber  52   b  and into the fourth stage  50   d  and its two compressor assemblies with impellers  104   g - h . Fluid exits the fourth stage into chamber  63   k  and enters the fifth stage  50   e , where the impellers  104   i - j  further compress the production fluid, reduce volumetric flow rate, and dissolve and entrain free gas. Fluid flows through diffuser bearing  121   b  and into the separation assembly  58   b . The diffuser bearings  121   a - b  provide stability for the shaft  62   b . The diffuser bearings do not restrict fluid flow or create an increase in backpressure on the fluid. 
         [0068]    Separator stage  142   b  works similarly to separation assembly  142   a , separating free gas and liquid via vortex, with free gas exiting the upper section  42   a  through vents  96   b  and production liquid (and any remaining free gas) passing through ports  98   b  and through outlet  100   b . Mounted above the head assembly  56   b  is preferably at least one ESP for pumping the compressed production fluid to the surface. 
         [0069]    The gas compression separator assembly can be used at various well depths, typically ranging from 500 feet to over 13,000 feet deep. It is anticipated that the gas compression separator assembly will be of greater use in wells producing larger volumes of free gas, where the assembly entrains or dissolves free gas into the production liquid. The system is useful to prevent or reduce gas lock conditions, repetitive time-outs, restarts, down time, and consequent lost production. 
         [0070]    The gas compression separator assembly does not rely on flow restriction to build pressure or to regulate fluid flow rates to within a range determined by the ESP capacity. No restriction plate or flow regulator plate is positioned in the system. Instead, the gas compression separator acts to compress the production fluid including its free gas component allowing fluid flow to continue uninterrupted while reducing the volumetric flow rate. In the exemplary embodiment described herein, the volumetric flow rate is reduced by a factor of up to approximately 18. The gas compression separator assembly allows uninterrupted production fluid flow through the production string along the assembly length. This does not imply that the compressor and separator assemblies do not, respectively, compress production fluid and separate free gas from the production fluid. Rather, the fluid flow is uninterrupted by any back-pressure or restriction devices, such as restrictor plates, restriction orifices, nozzles, or ports, or other flow restriction devices (such as “diffusers” designed to restrict flow rate, for example) which restrict or regulate fluid flow in order to create back-pressure or limit flow to a rate within the operating range of an ESP, etc. The uninterrupted flow is output at the assembly outlet, preferably to an intake of an ESP positioned above the assembly. Alternately, the production fluid, now compressed and with a reduced free gas volume, can be flowed through additional tools, passageways, etc., to one or more ESPs positioned above. The ESP pumps the production fluid to the surface and, like the compressor assemblies and separator assemblies of the gas compression separator assembly, is powered by rotary shaft driven by the downhole electric motor. 
         [0071]      FIGS. 5A-B  are cross-sectional views of another exemplary embodiment of a gas compression separator according to an aspect of the disclosure. The figures show a gas compression separator of alternate construction but having similar elements as those described in detail above with respect to  FIGS. 3-4 . Consequently, the description regarding  FIGS. 5A-B  is concise, with fewer part references and the description of parts above applying to like parts in assembly  200 . The assembly seen in  FIGS. 5A-B  can be used as a substitute for the upper section  42   b  or as a stand-alone unit. 
         [0072]    The tool section  200  has a series of compressors arranged in compression stages  250   a - c , fluid chamber  252 , base assembly  254 , head assembly  256 , and a gas separation assembly  258 , positioned in or connected to a generally cylindrical housing  260 . A compression tube  261  is formed by a combination of compressor tubes  261   a - b , diffuser bodies  318 , and diffuser bearing housings  319 . An interior passageway  263  is defined through the tool section  200  for flow of production fluid. 
         [0073]    Drive shaft  262  extends through the assembly  200  and has a keyway  264  for attachment of rotary elements to the shaft. Upper and lower splines  266  allow connection to similar shafts above and below. 
         [0074]    The shaft is supported by a plurality of bearing assemblies  268   a - j . Bearing assemblies are known in the art and preferably include associated sleeves, bushings, snap rings, pins, screws, etc. Bearing assemblies can be stand-alone and fitted into the tool, as with the bearings  268   a  in the base assembly  254  and bearing  268   j  in the head  256 , or can be part of or partially formed by compressor elements such as, for example, diffuser bodies, diffuser bearing housings, etc. The bearings are of similar design and function as those described elsewhere herein and are not described in detail. 
         [0075]    Base assembly  254  has a body  282  attached to the housing  260 , a fluid intake  284 , and a fluid outlet  286 . The base  282  further houses bearing  268   a  and has a coupling  288  for attachment to an adjacent tool or tubing. The head assembly  256  has a body  290  defining a portion of passageway  263 . The head assembly includes bearing  268   j , a tool coupling  292 , and a fishing neck  294 . The head assembly is a cross-over tool, providing a plurality of vents  296  for separated free gas to cross from the chamber  340  to the exterior of the tool section  200 . Production liquid (and remaining free gas) flows through ports  298  to a tool attached above. 
         [0076]    Fluid chamber  252  is defined between the compression stages  250   b  and  250   c . In a preferred embodiment, the compression nut assembly  330  is positioned in the chamber  252 . 
         [0077]    The tool section  200  has a plurality of compression stages  250   a - c . Each stage has two corresponding compressor assemblies  205  in a preferred embodiment. For example, the first compression stage  250   a  includes compressor assemblies  205   a - b . The compressor assemblies each comprise an impeller  304  and diffuser  306 . The diffusers  306  typically include a bearing assembly  268 . As an example, compressor assembly  205   a  includes impeller  304   a , diffuser  306   a , bearing assembly  268   b , diffuser bodies  318 , and a compressor base  316 . The remaining stages, compressors, etc., have similar reference numbers and will not be called out. Compressor assemblies are known in the art as those of skill will recognize. 
         [0078]    In an exemplary embodiment, the compression stage  250   a  utilizes two compressor assemblies with a 2200 BPD capacity, the compression stage  250   b  utilizes two compressor assemblies with 1250 BPD capacity, and the compression stage  250   c  utilizes two compressor assemblies with 650 BPD capacity. The compressor assemblies in a stage can have the same or differing capacities, more or fewer compression stages and compressor assemblies can be used, etc. 
         [0079]    The gas compression separator assembly preferably also includes one or more diffuser bearings  321  each having a housing  319 . The diffuser bearings  321  provide additional stability for the shaft  262 . 
         [0080]    Impeller and diffuser assemblies are discussed in detail above with descriptions applying to the impellers  304   a - f  and diffusers  306   a - f.    
         [0081]    A compression nut assembly  330  is mounted on the shaft  262  above compressor assembly  205   d . The exemplary compression nut assembly has a compression nut, sleeve, set screw, and two-piece ring, as described above herein, and can be used with necessary spacers  280 . The compression nut assembly acts as a mounting or retainer for the compressor and diffuser bearing elements below. In a preferred embodiment, the compression nut assembly attaches fixedly to the shaft and provides a load-bearing face for mounting the compressor assemblies and diffuser bearings in compression. Compression nut assemblies and equivalents are known in the art. 
         [0082]    The gas separation assembly  258  includes a plurality of vortex generators  342  mounted to the shaft  262  and positioned in a chamber  340 . The vortex generators are discussed above herein and will not be described in detail here. The vortex generators create a vortex, wherein heavier production liquid components are forced outward against the chamber wall while the lighter free gas component gathers near the vortex axis proximate the shaft. Separated free gas exits the chamber and the tool section through vents  296 . The remaining production fluid is drawn through interior ports  298 . 
         [0083]    As described above, the assembly or portions thereof can be assembled in compression or in floater configuration. Preferably, the gas compression separator assembly is in compression, in part or in whole. Here, the elements below the compression nut assembly  330  and above the two-piece ring  278  are in compression. The compression nut assembly  330  and two-piece ring  278  act to hold the intervening impellers  304   a - f , bearing sleeves, and spacers  280  in compression. From the compression nut assembly  330  to the two-piece split ring  278 , a continuous series of metal parts, in metal-to-metal contact, is provided. Assembly of parts in compression is described elsewhere herein. Similarly, the use and positioning of a thrust bearing is described elsewhere herein. 
       Method Claim Support 
       [0084]    In preferred embodiments, various methods are disclosed. The steps listed herein infra are not exclusive, not all required in methods disclosed herein, and can be combined in various ways and orders. It is explicitly stated that the following steps can be arranged in different orders, omitted, repeated, transposed, and/or re-arranged, and additional steps can be added. Steps presented in an order XYZ, for example, can be performed in the order XZY, YXZ, YZX, etc. Persons of ordinary skill in the art, upon reading this disclosure, will be well aware of various methods including some or all of the steps disclosed herein without an exhaustive listing of every potential combination of steps, addition or omission of steps, etc. Further, a person of ordinary skill in the art will understand that and which steps can be performed, and in what various orders, without those steps being listed consecutively in a single paragraph. Steps and methods which are disclosed herein in relation to a description of one or more embodiments or elements thereof, for example, are explicitly understood to be steps which can be taken in conjunction with other steps, even though the steps are not in the same sentence or paragraph. The various possible combinations and orders of various steps not only do not depart from the spirit of the inventions disclosed herein, they are explicitly taught and disclosed by this paragraph and throughout. Finally, where steps are required to be taken in particular order, must be taken consecutively with no intervening steps, etc., such will either be explicitly stated in the text or claim, or will, again, be apparent to one of ordinary skill in the art. 
         [0085]    Method steps are presented here, numbered for ease of reference, even though a practitioner of the arts or one of ordinary skill in the art is capable of discerning these and other steps from the disclosure supra. Exemplary steps include: 1. a method of producing fluid from a subterranean well having a production string positioned downhole in a wellbore extending through a formation, the method comprising the steps of: a) flowing production fluid from the formation through an interior passageway defined in the production string, the production fluid having a free gas component and a liquid component; b) allowing uninterrupted production fluid flow through a gas compression separator assembly positioned along the production string while: compressing the production fluid in the production string; separating at least some free gas from the production liquid; and c) flowing the compressed production fluid to the intake of an ESP. Additional steps and details regarding possible steps follow. 2. The method of 1, wherein step (b) further comprises dissolving or entraining at least a portion of the free gas into the production liquid. 3. The method of 1-2, wherein step (b) further comprises venting the separated free gas to the exterior of the production string at a downhole location. 4. The method of 1-3, wherein the step of compressing further comprises incrementally compressing the production fluid using a series of compressor assemblies. 5. The method of 4, further comprising the step of sequentially reducing the volumetric fluid flow rate of the production fluid using the series of compressor assemblies. 6. The method of 4-5, wherein each compressor assembly of the series has an operating range, and further comprising compressing the production fluid using a compressor assembly to within the operating range of a subsequent compressor assembly. 7. The method of 4-6, wherein the compressor assemblies have at least one impeller and at least one diffuser. 8. The method of 4-7, wherein at least one of the compressor assemblies of the series are assembled in compression. 9. The method of 4-8, wherein the series of compressor assemblies are divided into a plurality compression stages, each compression stage having at least two compressor assemblies, and further comprising driving at least two compression stages utilizing different diameter shafts. 10. The method of 1-9, wherein the step of compressing further includes reducing volumetric flow rate of the production fluid. 11. The method of 1-10, wherein the step of compressing further includes increasing production fluid pressure. 12. The method of 1-11, wherein the step of separating free gas from production liquid further comprises creating a vortex of production fluid in a fluid chamber. 13. The method of 12, further comprising forcing lighter production free gas toward the center of the vortex and heavier production liquid toward the fluid chamber wall. 14. The method of 1-13, further comprising venting a portion of free gas through a cross-over tool. 15. The method of 12, wherein creating the vortex includes the step of rotating at least one paddle in the fluid chamber. 16. The method of 1-15, further comprising the step of pumping the compressed production fluid to the surface using the ESP. 17. The method of 1-16, further comprising the step of reducing the likelihood of gas lock occurring in the ESP. 
         [0086]    Exemplary methods of use of the invention are described, with the understanding that the invention is determined and limited only by the claims. Those of skill in the art will recognize additional steps, different order of steps, and that not all steps need be performed to practice the inventive methods described. 
         [0087]    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 disclosed apparatus and methods 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.

Summary:
Downhole Electric Submersible Pumps (ESP) in a production string often experience gas lock caused by free gas present in the production liquids which reduces intake pressure below the operating parameters of the ESP. A gas compression separator assembly, having a series of compressors and separation chambers, entrains or dissolves the free gas component of the production fluid and separates free gas for downhole disposal. The production fluid fed to the ESP intake has an increased fluid pressure, a reduced volumetric fluid flow, and a lower free gas content, and is less likely to induce gas lock of the ESP.