Abstract:
A Vertical Annular Separation and Pumping System (VASPS) utilizing a outer annulus liquid discharge arrangement to replace a standard pump shroud associated with an electrical submersible pump. The outer annulus liquid discharge arrangement directs produced wellbore liquids around the electrical submersible pump motor to provide a cooling medium to prevent overheating and premature failure of the electrical submersible pump.

Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
     This application is the National Stage of International Application No. PCT/US06/017136, which claims the benefit of U.S. Provisional Application No. 60/706,799, filed 9 Aug. 2005. This application is related to International Application No. PCT/US06/016702 entitled “Vertical Annular Separation and Pumping System With Integrated Pump Shroud and Baffle”, which claims the benefit of U.S. Provisional Application No. 60/706,740 filed on 9 Aug. 2005. 
    
    
     FIELD OF THE INVENTION 
     This invention relates to a vertical annular separator for separating a fluid stream into a liquid phase stream and a gas phase stream. In particular, this invention relates to an apparatus for and methods of separating produced hydrocarbon fluids and other wellbore fluids into liquid and gas phase streams at subsea locations and directing the separated phase streams to other locations. 
     BACKGROUND OF THE INVENTION 
     Offshore or subsea hydrocarbon deposits continue to attract significant attention from oil and gas producers throughout the world. As onshore hydrocarbon deposits currently in production, particularly in the United States, are depleted and as larger onshore oilfields are discovered only infrequently, producers increasingly look for new exploration and production opportunities in offshore locations. 
     A factor limiting the development of many of the discovered offshore hydrocarbon deposits, particularly crude oil, natural gas, and associated natural gas liquids, is the cost to install and maintain equipment and facilities to produce the hydrocarbons. Offshore drilling and production platforms and subsea production equipment installations require sizeable investments. In trying to maximize the economic benefits from offshore facilities, producers focus on reducing the installation weight and costs of the equipment on the offshore production platforms necessary to produce the hydrocarbons. 
     By reducing the installation weight and costs of equipment, new offshore installations may be smaller and less expensive for producing newly discovered fields and existing offshore installations may be further modified to handle the production from more wells and larger production areas. By using existing facilities, a production facility may exploit marginal reservoirs adjacent to or near existing fields. Also, by using existing facilities to produce new or marginal discoveries, an oil producer can extend the life of the facilities and increase the level of recoverable reserves at costs less than those required for new discoveries and new installations. Often such new or marginal discoveries may be located at a remote location, e.g. 5 to 15 miles (8 to 24 km), from existing production platforms or facilities. Large, lengthy flowlines are installed to transport produced wellbore fluids, primarily crude oil, natural gas, natural gas liquids, and water, to these platforms or facilities from such a remote location. 
     Although large, lengthy flowlines are significantly less expensive that new offshore production platforms, such flowlines may limit the fluid production rate from a given well. One of the more significant factors limiting the amount of fluid a given oil or gas well may produce is the amount of back pressure exerted at the wellhead by facilities downstream of the wellhead. One measure of the amount of such back pressure is referred to as the wellhead flowing pressure. The wellhead flowing pressure is typically the pressure at the wellhead during normal operating conditions without a wellhead choke or other flow restriction means in the wellhead. When the wellhead flowing pressure can be reduced, a typical well can produce more fluid from a given reservoir, which leads to a longer field production life and more oil and gas recovery. 
     Several factors can cause increases in wellhead flowing pressure in a given well. For example, flowlines from subsea wellheads to separation facilities may in some cases be several miles long which can result in significant friction losses caused by the turbulent, multiphase fluid flow in the flowlines. Such friction losses result in an increase in pressure required to move a given amount of fluid through a flowline. This pressure increase, when added to the operating pressures of facilities downstream of the wellhead, may significantly increase the wellhead flowing pressure. Another factor that causes increases in wellhead flowing pressure are changes in elevation from deepwater subsea fields to shallow water facilities. (Such changes in elevation cause an increased fluid head, i.e. a column of fluid, in a flowline which increases the wellhead flowing pressure and significantly reduces fluid production.) Still another factor that may increase the wellhead flowing pressure is the gas-liquid (two-phase) flow regime in the flowline to the production platform. Such two-phase flow results in increased pressure losses compared to single phase flow in a flowline, such as where gases are produced through one flowline and liquids (oil and water) are produced through another flowline. A separate, but related, problem may occur in a two-phase flow when large volumes of liquids accumulate in a flowline and upon accumulation of adequate pressure, are pushed forward and produced in a very short period of time as large slugs of liquids. Liquids produced during a slugging event can overwhelm the fluid handling capabilities of equipment employed on an offshore platform or facility as well as create high back pressures on a well. 
     Several efforts have been proposed and implemented to reduce the wellhead flowing pressure by separating produced wellbore fluids into gas and liquid streams at a subsea location and then providing separate flowlines to the platform or facilities for both the gas and liquid phase streams. One particularly innovative approach to separating wellbore fluids into gas and liquid phase streams at a subsea location is the vertical annular separation and pumping system (VASPS), as disclosed in U.S. Pat. No. 4,900,433, entitled “Vertical Oil Separator”, assigned to The British Petroleum Company. U.S. Pat. No. 4,900,433 is hereby incorporated by reference in its entirety. A more detailed description of a VASPS is provided in “VASPS: An Innovative Subsea Separation System” presented at the 11th International Conference and Exhibition, Oct. 19-21, 1999 at Stavanger, Norway, which presentation is hereby incorporated by reference in its entirety. A VASPS unit relates generally to the technical areas of subsea multiphase boosting systems and artificial lifting methods for increasing reservoir production rates. 
     A VASPS is a two-phase (gas-liquid) separation and pumping system which may be installed in a subsea “dummy well” near the mudline of the subsea floor. A “dummy well” is a simple borehole, typically lined with a casing or similar pipe structure, extending into the subsea surface near the mudline a distance adequate to receive the VASPS. VASPS receives a full wellbore fluid stream and separates the stream into a gas phase stream and a liquid phase stream. The gas phase stream is then directed to a flowline and transported to other facilities for additional treating, while the liquid phase stream is pumped from the VASPS through a separate flowline to other treating facilities. Such subsea separation provides several benefits, including primary gas phase-liquid phase separation at a subsea location, which reduces the need for large, weighty separators on the offshore platforms to handle a gas-liquid flow regime and lessens “slugging” effects associated with such gas-liquid two-phase flow. 
     A typical VASPS unit includes an outer pressure housing, an inner helix separator assembly, a gas discharge annulus, a centrally located liquid discharge tube, a liquid discharge pump, and an electric motor to drive the liquid discharge pump. The entire VASPS unit would then be placed in an outer casing that may be cemented in the dummy well in the seabed. Alternatively, a VASPS unit may be placed in an outer housing mounted in a support placed on or near the subsea mudline. 
     During operation of a VASPS unit, a multiphase well stream (typically consisting of crude oil, natural gas, natural gas liquids, and salt water) enters the outer pressure housing and is directed to the inner helix separator for primary separation of the gas and liquid phase streams. This primary separation is accomplished through the application of centrifugal forces created by the cylindrical shape of the helix. Separated gas flows through holes in the helix into a gas discharge annulus and up into a gas expansion chamber. The gas then exits the VASPS unit into a separate flowline for delivery to and further treatment at the production facility (typically the offshore platform). Meanwhile, the degassed liquid flows in a counter-current direction from the exiting gas down the helix separator into a liquid sump area where it is pumped by the liquid discharge pump through the central liquid discharge tube into a separate flowline for delivery to and further treatment at the production facility (again typically the offshore platform). 
     Two of the key components for the removal of produced liquids from a VASPS unit are the electric motor and the liquid discharge pump. The electric motor is frequently combined with the liquid discharge pump to form an integrated unit referred to as an “electrical submersible pump” (ESP). ESPs are typically controlled and powered through an umbilical cord in communication with a remote control system and power source. The ESP discharges the produced, separated liquids through the liquid discharge tubing. 
     ESPs have long been used to produce liquid from wellbores, typically from formations having little or no produced gas. ESPs generally have difficulty (and are not particularly effective) in pumping fluids with significant volumes of free gas as the centrifugal impellers of an ESP are typically designed for pumping fluids rather than compressing gas. Hence, with gases separated from wellbore fluids in a VASPS unit, an ESP can operate more effectively and efficiently to remove liquids. ESPs are supplied by various oilfield equipment suppliers, including Schlumberger with its REDA® line of ESPs and Baker Hughes with its Centrilift® line of ESPs. In many installations, ESPs are positioned in wellbores so that the electric motor is mounted below the pump (including the pump intake and discharge outlets). In a typical installation in a vertical or near vertical well, an ESP is set below the well perforations to maximize liquid draw down and to minimize gas introduction into and interference with the pump. 
     During operation, an ESP&#39;s electric motor can produce significant amounts of heat. As ESPs have no separate, dedicated cooling system to remove heat generated during normal operations, ESPs are designed to use wellbore fluids as a cooling medium to keep the pump and the electric motor from overheating. In many ESP arrangements, the pump is mounted above the electrical motor. In such arrangements, a device referred to as a pump shroud is sometimes used to direct the wellbore fluids around the electric motor during operation and to remove heat generated during pump operation. Without such a pump shroud or other fluid directing device, wellbore fluid would not move past the electrical motor and therefore not remove any significant heat generated by the electrical motor. A pump shroud typically covers and encloses the pump inlet above the top of the electric motor and may be 75 to 100 feet (25 to 30 meters) long. The wellbore liquid flows along the outside of the pump shroud to the bottom of the ESP. The liquid then makes a 180-degree turn at the bottom of the pump shroud and then flows upward between the inside of the pump shroud and the electric motor, removing heat generated by the electric motor as the wellbore fluid moves past the motor and into the pump. The pump shroud is typically retrieved when the ESP is removed from the wellbore. 
     In some wellbores with ESP installations, as well as in wellbores using a VASPS unit, installed pump shrouds may create numerous problems and limitations to the operations of the ESP. An improperly mounted or damaged pump shroud can create multiple problems, such as misdirected fluid flow, which can lead to electric motor overheating, which can in turn lead to excessive scale build-up between the electric motor and the pump shroud, which can further lead to reduced fluid production due to scale build-up; poor gas separation due to pump shroud leakage; overheating of the electric pump causing shortened ESP run-times between repairs; and excessive pump shroud vibrations. Additionally, a pump shroud reduces the size of an ESP that can be placed in a given wellbore. If the pump shroud could be removed and replaced by a design that would provide the necessary wellbore fluid flow for adequate cooling of the ESP motor, larger ESPs, capable of moving more wellbore fluids, could be installed in a given opening. A more detailed description of a VASPS unit is provided below. 
     SUMMARY OF THE INVENTION 
     This invention provides an improved VASPS unit without the need for a separate pump shroud for redirecting fluid flow around the VASPS discharge pump through a rearrangement of the VASPS internal flow paths. Additionally, methods of operating a production facility using the improved VASPS to separate produced hydrocarbon fluids and other wellbore fluids into liquid and gas phase streams at subsea locations and directing the separated phase streams to other locations are also disclosed. 
     In particular, a subsea vertical separator of the present invention would include:
         (a) an intermediate casing within an outer casing, forming a first annulus;   (b) an inner casing within the intermediate casing, forming a second annulus;   (c) a fluid inlet in communication with the second annulus;   (d) a liquid outlet in communication with the first annulus;   (e) a gas passage in the inner casing for conducting separated gas phase fluids, wherein the gas passage has a gas inlet and a gas outlet;   (f) a pump assembly comprising a pump positioned within the intermediate casing having (i) a pump intake in fluid communication with the second annulus and (ii) a pump discharge in fluid communication with the first annulus; and   (g) a motor to drive the pump.       

     In any of the embodiments described, the subsea vertical separator could include a helix assembly positioned in the second annulus between the inner casing and the intermediate casing. 
     In any of the embodiments described, the subsea vertical separator could include an outer casing having a housing with an upper end and a lower end to provide pressure containment for the first annulus, second annulus, and gas passage. 
     In any of the embodiments described, the subsea vertical separator could include a separator head space in fluid communication with the first annulus. 
     In particular, a method for producing hydrocarbons from a subsea location comprising:
         (a) providing a production facility;   (b) installing a subsea vertical separator capable of separating produced wellbore fluids into a liquid phase and a gas phase, such separator comprising:
           (i) an intermediate casing within an outer casing, forming a first annulus;   (ii) an inner casing within the intermediate casing, forming a second annulus;   (iii) a fluid inlet in communication with the second annulus;   (iv) a gas passage in the inner casing for conducting separated gas phase fluids, wherein the gas passage has a gas inlet and a gas outlet;   (vi) a pump assembly comprising a pump positioned within the intermediate casing having (a) a pump intake in fluid communication with the second annulus and (b) a pump discharge in fluid communication with the first annulus;   (vii) a motor assembly to drive the pump;   
           (c) installing a piping system to transport separated gas to the production facility;   (d) installing a piping system to transport separated liquids to the production facility;   (e) connecting a power source and a control source to the motor assembly;   (f) producing wellbore fluids from the subsea location;   (g) transporting the produced wellbore fluids to the separator fluid inlet;   (h) separating the produced wellbore fluids into a gas phase and a liquid phase;   (i) transporting the gas phase fluids to the production facility; and   (j) transporting the liquid phase fluids to the production facility.       

    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Examples of the prior art and various embodiments of this invention are shown in the attached Figures, wherein: 
         FIG. 1  is a sectional view of a prior art VASPS unit; 
         FIG. 2  is a sectional view of a VASPS unit according to the present invention; 
         FIG. 3  is a sectional view of a VASPS unit according to the present invention mounted in a subsea location. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     The present invention provides a VASPS unit with improved gas stream and liquid stream flow path arrangements. In the preferred embodiment, a multiple casing arrangement is used in conjunction with an ESP assembly to allow wellbore fluids to circulate and separate into a gas stream and a liquid stream prior to the gas stream exiting the unit passage and the fluid stream entering the ESP pump intake for transportation and further treating. 
     Apparatus Description 
     The prior art VASPS and the improved VASPS of the present invention will now be described with reference to the Figures. 
       FIG. 1  shows a sectional view of a prior art VASPS unit  101 . Prior art VASPS unit  101  comprises pressure housing  103  surrounding intermediate casing  105  surrounding inner casing  107 , each typically in tubular form, constructed typically of standard size concentric oilfield pipe and casing materials. Typical sizes and materials of construction for these would include: (i) for pressure housing  103 : 30 to 36 inch (0.8 to 1.0 meter) casing having an overall length of about 100 to 225 feet (30 to 70 meters); (ii) for intermediate casing  105 : 16 to 26 inch (0.5 to 0.7 meter) pipe; and for inner casing  107 : 8 to 10 inch (0.25 to 0.35 meter) screwed tubing. 
     Positioned between pressure housing  103  and intermediate casing  105  is helix assembly  109 . Helix assembly  109  provides initial, primary separation of the gas phase and liquid phase of the produced fluids. Helix assembly  109  may be constructed from a length of metal plate twisted, rolled, or pressed to form a cylindrical spiral shape around and preferably connected to intermediate casing  105 . Helix assembly  109  preferably intersects intermediate casing  105  perpendicularly or nearly perpendicularly as helix assembly  109  spirals around intermediate casing  105 .  FIG. 1  shows a cross section of helix assembly  109  as it abuts perpendicularly to intermediate casing  105 . 
     Fluid inlet  111  allows fluids to enter pressure housing  103  into fluid annulus  113  formed between the inner wall of pressure housing  103  and the outer wall of intermediate casing  105 . Plate  115  is located at the top of intermediate casing  105  and isolates separator head-space  117  from fluid annulus  113 . Gas passages  119  extending through intermediate casing  105  allow for fluid (primarily gas) communication between fluid annulus  113  and gas annulus  121  formed between the inner wall of intermediate casing  105  and the outer wall of inner casing  107 . Liquid passages  120  extending through intermediate casing  105  allow for fluid (primarily liquid) communication between fluid annulus  113  near the lower end of intermediate casing  105  during operation of VASPS unit  101 . Gas passages  125  extending through plate  115  allow fluid (primarily gas) communication between gas annulus  121  and separator head-space  117 . Gas outlet  123  extends through pressure housing  103  to allow fluid (primarily gas) communication between separator head-space  117  and gas outlet flowline (not shown). 
     Inner casing  107  extends from liquid outlet  127  down through separator head-space  117  to ESP assembly  129 . ESP assembly  129  comprises pump shroud  131 , ESP pump  133 , and ESP motor  135 . Pump shroud  131  may extend to above, at, or below the bottom of intermediate casing  105 . ESP intake  137  communicates through ESP pump  133  into ESP discharge connection  139  into liquid passage  141  of inner casing  107  for discharge through liquid outlet  127 . 
     Prior art VASPS  101  is typically installed at a subsurface location at or above the mudline of subsea bed  145  and placed in base conduit  147  which is cemented in place in a dummy hole  149 . 
     A wide selection of materials are available for constructing VASPS  101 . Those reasonably skilled in the art of subsea production equipment are aware of material and equipment performance requirements for subsea equipment. Such individuals reasonably skilled in the art will consider factors such as operating temperatures and pressures, projected fluid production volumes, gas-liquid ratios, produced fluid quality, i.e., considering contaminants such as carbon dioxide and hydrogen sulfide, and other factors in selecting the materials to construct VASPS  101 . It is expected that most components of VASPS  101  are commercially available or easily fabricated from standard oil field equipment. 
     The operation of prior art VASPS  101  will now be discussed with reference to  FIG. 1 . Produced two-phase (liquid and gas) wellbore fluids enter prior art VASPS  101  through fluid inlet  111 . The wellbore fluids enter fluid annulus  113  and are routed through helix assembly  109  where they experience angular acceleration. The wellbore liquid stream (typically crude oil and water), being more dense that the wellbore gas (typically natural gas), will move to the inside edge of pressure housing  103  and begin moving downward under gravitational forces toward the bottom of pressure housing  103 . As the gas and fluid streams begin to separate and the separated gas stream moves toward the outer wall of intermediate casing  105 , gas-liquid interface  110  will form on top of helix assembly  109  and against the inner wall of pressure housing  103 . The less dense wellbore gas stream will move toward the center of intermediate casing  105  and into gas annulus  121  through gas passages  119 . The gas will then move up gas annulus  121  through gas passages  125  into separator head-space  117 . The separated gas will then move out of prior art VASPS  101  through gas outlet  123  and into a gas outlet flowline (not shown) for further treating and handling. 
     As the produced liquids move to the inside wall of pressure housing  103  and move downward under gravitational force, liquid accumulation occurs at the bottom of the prior art VASPS  101  so as to establish a liquid height  143 . The separated liquid may accumulate around ESP assembly  129  from fluid annulus  113  through liquid passages  120 . 
     When liquid height  143  reaches a predetermined level, ESP motor  135  is energized to drive ESP pump  133 . The monitoring of liquid height  143  and the control of ESP pump  133  are well known in the art and may utilize liquid still-wells with ultrasonic level sensors and variable speed pump controllers to control and power ESP pump  133  to remove accumulated, produced fluid from VASPS  101 . 
     The separated liquids (oil and water) flow downward between intermediate casing  105  and pump shroud  131  as shown by flow arrows  151 . At the bottom of pump shroud  131 , the produced liquid stream changes direction and then begins to flow upward past ESP motor  135  into ESP intake  137  as shown by flow arrows  153 . By flowing around the pump shroud  131  and back past ESP motor  135 , the produced wellbore liquids act as a cooling medium by removing heat from and generated by ESP motor  135 . 
     The separated liquid stream then flows through ESP pump  133  through ESP discharge connection  139  and into liquid passage  141  in inner casing  107  and out of prior art VASPS  101  through liquid outlet  127  as shown by flow arrows  155 . 
     VASPS of the prior art and current inventions may vary in size and capacity. ESP assembly  129  may include a ESP motor  135  having a 100 to 2000 horsepower rating and ESP pump  133  capable of moving 100 to 50,000 barrels of fluid a day at discharge pressures up to 3000 psi. 
       FIG. 2  shows a sectional view of the improved VASPS  200  of the present invention. VASPS  200  is comprised of outer casing pressure housing  212  surrounding intermediate casing  214  surrounding inner casing gas discharge tubing  216 . Pressure housing  212  and intermediate casing  214  may be constructed of any material, but are preferably constructed of standard oilfield tubulars such as casing materials or carbon steel pipe which are compatible with service conditions and requirements of a subsea facility. Likewise, gas discharge tubing  216 , may be constructed of any material, but is preferably constructed of standard, screwed oilfield tubulars which allow the easy placement and retrieval of portions of VASPS  200 . The upper and lower ends (not labeled in the Figures) of pressure housing  212  may be plates or other means to provide overall pressure containment for the operation of VASPS  200 , particularly pressure housing  212 , and each of the embodiments described herein. These plates or other means may be welded to or otherwise fixedly attached to pressure housing  212 . Also, the upper and lower ends might be connected to pressure housing  212  by use of removable connections to provide for the removal and repair or replacement of VASPS  200 . 
     Positioned between intermediate casing  214  and gas discharge tubing  216  is helix assembly  218 . Helix assembly  218  may be a series of vanes or plates, preferably welded on to the outer wall of gas discharge tubing  216 , that form a spiral conduit which contacts the inner wall of intermediate casing  214 . Wellbore fluids enter pressure housing  212  through fluid inlet  220  into fluid annulus  222  which is formed by the inner wall of intermediate casing  214  and the outer wall of gas discharge tubing  216 . Plate  224  is located at the top of intermediate casing  214  and extends to inner wall of pressure housing  212  and isolates separator head-space  226  from fluid annulus  222 . Gas passages  228  extend through gas discharge tubing  216  and allow for fluid (primarily gas) communication between fluid annulus  222  and gas annulus  231 . Gas phase flow  233  is noted by the arrows in  FIG. 2 . 
     It should also be understood that the Figures herein do not show any removable connectors means which might be used to secure and position the internal parts of VASPS  200  while providing for the removal for repair or replacement of VASPS  200 . For example, no removable connector means are shown to secure helix assembly  218  to intermediate casing  214  or to secure intermediate casing  214  to pressure housing  212 . Such connectors are considered standard equipment and well understood by individuals familiar with subsea oilfield production equipment and may be selected from commercially available subsea connector equipment. 
     Gas outlet  234  extends through pressure housing  212  to allow fluid (primarily gas) to exit the VASPS. Liquid passages  236  in plate  224  allow fluid (primarily liquid) communication between liquid annulus  230  and separator head-space  226 . It is preferred that fluid inlet  220 , gas outlet  234 , and liquid outlet  238  be at or near the top of VASPS  200 . 
     Liquid annulus  230  extends from the bottom of VASPS  200  along the wall of outer casing pressure housing  212  and is in fluid communication with liquid outlet  238  through liquid passage  236  and through separator head-space  226 . At the bottom of VASPS  200 , liquid annulus  230  extends into ESP assembly  240  at ESP discharge connection  258 . ESP assembly  240  comprises ESP pump  242  and ESP motor  244 . ESP pump  242  has ESP intake  248  (the pump inlet ports). 
     Intermediate casing  214  should preferably extend to or below the bottom of ESP assembly  240  with the exterior wall of intermediate casing  214  forming the interior wall of liquid annulus  230 . ESP intake  248  communicates with fluid annulus  222  below helix assembly  218 . ESP intake  248  is also in fluid communication with ESP pump  242  which moves liquid into ESP discharge connection  258  and into liquid annulus  230  for discharge through liquid passage  236  into head space  226  an through liquid outlet  238 . Liquid phase flow  261  is noted by the arrows in  FIG. 2 . 
     Controls to operate ESP assembly  240  to discharge the separated liquids are not shown in  FIG. 2 . The monitoring of liquid level and the control of ESP assembly  240  are well known in the art and may utilize liquid still-wells with ultrasonic level sensors or other level control devices and variable speed pump controllers to control and power ESP assembly  240  to remove accumulated, produced fluid from VASPS  200 . 
     Not shown in  FIG. 2  is the placement of VASPS  200  on the subsea floor. VASPS  200  is preferably installed at a location at or above the mudline of subsea bed (not shown) and placed in base conduit (not shown) which is cemented in place in a dummy hole. However, depending on the application and location of associated subsea facilities, VASPS  200  may be installed in a base conduit extending partially into the seabed. It is also possible to have VASPS  200  resting on the seabed or even above the seabed when integrated with other production equipment. 
     The operation of VASPS  200  will now be discussed with reference to  FIG. 2 . Produced two-phase (liquid and gas) wellbore fluids enter VASPS  200  through fluid inlet  220 . The wellbore fluids enter fluid annulus  222  where they experience angular acceleration caused by helix assembly  218 . The wellbore liquids (typically crude oil and water), being more dense that the wellbore gas (typically natural gas), will move to the inside edge of intermediate casing  214  and begin moving under gravitational forces toward the bottom of pressure housing  212 . The less dense wellbore gas will move toward the center of intermediate casing  214  and into gas annulus  231  through gas passages  228 . Gas-liquid interface  260  is formed on the upper side of helix assembly  218 . The gas will continue to move into gas annulus  231  through gas passages  228 . The separated gas will expand and then move out of VASPS  200  through gas outlet  234  and a gas outlet flowline (not shown) to other treating and handling facilities. 
     As the produced liquids move to the inside edge of intermediate casing  214  and move downward under gravitational force, separated liquids accumulate at the bottom of VASPS  200  so as to establish a liquid height  264 . The separated liquid may accumulate around ESP assembly  240  by moving downward through helix assembly  218 . 
     When liquid height  264  reaches a predetermined level, ESP motor  244  is energized to drive ESP pump  242 . The separated liquids (oil and water) flow downward between the outside wall of inner casing gas discharge tubing  216  and the inside wall of intermediate casing  214 . Near the bottom of intermediate casing  214 , the produced liquid flows past ESP motor  244  into ESP intake  248 . By flowing past ESP motor  244 , the produced wellbore fluids act as a cooling medium by removing heat from and generated by ESP motor  244 . This cooling process assists in maintaining an acceptable operating temperature for ESP motor  244 . 
     The produced liquids then move through ESP pump  242  and out ESP discharge connection  258  into liquid annulus  230 . The produced fluids then pass through liquid passages  236  and into separator head space  226  before exiting VASPS  200  through liquid outlet  238  to a liquid discharge line (not shown) and to another facility (not shown) for further treating. 
     The most significant differences in the prior art VASPS  101  of  FIG. 1  and the VASPS  200  of  FIG. 2  are (i) the removal of the pump shroud  131  ( FIG. 1 ), the relocation of the helix assembly  109  ( FIG. 1 ), (ii) the replacement of the inner casing  107  ( FIG. 1 ) to handle the fluid discharge with liquid annulus  230  ( FIG. 2 ) between the inner casing gas discharge tubing  216  ( FIG. 2 ) and outer casing pressure housing  212  ( FIG. 2 ), (iii) relocating the gas annulus  121  ( FIG. 1 ) with an inner casing gas discharge tubing  216  ( FIG. 2 ) to collect and remove the separated gas phase stream, and (iv) the placement of ESP motor  244  ( FIG. 2 ) above ESP pump  242  ( FIG. 2 ). The removal of the pump shroud  131  ( FIG. 1 ) provides many benefits, including reduced expenses associated with installing and maintaining the pump shroud and the ability to install a larger capacity ESP pump  242  ( FIG. 2 ) to produce more fluid from a given VASPS unit without increasing the size of the pressure housing  212  ( FIG. 2 ) or intermediate casing  214  ( FIG. 2 ). 
       FIG. 3  shows a sectional view of a preferred embodiment of the present invention. VASPS  301  comprises pressure housing  303  surrounding intermediate casing  305  surrounding inner casing gas discharge tubing  307 . Positioned between intermediate casing  305  and inner casing gas discharge tubing  307  is helix assembly  309 . 
     Fluid inlet  311  allows fluids to enter pressure housing  303  into fluid annulus  313  which is formed by the inner wall of intermediate casing  305  and the outer wall of inner casing gas discharge tubing  307 . Plate  314  is located at the top of intermediate casing  305  and isolates separator head-space  315  from fluid annulus  313 . Gas passages  317  allow for fluid (primarily gas) communication between fluid annulus  313  and gas annulus  319  in inner casing gas discharge tubing  307 . Gas outlet  323  extends through pressure housing  303  to allow fluid (primarily gas) communication between gas annulus  319  and gas outlet flowline  325 . 
     Liquid annulus  316  is formed between the outside wall of intermediate casing  305  and the inner wall of outer casing pressure housing  303 . Liquid annulus  316  extends from plate  314  near the top of VASPS  301  down to ESP discharge connection  334 . Liquid passages  335  allow fluid communication between liquid annulus  316  and separator head-space  315 . Liquid outlet  349  extends through pressure housing  303  to allow fluid (primarily liquid) communication between separator headspace  315  and liquid flowline  359 . Liquid phase flow  318  is noted by the arrows in  FIG. 3 . 
     ESP assembly  331  comprises ESP pump  333 , ESP motor  336 , and ESP intake  337 . ESP assembly  331  is suspended and preferably held in place within VASPS  301  at the end of inner casing gas discharge tubing  307 . 
     VASPS  301  is shown installed at a subsurface location at or above the mudline of subsea bed  343  and placed in base conduit  345 , which is cemented in place in a dummy hole  347 . 
     A complete installation and operation of a VASPS of the present invention would include installing a VASPS unit at a subsea location; providing a floating or other production vessel, platform, or other subsea or onshore arrangement (collectively referred to as a production facility); installing a piping system to transport separated gases and liquids to the production facility; connecting a power source and a control source to the VASPS unit; producing wellbore fluids from the subsea location; transporting the produced wellbore fluids to the VASPS unit; separating the produced wellbore fluids into a gas phase and a liquid phase; transporting the gas and liquid phase fluids to the production facility. 
     Having now fully described this invention, it will be appreciated by those skilled in the art that the invention can be performed within a wide range of parameters within what is claimed, without departing from the spirit and scope of the invention.