Abstract:
A Vertical Annular Separation and Pumping System (VASPS) utilizing an isolation baffle to replace a standard pump shroud associated with an electrical submersible pump. The isolation baffle may be a one piece plate positioned so as to direct produced wellbore liquids around the electrical submersible pump motor to provide a cooling medium to prevent overheating and early failure of the electrical submersible pump.

Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
     This application is the National Stage of International Application No. PCT/US06/016702, which claims the benefit of U.S. Provisional Application No. 60/706,740, filed 9 Aug. 2005. This application is related to International Application No. PCT/US06/017136 entitled “Vertical Annular Separation and Pumping System With Our Annulus Liquid Discharge Arrangement”, which claims the benefit of U.S. Provisional Application No. 60/706,799 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 hydrocarbon deposits continue to attraction 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 subsea 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 cost of the equipment on the offshore production platforms necessary to produce the hydrocarbons. 
     By reducing the installation weight and cost of equipment, new offshore installations may be smaller and less expensive for producing newly discovered fields. Additionally, existing offshore installations may be further modified to handle 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 than new offshore production platforms, such flowlines may limit the fluid production rate from a given well or collection of wells. 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 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 change in elevation causes 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 is frequently used as part of a subsea multiphase boosting system and artificial lifting method to increase 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. Also, such an arrangement lessens “slugging” effects associated with such gas-liquid two-phase flow by providing a constant fluid flow rate to the offshore production platform. 
     A typical VASPS unit may be a self-contained unit which includes an outer pressure housing, an inner helix separator assembly, a gas discharge annulus, a 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 toward the center of the VASPS unit 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 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. This difficulty occurs because 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 outlet). 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. Such misdirected fluid flow 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. Additionally, misdirected fluid flow may cause 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 electric motor. 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 first annulus;   (d) a gas outlet in communication with the second annulus;   (e) a liquid passage in the inner casing for conducting separated liquid phase fluids, wherein the liquid passage has a liquid inlet and a liquid outlet;   (f) a pump assembly comprising a pump positioned within the intermediate casing having (i) a pump intake and (ii) a pump discharge in fluid communication with the liquid inlet of the liquid passage;   (g) a motor positioned below the pump assembly to drive the pump; and   (h) an isolation baffle positioned between the inner casing and intermediate casing at or above the pump assembly, whereby separated liquid phase fluids accumulating in the second annulus above the isolation baffle are directed primarily to pass (i) from the second annulus into the first annulus above the isolation baffle, (ii) back into the second annulus at a location below the isolation baffle and at or below the motor assembly, and (iii) into the pump intake above the motor assembly.       

     In any of the embodiments described, the subsea vertical separator could include a helix assembly positioned in the first annulus between the outer casing and the intermediate casing. 
     In any of the embodiments described, the subsea vertical separator could include (a) first passages in the intermediate casing above the isolation baffle to allow separated gas phase fluids to pass from the first annulus to the second annulus and to the gas outlet and (b) second passages in the intermediate casing at or below the motor to allow separated liquid phase fluids to pass from the first annulus to the second annulus and to the pump intake. 
     In any of the embodiments described, the subsea vertical separator could include an opening below the motor and below the bottom of the intermediate casing, thereby allowing separated liquid phase fluids to flow (i) from the first annulus, (ii) under the bottom of the intermediate casing to the second annulus, (iii) upward past the motor assembly, and (iv) upward to the pump intake. 
     In any of the embodiments described, the subsea vertical separator could have the isolation baffle attached (a) to the pump assembly with a means for flexibly sealing against the intermediate casing or (b) to the inner casing above the pump assembly with a means for flexibly sealing against the intermediate casing. 
     In an embodiment described, the subsea vertical separator could have the isolation baffle attached to the pump assembly and a landing ring attached to the intermediate casing allowing the landing ring to receive the isolation baffle and providing a substantial fluid seal against the intermediate casing. 
     In any of the embodiments described, the subsea vertical separator could include a landing guide attached to the pump assembly capable of guiding the pump assembly through the landing ring. 
     In an embodiment described, wherein the isolation baffle could be attached to the inner casing and a landing ring could be attached to the intermediate casing whereby the landing ring is capable of receiving the isolation baffle and providing a fluid seal against the intermediate casing. 
     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) a helix assembly positioned in the first annulus between the outer casing and the intermediate casing;   (c) an inner casing within the intermediate casing, forming a second annulus;   (d) a fluid inlet in communication with the first annulus;   (e) a gas outlet in communication with the second annulus;   (f) a liquid passage in the inner casing for conducting separated liquid phase fluids, wherein the liquid passage has a liquid inlet and a liquid outlet;   (g) a pump assembly comprising a pump positioned within the intermediate casing having (i) a pump intake and (ii) a pump discharge in fluid communication with the liquid inlet of the liquid passage;   (h) a motor positioned below the pump assembly to drive the pump;   (i) an isolation baffle positioned between the inner casing and intermediate casing at or above the pump assembly, whereby separated liquid phase fluids accumulating in the second annulus above the isolation baffle are directed primarily to pass (i) from the second annulus into the first annulus above the isolation baffle, (ii) back into the second annulus at a location below the isolation baffle and at or below the motor assembly, (iii) into the pump intake above the motor assembly, (iv) through the pump, (v) through the liquid inlet of the liquid passage, (vi) through the liquid passage, and (vii) finally through the liquid outlet of the liquid passage;   (j) first passages in the intermediate casing above the isolation baffle to allow separated gas phase fluids to pass from the first annulus to the second annulus and to the gas outlet; and   (k) second passages in the intermediate casing at or below the motor to allow separated liquid phase fluids to pass from the first annulus to the second annulus and to the pump intake.       

     In particular, a method for producing hydrocarbons from a subsea location of the present invention would include:
         (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 first annulus;   (iv) a gas outlet in communication with the second annulus;   (v) a liquid passage in the inner casing for conducting separated liquid phase fluids, wherein the liquid passage has a liquid inlet and a liquid outlet;   (vi) a pump assembly comprising a pump positioned within the intermediate casing having (a) a pump intake and (b) a pump discharge in fluid communication with the liquid inlet of the liquid passage;   (vii) a motor assembly positioned below the pump assembly to drive the pump; and   (viii) an isolation baffle positioned between the inner casing and intermediate casing at or above the pump assembly, whereby separated liquid phase fluids accumulating in the second annulus above the isolation baffle are directed primarily to pass (a) from the second annulus into the first annulus above the isolation baffle, (b) back into the second annulus at a location below the isolation baffle and at or below the motor assembly, and (c) into the pump intake above the motor assembly;   
           (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. 2A  is a sectional view of a VASPS unit according to the present invention showing an isolation baffle adjacent to the ESP pump assembly; 
         FIG. 2B  is a detail view of an isolation baffle according to the present invention; 
         FIG. 2C  is a sectional view of a VASPS unit according to the present invention showing an isolation baffle adjacent to the liquid discharge tubing; 
         FIG. 3A  is a sectional view of a VASPS unit according to the present invention showing an isolation baffle adjacent to the pump assembly with a landing ring to receive the isolation baffle; 
         FIG. 3B  is a sectional view of a VASPS unit according to the present invention showing an isolation baffle adjacent to the liquid discharge tubing with a landing ring to receive the isolation baffle; 
         FIG. 4A  is a sectional view of a VASPS unit according to the present invention showing a flexible seal adjacent to the pump assembly with a sealing bushing to receive the isolation baffle; 
         FIG. 4B  is a detail view of a sealing bushing according to the present invention; 
         FIG. 4C  is a sectional view of a VASPS unit according to the present invention showing a flexible seal adjacent to the liquid discharge tubing with a sealing bushing to receive the isolation baffle; 
         FIG. 4D  is a detail view of a sealing bushing according to the present invention; and 
         FIG. 5  is a sectional view of one embodiment of a VASPS unit according to the present invention mounted in a subsea location showing an isolation baffle adjacent to the pump assembly. 
         FIG. 6  is a flow chart illustrating a method of producing hydrocarbons from a subsea location according to an embodiment of the present invention. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     The present invention provides a VASPS unit without a separate pump shroud to circulate wellbore fluids for use as a cooling medium for the ESP electric motor on the VASPS unit. In one embodiment, an isolation baffle is mounted to an ESP assembly and positioned to allow wellbore fluids to circulate around an intermediate casing below the ESP electric motor prior to entering the ESP pump intake. 
     In another embodiment, an isolation baffle is mounted to an inner fluid discharge tubing and positioned to direct wellbore fluids to circulate around the intermediate casing below the ESP electric motor prior to entering the ESP pump intake. 
     In another embodiment, an isolation baffle is mounted to an ESP assembly and a landing ring is installed against an intermediate casing to receive the isolation baffle to direct wellbore fluids to circulate around the intermediate casing below the ESP electric motor prior to entering the ESP pump intake. 
     In another embodiment, an isolation baffle is mounted to an inner fluid discharge tubing and a landing ring is installed against an intermediate casing to receive the isolation baffle to direct wellbore fluids to circulate around the intermediate casing below the ESP electric motor prior to entering the ESP pump intake. 
     In another embodiment, a flexible seal is mounted to an ESP assembly and a sealing bushing is installed against an intermediate casing to receive the flexible seal to direct wellbore fluids to circulate around the intermediate casing below the ESP electric motor prior to entering the ESP pump intake. 
     In another embodiment, an isolation baffle with a exterior flexible seal is mounted to an inner fluid discharge tubing and a sealing bushing is installed against an intermediate casing to receive the exterior flexible seal to direct wellbore fluids to circulate around the intermediate casing below the ESP electric motor prior to entering the ESP pump intake. 
     Apparatus Description 
     A prior art VASPS unit and the improved VASPS units 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 produced fluids into a gas phase and a liquid phase. 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 arrow  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. 2A  shows a sectional view of the improved VASPS  10  of the present invention. VASPS  10  is comprised of outer casing pressure housing  12  surrounding intermediate casing  14  surrounding inner casing liquid discharge tubing  16 . Pressure housing  12  and intermediate casing  14  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, liquid discharge tubing  16 , 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  10 . The upper and lower ends (not labeled in the Figures) of pressure housing  12  may be plates or other means to provide overall pressure containment for the operation of VASPS  10 , particularly pressure housing  12 , and each of the embodiments described herein. These plates or other means may be welded to or otherwise fixedly attached to pressure housing  12 . Also, the upper and lower ends might be connected to pressure housing  12  by use of removable connections to provide for the removal and repair or replacement of VASPS  10 . 
     Positioned between pressure housing  12  and intermediate casing  14  is helix assembly  18 . Helix assembly  18  may be a series of vanes or plates, preferably welded on to the outer wall of intermediate casing  14 , that form a spiral conduit which contacts the inner wall of pressure housing  12 . Wellbore fluids enter pressure housing  12  through fluid inlet  20  into fluid annulus  22  which is formed by the inner wall of pressure housing  12  and the outer wall of intermediate casing  14 . Plate  24  is located at the top of intermediate casing  14  and extends to inner wall of pressure housing  12  and isolates separator head-space  26  from fluid annulus  22 . Gas passages  28  extend through intermediate casing  14  and allow for fluid (primarily gas) communication between fluid annulus  22  and gas annulus  30  which is formed by the inner wall of intermediate casing  14  and the outer wall of liquid discharge tubing  16 . Lower passages  32  extending through intermediate casing  14  allow fluid (primarily liquid) communication between gas annulus  30  and fluid annulus  22  near the lower end of intermediate casing  14 . Gas outlet  34  extends through pressure housing  12  to allow fluid (primarily gas) communication between separator head-space  26  and gas outlet flowline (not shown). Gas passages  36  in plate  24  allow fluid (primarily gas) communication between gas annulus  30  and separator head-space  26 . It is preferred that fluid inlet  20 , gas outlet  34 , and liquid outlet  38  be at or near the top of VASPS  10 . 
     It should also be understood that the Figures herein do not show any removable connector means which might be used to secure and position the internal parts of VASPS  10  while providing for the removal for repair or replacement of VASPS  10 . For example, no removable connector means are shown to secure helix assembly  18  to intermediate casing  14  or to secure intermediate casing  14  to pressure housing  12 . 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. 
     Liquid discharge tubing  16  having liquid passage  58  extends from liquid outlet  38  down through separator head-space  26  to liquid passage inlet  57  and into ESP assembly  40  at ESP discharge connection  56 . ESP assembly  40  comprises ESP pump  42 , ESP motor  44 , and isolation baffle  46 . Isolation baffle  46  is attached in  FIG. 2A  to ESP assembly  40  above ESP intake  48  (the pump inlet ports) and contacts the inside wall of intermediate casing  14 . Isolation baffle  46  will preferably be a circular disk with a flexible outer edge seal  52 . Isolation baffle  46  should be fabricated from a material stiff enough to support and not deflect away from the inside wall of intermediate casing  14  under differential pressure to be encountered across isolation baffle  46  during operation of the ESP assembly  40 . A preferred material for isolation baffle  46  and flexible outer edge seal  52  would be a neoprene or high density polyethylene material. It is not critical that flexible outer edge seal  52  form a leak proof seal against the inside wall of intermediate casing  14 , but only necessary that the seal directs an adequate amount of fluid through lower liquid passage  54  to properly cool ESP motor  44 . Additionally, isolation baffle  46  may be a circular, carbon steel metal plate with only outer edge  52  fabricated from a neoprene or high density polyethylene type material. A detail of isolation baffle  46  and outer edge  52  is shown in  FIG. 2B . 
     The bottom of intermediate casing  14  should preferably extend to or below the bottom of ESP assembly  40  and most preferably below ESP motor  44 . ESP intake  48  communicates with fluid annulus  22  through lower liquid passages  54  below the bottom of intermediate casing  14 . ESP intake  48  is also in fluid communication with ESP pump  42  which moves liquid into ESP discharge connection  56  at liquid passage inlet  57  and into liquid passage  58  of liquid discharge tubing  16  for discharge through liquid outlet  38 . Liquid phase flow  61  is noted by the arrows in  FIG. 2A . Controls to operate ESP assembly  40  to discharge the separated liquids are not shown in  FIG. 2A . The monitoring of liquid level and the control of ESP assembly  40  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 assembly  40  to remove accumulated, produced fluid from VASPS  10 . 
     Not shown in  FIG. 2A  is the placement of VASPS  10  on the subsea floor. VASPS  10  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  10  may be installed in a base conduit extending partially into the seabed. It is also possible to have VASPS  10  resting on the seabed or even above the seabed when integrated with other production equipment. 
     The operation of VASPS  10  will now be discussed with reference to  FIGS. 2A and 2B . Produced two-phase (liquid and gas) wellbore fluids enter VASPS  10  through fluid inlet  20 . The wellbore fluids enter fluid annulus  22  where they experience angular acceleration caused by helix assembly  18 . 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 pressure housing  12  and begin moving under gravitational forces toward the bottom of pressure housing  12 . The less dense wellbore gas will move toward the center of intermediate casing  14  and into gas annulus  30  through gas passages  28 . Gas-liquid interface  29  is formed on the upper side of helix assembly  18 . The gas will then move up gas annulus  30  through gas passages  36  into separator head-space  26 . The separated gas will expand and then move out of VASPS  10  through gas outlet  34  and a gas outlet flowline (not shown) to other treating and handling facilities. 
     As the produced liquids move to the inside edge of pressure housing  12  and move downward under gravitational forces, separated liquids accumulate at the bottom of VASPS  10  so as to establish a liquid height  60 . The separated liquid may accumulate around ESP assembly  40  by moving from fluid annulus  22  through lower liquid passages  54 . 
     When liquid height  60  reaches a predetermined level, ESP motor  44  is energized to drive ESP pump  42 . The separated liquids (oil and water) flow downward between pressure housing  12  and intermediate casing  14  as shown by flow arrows  61 . At the bottom of intermediate casing  14 , the produced liquid changes direction and then begins to flow upward past ESP motor  44  into ESP intake  48 . By flowing around the intermediate casing  14  and through lower liquid passages  54  and then back past ESP motor  44 , the produced wellbore fluids act as a cooling medium by removing heat from and generated by ESP motor  44  and assist in maintaining an acceptable operating temperature for ESP motor  44 . 
     The produced liquids then move through ESP pump  42  and out ESP discharge connection  56  through liquid passage inlet  57  into liquid passage  58  in liquid discharge tubing  16 . The produced fluids then exit VASPS  10  through liquid outlet  38  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  and the VASPS  10  of  FIGS. 2A and 2B  are (i) the removal of the pump shroud  131  ( FIG. 1 ) and its replacement with isolation baffle  46  ( FIG. 2A ) and (ii) the removal of certain liquid flow passages  120  below the top of ESP assembly  129  ( FIG. 1 ) and the ensuing redirection of liquid flow at the base of the VASPS  10 . Additionally, lower passages  32  do not extend through intermediate casing  14  below isolation baffle  46 . 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  42  to produce more fluid from a given VASPS unit without increasing the size of the pressure housing  12  or intermediate casing  14 . 
       FIG. 2C  shows a sectional view of an another embodiment of VASPS  10  as modified from the embodiment shown in  FIG. 2A . The only change in  FIG. 2B  from the embodiment shown in  FIG. 2A  is the location of the attachment of isolation baffle  70 . Specifically, isolation baffle  70 , with flexible outer edge seal  62 , of the embodiment shown in  FIG. 2C  attaches to the outside wall of inner casing liquid discharge tubing  16  above ESP assembly  40 . As with isolation baffle  46  in  FIG. 2A , isolation baffle  70  will preferably be a circular disk with a flexible outer edge seal  62 . Isolation baffle  70  should be fabricated from a material stiff enough to support and not deflect away from the inside wall of intermediate casing  14  under any differential pressure expected to be encountered across isolation baffle  70 . A preferred material for isolation baffle  70  and flexible outer edge seal  62  would be a neoprene or high density polyethylene material. It is not critical that flexible outer edge seal  62  form a leak proof seal against the inside wall of intermediate casing  14 , but only necessary that the seal directs an adequate amount of fluid through lower liquid passage  54  to properly cool ESP motor  44 . Additionally, isolation baffle  70  may be a circular, carbon steel metal plate with only outer edge  62  fabricated from a neoprene or high density polyethylene type material 
     For the embodiment shown in  FIG. 2C , it is preferred that isolation baffle  70  is attached to the outside wall of liquid discharge tubing  16  whereby when installed in intermediate casing  14 , isolation baffle  70  is positioned below the lowest lower passage  32  to prevent excessive movement of liquid from fluid annulus  22  (or gas annulus  30 ) directly to ESP intake  48  without first moving past ESP motor  44 . 
       FIG. 3A  shows a sectional view of a further modification of VASPS  10  shown in  FIG. 2A . The embodiment shown in  FIG. 3A  has a modified isolation baffle  64 , which is again attached to ESP assembly  40 , but has a diameter somewhat less than the inside diameter of intermediate casing  14 . Attached to the inside of intermediate casing  14  is landing ring  66  which is positioned to contact and receive isolation baffle  64  when ESP assembly  40  is placed in VASPS  10 . Landing ring  66  should have an inside diameter smaller than the outside diameter of isolation baffle  64 . When isolation baffle  64  is engaged with landing ring  66 , wellbore fluids will be directed around the bottom of intermediate casing  14  and up past ESP motor  44  and into ESP intake  48 . As in the embodiments shown in  FIGS. 2A and 2C , it is not necessary that a leak proof seal be formed by the isolation baffle  64  against landing ring  66 , but only that excessive movement of liquid from fluid annulus  22  (or gas annulus  30 ) directly to ESP intake  48  without first moving past ESP motor  44  is prevented. An improved seal may be accomplished with a flexible insert (not shown) such as neoprene or high density polyethylene placed on the surface between the under surface of isolation baffle  64  and the upper surface of landing ring  66 . 
     To assist in placing ESP assembly  40  through landing ring  66 , alignment guide  68  may be attached to ESP assembly  40 . Alignment guide  68  may be any simple metal or other material structure, preferably pointed or conical in shape, that prevents the bottom of ESP assembly  40  from engaging, and not moving past, landing ring  66  while inserting ESP assembly  40  during assembly or repair operations for VASPS  10 . 
       FIG. 3B  shows a sectional view of another embodiment of VASPS  10  as modified from the embodiment shown in  FIG. 3A . In  FIG. 3B , isolation baffle  71  attaches to the outside wall of inner casing liquid discharge tubing  16  above ESP assembly  40 . Landing ring  72  is attached to the inside of intermediate casing  14 . For the embodiment shown in  FIG. 3B , it is preferred that isolation baffle  71  is attached to the outside wall of liquid discharge tubing  16  so that when installed in intermediate casing  14 , isolation baffle  71  is positioned below the lowest lower passages  32  to prevent excessive movement of liquid from fluid annulus  22  directly to ESP intake  48  without moving past ESP motor  44 . Additionally, the embodiment shown in  FIG. 3B  has alignment guide  68  to assist in placing ESP assembly  40  through landing ring  72 . 
       FIG. 4A  shows a sectional view of another modification of VASPS  10  shown in  FIG. 2A . The embodiment shown in  FIG. 4A  has flexible seal  74  attached preferably at or near the top of ESP assembly  40  that engages the inner wall of sealing bushing  76 . A preferred material for flexible seal  74  would be a neoprene or high density polyethylene material. Additionally, sealing bushing  76  is attached to the inside of intermediate casing  14 . For the embodiment shown in  FIG. 4A , it is preferred that sealing bushing  76  be attached to the inside wall of intermediate casing  14  so that flexible seal  74  is positioned below the lowest lower passages  32  to prevent excessive movement of liquid from fluid annulus  22  directly to ESP intake  48  without moving past ESP motor  44 . Sealing bushing  76  is similar to landing ring  66  of  FIGS. 3A and 3B , but has a more cylindrical shape with a greater length to provide a long sealing surface for flexible seal  74  to engage the inner surface of sealing bushing  76  and fuller alignment of ESP assembly  40  in VASPS  10 . As in the embodiments described herein, it is not necessary that a leak proof seal be formed by the flexible seal  74  against its seating location (sealing bushing  76 ), but only that excessive movement of liquid from above ESP assembly  40  directly to ESP intake  48  without moving past ESP motor  44 . A detail of flexible seal  74  and sealing bushing  76  is shown in  FIG. 4B . 
       FIG. 4C  shows a sectional view of an another embodiment of VASPS  10  as modified from the embodiment shown in  FIG. 4A . In  FIG. 4C , isolation baffle  78  attaches to the outside wall of inner casing liquid discharge tubing  16  above ESP assembly  40 . At the edge of isolation baffle  78  is flexible seal  77  that engages the inner wall of sealing bushing  80 . Sealing bushing  80  is attached to the inside of intermediate casing  14 . For the embodiment shown in  FIG. 4C , it is preferred that isolation baffle  78  be attached to the outside wall of intermediate casing liquid discharge tubing  16  so that when installed in intermediate casing  14 , isolation baffle  78  is positioned below the lowest lower passages  32  to prevent excessive movement of liquid from fluid annulus  22  directly to ESP intake  48  without moving past ESP motor  44 . Additionally, the embodiment shown in  FIG. 4C  has alignment guide  68  to assist in placing ESP assembly  40  through sealing bushing  80 . A detail of flexible seal  77  and sealing bushing  80  is shown in  FIG. 4D . 
       FIG. 5  shows a sectional view of a preferred embodiment of the present invention. VASPS  501  comprises pressure housing  503  surrounding intermediate casing  505  surrounding inner casing forming liquid discharge tubing  507 . Positioned between pressure housing  503  and intermediate casing  505  is helix assembly  509 . 
     Fluid inlet  511  allows fluids to enter pressure housing  503  into fluid annulus  513  which is formed by the inner wall of pressure housing  503  and the outer wall of intermediate casing  505 . Plate  514  is located at the top of intermediate casing  505  and isolates separator head-space  515  from fluid annulus  513 . Gas passages  527  in plate  514  allow fluid (primarily gas) communication between gas annulus  519  and separator head-space  515 . Gas passages  517  allow for fluid (primarily gas) communication between fluid annulus  513  and gas annulus  519  which is formed by the inner wall of intermediate casing  505  and the outer wall of liquid discharge tubing  507 . Lower passages  521  allow for fluid (primarily liquid) communication between gas annulus  519  and fluid annulus  513  near the lower end of intermediate casing  505 . Gas outlet  523  extends through pressure housing  503  to allow fluid (primarily gas) communication between separator head-space  515  and gas outlet flowline  525 . 
     Liquid discharge tubing  507  extends from liquid outlet  529  with liquid discharge passage  536  down through separator head-space  515  to ESP assembly  531  at liquid inlet  532 . ESP assembly  531  comprises ESP pump  533 , ESP discharge fitting  534 , ESP motor  535 , and pump inlet  537 . Isolation baffle  539  is attached to ESP assembly  531  above ESP intake  537  and contacts the inside wall of intermediate casing  505 . Isolation baffle  539  includes flexible outer edge seal  541 . 
     VASPS  501  is shown installed at a subsurface location at or above the mudline of subsea bed  543  and placed in base conduit  545 , which is cemented in place in a dummy hole  547 . 
     Referring to  FIG. 6 , a complete installation and operation of a VASPS of the present invention would include installing a VASPS unit at a subsea location  702 ; providing a floating or other production vessel, platform, or other subsea or onshore arrangement (collectively referred to as a production facility)  704 ; installing a piping system to transport separated gases and liquids to the production facility  706 ; connecting a power source and a control source to the VASPS unit  708 ; producing wellbore fluids from the subsea location  710 ; transporting the produced wellbore fluids to the VASPS unit  712 ; separating the produced wellbore fluids into a gas phase and a liquid phase  714 ; transporting the gas and liquid phase fluids to the production facility  716 . 
     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.