DOWNHOLE GAS SEPARATOR APPARATUS

Abstract

A downhole gas separator apparatus for separating gas from liquids during extraction of oil from the ground is disclosed. The apparatus can be used for high angle or horizontal wells, as well as low angle or vertical wells. The dimensions can vary to be used for extra heavy oil as well as light crude oil.

Description

FIELD OF THE INVENTION

The invention relates to a new or improved downhole gas separator apparatus for separating gas from liquids in well fluid during extraction of oil, and in particular relates to a new or improved downhole gas separator apparatus and method of separating gas and liquid in well fluid. The apparatus can be used for high angle or horizontal wells, as well as low angle or vertical wells. The dimensions can vary to be used for extra heavy oil as well as light crude oil.

BACKGROUND OF THE INVENTION

Throughout their productive life, most oil wells produce oil, gas, and water. This mixture is separated at the surface. Initially, the mixture coming from the reservoir may be mostly oil and gas with a small amount of water. Over time, the percentage of water increases. Increased water production eventually leads to the need for artificial lift, since water is heavier than oil. The pressure formed by the column of oil/water mixture in the wellbore may exceed the reservoir pressure. When this occurs, the well can no longer free flow by natural flow and artificial lift is required for the remainder of the well's life. In many oil wells, and particularly those in fields that are established and aging, natural pressure has declined to the point where the oil must be artificially lifted to the surface.

The most common type of artificial lift pump system applied is beam pumping, which engages equipment on and below the surface to increase pressure in the well by and push oil to the surface. Consisting of a sucker rod string and a sucker rod pump, beam pumps are the familiar jack pumps seen on onshore oil wells.

In beam pumping, subsurface pumps are located in the well below the level of the oil. A string of sucker rods extends from the pump up to the surface to a pump jack device, beam pump unit or other devices. A prime mover, such as a gasoline or diesel engine, an electric motor or a gas engine, on the surface causes the pump jack to rock back and forth, thereby moving the string of sucker rods up and down inside of the well tubing.

The string of sucker rods operates a subsurface positive displacement pump called a sucker rod pump (“SRP”) having a plunger that is reciprocated inside of a barrel by the sucker rods. Reciprocation charges a chamber between the valves with fluid and then lifts the well fluid up the tubing towards the surface. The SRP is inserted or set in the tubing near the bottom of the well. Each upstroke of the beam unit lifts the oil above the pump's plunger.

FIG. 1 depicts a beam pumping system for a producing oil well known in the prior art. Production casing 10 extends from the surface equipment 11 down to the producing zone 12. Production tubing 14 extends downwardly from the surface equipment at 11 to the area of the producing zone 12. The production tubing 14 comprises a series of joints screwed together to form a hollow, cylindrical production passageway 15 upwardly to surface collection equipment illustrated by the collection line at 16. The production tubing 14 is of a smaller external diameter than the casing 10 such that an annular area or “annulus” 17 is formed between the production casing 10 and production tubing 14. An annulus collection line 18 collects gas from the annulus 17.

A pumping unit 19 is utilized which drives a rod or shaft 20 which extends from the pumping unit downwardly through the production tubing to a pump 21. The shaft or rod 20 is called a “sucker rod” and the pump 21 is called a “sucker rod pump.”

Typically, the SRP includes an outer housing 21a that mounts pumping piston 21b which is operably connected to the sucker rod 20 for movement between an up position at the end of the up stroke and a down position at the end of the down stroke. Typically, such SRPs collect well fluid within the housing 21a during the down stroke of the piston 21b and pump well fluid outwardly of the pump housing 21a and into the production tubing passageway 15 during the upstroke so that the well fluid is collected from the surface line 16.

Another type of artificial lift pumping system is hydraulic pumping equipment which utilizes a downhole hydraulic pump, rather than sucker rods, to lift well fluid to the surface. Well fluid is forced against the pistons, causing pressure and the pistons to lift the well fluids to the surface. Similar to the physics applied in waterwheels powering old-fashion gristmills, the natural energy within the well is put to work to raise the well fluid to the surface.

Progressing cavity pumps (PCP) are volumetric type (positive displacement) pumps that can be used in artificial lift pumping systems. PCP systems typically consist of a surface drive, drive string and downhole PCP. The PCP comprises a single helical-shaped rotor that turns inside a double helical stator. The stator is attached to the production tubing and remains stationary during pumping. In most cases the rotor is attached to a sucker rod string which is suspended and rotated by a surface power unit. As the rotor turns eccentrically in the stator, a series of sealed cavities form and progress from the inlet to the discharge end of the pump. The result is a non-pulsating positive displacement flow with a discharge rate proportional to the size of the cavity, rotational speed of the rotor and the differential pressure across the pump. The stator of a PCP has an elastomer covering that can be damaged by gases such as carbon dioxide and hydrogen sulfide which are typically encountered in oil wells.

FIG. 2 depicts a PCP system for a producing oil well known in the prior art. Electric submersible pump systems (ESP) are also used in artificial lift pumping systems. ESPs employ a centrifugal pump below the level of the well fluid. Connected to a long electric motor, the ESP comprises several impellers, or blades, that spin and move the well fluid within the well. The system is installed at the bottom of the tubing string. An electric cable runs the length of the well, connecting the ESP to a surface source of electricity. The downhole components are suspended from the production tubing above the wells' perforations. In most cases the motor is located on the bottom of the work string. Above the motor is the seal section, the intake or gas separator, and the pump. The power cable is banded to the tubing and plugs into the top of the motor. As the well fluid comes into the well it must pass by the motor and into the pump. This well fluid flow past the motor aids in the cooling of the motor. The well fluid then enters the intake and is taken into the pump. Each stage (impeller/diffuser combination) adds pressure or head to the fluid at a given rate. The well fluid will build up enough pressure as it reaches the top of the pump to lift it to the surface and into the separator or flowline.

FIG. 3 depicts an ESP system for a producing oil well known in the prior art. In low pressure wells where gas is being produced along with oil, the gas tends to come out of the well fluid due to the low pressure of the well and may cause gas lock in the pump. Gas lock can reduce the efficiency of the pump substantially and can damage the pump. In very gaseous wells, the problem of gas lock in the pump can be of such severity that the well has to be shut. Typically, the more gas which can be eliminated from the well fluid, the better the operation of the pump.

The presence of gas in the well fluid being pumped can also damage the pump through heat generation, cavitation and/or gas absorption. For example, PCPs rely for their lubrication and cooling on the liquid that is being pumped. If this liquid contains too high a content of gas, then the pump will not be properly lubricated and cooled. Where lubrication and/or cooling are insufficient, then the pump stator may experience accelerated wear, and furthermore the heat generated by friction between the rotor and the stator can cause the stator to be “cooked” or “burned” resulting in premature failure of the stator and the pump.

For pumping wells based on PCP, SRP and ESP, tubing anchor, torque anchor or centralizers are typically used below the pump for stabilization purposes. These stabilizers force pump intake to be centralized and act adversely in term of gas liquid separation efficiency by allowing more gas to be dragged to the pump intake, reducing pumping efficiency and reducing run life in many cases.

As noted, low pumping efficiency can greatly increase operating expenses of the well due to, among others, excessive electrical power usage, a decrease in the amount of production from the well and additional maintenance requirements due to inefficient loadings of the pumping unit, rod string, motor and pump. To increase pumping efficiency it is common for downhole gas separators (DGSs) that separate gas from the liquid mixture in well fluid to be installed in the production tubing below the intake of the pump. The main purpose of the DGS is to enhance the generation of gas bubbles that can then be released through the production casing annulus.

Various types of DGSs are currently available. Conventional separators typically use bubbling separation but generally have a lower separating efficiency than is desirable. Cascade flow type separators, stratified type separators and Jukovski effect type separators generally offer greater efficiency over conventional separators. However, these separators depend on the level of liquid within them being maintained within a specified range which requires the use of an external manual or automatic control system based on sensors, valves and links between them. Such control systems and sensors are vulnerable points that add complexity to the system.

For example, in FIG. 1, an oil/gas separator S (DGS) is shown to be mounted at the end of the production tubing or string 14 in an area adjacent to the producing zone 12 in order to receive the oil/gas mixture flowing from the production zone 12 and separate sufficient gas out of the oil/gas mixture to avoid gas lock in the sucker rod pump 21.

SUMMARY OF THE INVENTION

The downhole gas separator apparatus for heavy oil according to the invention is a production optimization tool for improve pumping efficiency for SRP, PCP and ESP systems, allowing liquid-rich well fluid to be delivered to pump intake. The downhole gas separator apparatus thus helps to improve run life of the pump and oil production by increasing oil production and volumetric efficiency. By reducing free gas at the pump intake, operating conditions are improved allowing considerable savings in power, downhole pump sizes (smaller pumps to achieve same liquid rate) and rig services due to extended run life that can be achieved by improvement of pumping conditions.

The downhole gas separator apparatus comprises an internal element and an external element, and is disposed within the production casing below the pump intake. Two eccentric annuli are formed: (1) one annulus is formed between the external element and the production casing, where the external element is placed in an offset position related to the production casing (the “first eccentric annulus”) and (2) one annulus is formed between the internal element and the external element, where the internal element is placed in an offset position related to the external element (the “second eccentric annulus”). The downhole gas separator apparatus further comprises a sealing element at the bottom end of the external element that prevents well fluid from entering the apparatus from the production casing. The downhole gas separator apparatus further comprises a plurality of intake ports disposed at the top end leading into the second eccentric annulus. The internal element and the outer element are further disposed such that well fluid flows from the second eccentric annulus into the internal element at the bottom of the apparatus.

The downhole gas separator apparatus is installed below the pump intake (and pump centralizer). The first eccentric annulus and the second eccentric annulus together enhance gas-liquid separation based on density differences of oil and gas as well as changes of flow direction of well fluid. The dual eccentric annulus design creates preferential paths for liquid and gas flow.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention will be described with reference to the accompanying drawings, in which like elements are referenced with like numerals.

FIGS. 1 to 3 depict artificial lift pump systems known in the prior art.

FIGS. 4A-B depict Average Pump Intake (PIP) and Pump Discharge Pressure (PDP) before (where available) and after running with the downhole gas-oil separator apparatus of the invention installed.

FIGS. 5A-D provide a comparison of liquid rate before (stable conditions) and after installation of the apparatus of the invention (optimized point) was carried out.

FIGS. 6A-B provide data regarding separation efficiency with and without the downhole gas-oil separator apparatus of the invention.

FIGS. 7A-7G depict views of the external element and the interior element comprising the downhole gas separator apparatus according to one embodiment of the invention.

FIG. 8 depicts an end view of the downhole gas separator apparatus according to one embodiment of the invention.

DETAILED DESCRIPTION OF THE INVENTION

The downhole gas separator apparatus for heavy oil according to the invention is a production optimization tool for improve pumping efficiency for SRP, PCP and ESP systems, allowing liquid-rich well fluid to be delivered to pump intake. The downhole gas separator apparatus thus helps to improve run life of the pump and oil production by increasing oil production and volumetric efficiency. By reducing free gas at the pump intake, operating conditions are improved allowing considerable savings in power, downhole pump sizes (smaller pumps to achieve same liquid rate) and rig services due to extended run life that can be achieved by improvement of pumping conditions.

The downhole gas separator apparatus comprises an internal element and an external element, and is disposed within the production casing below the pump intake. Two eccentric annuli are formed: (1) one annulus is formed between the external element and the production casing, where the external element is placed in an offset position related to the production casing (the “first eccentric annulus”) and (2) one annulus is formed between the internal element and the external element, where the internal element is placed in an offset position related to the external element (the “second eccentric annulus”). A sealing element at the bottom end of the external element prevents well fluid from entering the downhole gas separator apparatus from the production casing. The downhole gas separator apparatus comprises a plurality of intake ports disposed at the top end leading into the second eccentric annulus. The internal element and the outer element are disposed such that well fluid flows from the second eccentric annulus into the internal element at the bottom of the apparatus.

The downhole gas separator apparatus is installed below the pump intake (and pump centralizer). The first eccentric annulus and the second eccentric annulus together enhance gas-liquid separation based on density differences of oil and gas as well as changes of flow direction of well fluid. The dual eccentric annulus design creates preferential paths for liquid and gas flow.

Well fluid is forced to flow upward through first eccentric annulus between the production casing and the external element. The flow of well fluid through the first eccentric annulus promotes separation of oil and gas and helps in segregating gas-rich multiphase flow to the top of the production casing. As the well fluid flows upward it reaches the intake ports at the top of the external element of the downhole gas separator apparatus, whereupon it changes its direction orthogonal to the previous flow direction to flow downward through the second eccentric annulus. Gas is separated from oil as the liquid-rich multiphase well fluid as it flows downward, which gas is released and flows upward through the production casing to the surface. The liquid-rich multiphase well fluid travels downward through the second eccentric annulus until it reaches the bottom of the downhole gas separator apparatus, whereupon it switches flow direction again and moves upward into and the internal element through the internal element intake ports. This liquid-rich multiphase flow is directed to the pump intake.

The downhole gas separator apparatus can be manufactured using standard OCTG tubular, making it compatible with standard tubing tongues and tools. Accordingly, no special tools such as xover, elevators or fishing tools are required for installation or removal. Due to its dual eccentric annulus design, the apparatus provides higher area at the top of the annulus, and the external and internal annuli open to flow are well balanced to achieve optimal flowing well fluid velocities to improve gas-oil separation based on natural segregation and gas rise and coalescence. Intake (and gas outlet ports) are dimensioned to accommodate fluid shear and low pressure drop at high rates or high viscosity, making the apparatus suitable for extra-heavy oil applications. Elements can be disposed in the second eccentric annulus to create turbulence and wavy fluid behavior to increase contact between descending mixture and ascending gas bubbles. The seal element at the bottom of the apparatus helps prevent clogging of the inner element of the apparatus by solids in the well fluid. In the event of clogging, reverse flow can be achieved to flush the inner element.

Conventional separators based on flow segregation are conceived for liquid rates not higher than 500 BPD in light to medium crude (low viscosity) and 100 to 300 BPD in heavy crude application (with considerably higher pressure drop). The downhole gas separator apparatus can accommodate gas rates higher than 5 million SCFD and higher than 1000 BPD (field proven). The apparatus can be adapted to virtually any well condition by scaling its size (length, OD, ID) according to well configuration and fluid properties. Pre-existing equipment can be arranged in tandem arrays to further improve its operating range. Apparatus reconfiguration is based mainly in flow areas, velocity profiles and flow properties to achieve the optimal scenario to allow gas bubbles to rise thru the well fluid and be released through the two annuli. This apparatus further can accommodate the option to inject H2S scavengers, diluent, viscosity reductors and other chemicals to the inner part of the apparatus through (if required) an optional capillary tube port. This apparatus does not require any particular operation pressure and unlike traditional poor boy, cups type or other separators, this apparatus can be used with well fluid comprising viscous crude oil with high angles (>30°) providing low flow resistance, allowing a permanent liquid bed to be disposed on top of the intake ports which prevents free gas from easily entering into the pump intake from the inner element. This apparatus can also be combined with annulus back pressure systems.

Since most of the gas is vented to the annulus before reaching the PCP/SRP/ESP intake, liquid-rich well fluid is delivered to the pump which translates into benefits as:

• • Increased volumetric efficiency
  • Reduction of equipment sizing as volumetric efficiency increases
  • Less premature failures due to hysteresis or high gas volume at pump intake
  • Prevents gas lock and/or intermittent flow thru tubing.
  • Able to deal with same liquid rate at considerably lower RPM.
  • Reduction of pumping RPM/SPM results in less friction, less tubing wear and less system failures.
  • Pumping efficiency and power consumption (kw/barrel) increases considerably.
  • PCP size can be reduced by 30-50% maintaining the same liquid rate in high GOR conditions.
  • For the same PCP/SRP size more liquid can be produced at same or lower RPM/SPM.
  • The design, does not require any special tools for installation or removal.

The downhole oil-gas separator of the invention was originally designed for use with Orinoco Oil Belt (OOB) heavy crude. However, the scalable design of the invention allows the apparatus to be reconfigured to match well conditions.

• • Designed for liquid rates between 40-1500 BPD and gas rates 0.1-5.5 Million SCF/D (Field Tested)
  • Gas Lock and/or flow intermittence is minimized or eliminated (depending on well conditions)
  • Compatible with annular back pressure systems as SIAP/MAXIPROD/AWPA/ETC.
  • Filtering (debris) and tubing integrity (leak detection) testing capabilities can be added.

This apparatus has been installed and evaluated so far in more than 30 wells.

The average field properties where the apparatus has been installed and evaluated are the following:

API                      17 Average/14 (Min)/19 (Max)
GOR                      120-5500 SCF/STB
Liquid Rate per well     40-3000 STB/Day
PCP Seating Depth        3600-3900 FT (MD)
PCP Seating Dep          3400-3600 FT (TVD)
Artificial Lift Methods  100% PCP
Tubing String            5-½ LTC J55 or 4-½ EUE N80
Sucker Rod String        1¼″ or 1½″ (1 9/16″ pin size)
Number of Active Wells   85 Wells
Number of Active Pads    15 Pads
Average Field Production 36

Pressures:

During field test wells with downhole sensor and downhole separator (DHS) were kept under constant observation. FIGS. 4A-B depict Average Pump Intake (PIP) and Pump Discharge Pressure (PDP) before (where available) and after running with the downhole gas-oil separator apparatus of the invention installed. Several wells were sent to workover before PCP failure to run in PCP Separator. Two wells with low PCP run time had the PCP's reinstalled to determine what the behavior is before and after running in the apparatus of the invention (having the same pump). Real Time Monitoring reported thru tubing improved liquid gradient higher PDP) was observed in all the wells with DHS.

Field Test

Production Rate:

FIGS. 5A-D provide a comparison of liquid rate before (stable conditions) and after installation of the apparatus of the invention (optimized point) was carried out. Field test reports overall production increased in most wells evaluated so far since January 2013. Most of the wells increased liquid rates after installing and optimizing the system.

Some intermittent and low PI Wells (before installing) did not reflect additional oil rate but a stable flow condition (gas free) was observed in all of them with no intermittent flow that previously was the “normal condition” for such wells. Same liquid rate was achieved with less RPM or more liquid rates with same RPM (or lower). So far additional crude being produced due to gas separator installation represent a considerable amount of the 2013 production generation campaign for this field.

A special production test was run in two wells with very similar completion, flowing conditions and parameters. The test consisted in measuring total liquid rate and total gas rate first. Thereafter only thru tubing gas rate and total liquid rate was sampled (annulus diverted to gas gathering line maintaining same Casing Head Pressure).

Natural separation (NO SEPARATOR INSTALLED) was reported to be 76% approximately considering thru tubing gas rate divided by total gas rate for selected well with no separator. The well WITH SEPARATOR INSTALLED reported 95% of gas separation under same conditions. Both tests for both wells were taken the same day on the same PAD with the same well tester.

Natural and Artificial Separation Efficiency

A special production test was run in two wells with very similar completion, flowing conditions and parameters. The test consisted in measuring total liquid rate and total gas rate first. Thereafter only through tubing gas rate and total liquid rate was sampled (annulus diverted to gas gathering line maintaining same Casing Head Pressure).

As seen in FIGS. 6A-B, natural separation (NO SEPARATOR INSTALLED) was reported to be 76% approximately considering thru tubing gas rate divided by total gas rate for selected well with no separator. The well WITH SEPARATOR INSTALLED reported 95% of gas separation under same conditions. Both tests for both wells were taken the same day on the same PAD with the same well tester.

FIGS. 7A-7G depict views of the downhole gas separator apparatus according to one embodiment of the invention. The downhole gas separator apparatus comprises an external element 710 (FIG. 7A) and an internal element 720 (FIG. 7B). External element 710 comprises a plurality of second eccentric annulus intake ports 730 dispersed around the circumference toward the top of external element 710. Top end 750 of external element 710 is disposed proximal to the pump intake (not shown) and bottom end 760 distal from the pump intake. Internal element 720 comprises a plurality of turbulence devices 740 that create turbulence and wavy fluid behavior to increase contact between descending mixture and ascending gas bubbles. The design of devices 740 can vary according to the decision of the designer. Top end 770 of internal element 720 is disposed proximal to top end 750 of external element 710 and bottom end 780 of internal element 720 is disposed proximal to bottom end 760 of external element 710. Internal element 720 further comprises internal element intake ports 790 disposed at bottom end 780.

FIG. 7C depicts internal element 720 inserted in interior cavity 715 of external element 710 thus forming eccentric annulus 820 (the “second eccentric annulus” as described further in FIGS. 8A-B). Top end 750 of external element 710 is disposed proximal to the pump intake (not shown) and bottom end 760 distal from the pump intake. Top end 770 of internal element 720 is disposed top end 750 of external element 710 and bottom end 780 of internal element 720 is disposed proximal bottom end 760 of external element 710. Internal element 720 further comprises internal element intake ports 790 disposed at bottom end 780. The downhole gas separator apparatus further comprises a sealing element 765 at the bottom end 760 of the external element 710 that prevents well fluid from entering the apparatus from the production casing (not shown).

As seen in FIG. 7C, internal element 720 and external element 710 are disposed such that well fluid flows from the second eccentric annulus into interior cavity 725 of internal element 720 at one end 715 of the external element 720.

FIG. 7D depicts a close up view of top end 750 of external element 710 showing second eccentric annulus intake ports 730.

FIG. 7E depicts a close up view of the mid-section of internal element 720 showing turbulence devices 740.

FIG. 7F depicts a cross-sectional view of the top end 750 of internal element 720 inserted into cavity 715 of external element 710, showing second eccentric annulus intake ports 730; second eccentric annulus 820; and interior cavity 725 of internal element 720.

FIG. 7G depicts a cross-sectional view of the bottom end 760 of internal element 720 inserted into cavity 715 of external element 710, showing second eccentric annulus intake ports 730; internal element intake ports 790; second eccentric annulus 820; and interior cavity 725 of internal element 720.

FIG. 8 depicts an end view of the downhole gas separator apparatus 700 of FIGS. 7A-7G according to one embodiment of the invention showing the two eccentric annuli that are formed. The first eccentric annulus 810 is formed between the external element 710 and the production casing 830, where the external element 710 is placed in an offset position related to the production casing 720. The second eccentric annulus 820 is formed between the internal element 720 and the external element 710, where the internal element 720 is placed in an offset position related to the external element 710.

In the foregoing description, the invention has been described with reference to specific exemplary embodiments thereof. It will be apparent to those skilled in the art that a person understanding this invention may conceive of changes or other embodiments or variations, which utilize the principles of this invention without departing from the broader spirit and scope of the invention. The specification and drawings are, therefore, to be regarded in an illustrative rather than a restrictive sense.

Claims

1. A downhole gas separator apparatus comprising: wherein the external element is disposed within the interior of a production casing with the external element top end below the intake of a pump that forms part of an artificial lift pumping system of a producing oil well, wherein the external element outer wall and the inner wall of the production casing form a first eccentric annulus; wherein the internal element is disposed within the external element interior cavity, wherein the internal cavity outer wall and the external cavity inner wall form a second eccentric annulus, wherein the internal element top end is connected to the pump intake.

an external element comprising an external element outer wall, an external element inner wall, an external element top end, an external element bottom end, an external element interior cavity, a seal that prevents the flow of fluid into the external element interior cavity from the external element bottom end and a plurality of external element intake ports around the circumference of the external element substantially toward the top end of the external element; and

an internal element comprising an internal element outer wall, an internal element inner wall, an internal element top end, an internal element bottom end, an internal element interior cavity and a plurality of internal element intake ports around the circumference of the internal element substantially toward the bottom end of the internal element;

2. The downhole gas separator apparatus of claim 1, wherein the first eccentric annulus is placed in an offset position related to the production casing.

3. The downhole gas separator apparatus of claim 2, wherein the internal element is placed in an offset position in relation to the external element to form the second eccentric annulus.

4. The downhole gas separator apparatus of claim 1, wherein the internal element exterior wall comprises a plurality of elements that create turbulence in a fluid that flows through the second eccentric annulus.

5. The downhole gas separator apparatus of claim 1, wherein the pump comprises a sucker rod pump, a progressing cavity pump or an electric submersible pump.

6. The downhole gas separator apparatus of claim 1, wherein the producing oil well comprises a high angle well, a horizontal well, a low angle well or a vertical well. The dimensions can vary to be used for extra heavy oil as well as light crude oil

7. A method of separating gas and liquid flowing upward through the production casing of a producing oil well, comprising:

disposing a downhole gas separator apparatus into the interior of the production casing of a producing oil well below the intake of a pump that forms part of an artificial lift pumping system of the producing oil well, wherein the downhole gas separator apparatus comprises: an external element comprising an external element outer wall, an external element inner wall, an external element top end, an external element bottom end, an external element interior cavity, a seal that prevents the flow of fluid into the external element interior cavity from the external element bottom end and a plurality of external element intake ports around the circumference of the external element substantially toward the top end of the external element; and an internal element comprising an internal element outer wall, an internal element inner wall, an internal element top end, an internal element bottom end, an internal element interior cavity and a plurality of internal element intake ports around the circumference of the internal element substantially toward the bottom end of the internal element;

wherein the external element outer wall and the inner wall of the production casing form a first eccentric annulus;

wherein the internal element is disposed within the external element interior cavity,

wherein the internal cavity outer wall and the external cavity inner wall form a second eccentric annulus,

wherein the internal element top end is connected to the pump intake;

flowing a multiphase fluid comprising gas and oil upward through the first eccentric annulus between the inner wall of the production casing and the external element outer wall, during which time gas separates from the multiphase fluid;

diverting the flowing multiphase fluid into the second eccentric annulus through the external element intake ports;

diverting the flowing multiphase fluid into the internal element interior cavity through the internal element intake ports; and

feeding the flowing multiphase fluid into the pump intake at the internal element top end;

wherein gas that separates from the multiphase fluid flows upward through the production casing and is released;

wherein the multiphase fluid that reaches the pump intake comprises less gas than the multiphase fluid that entered the first eccentric annulus.

8. The method of claim 7, wherein the first eccentric annulus is placed in an offset position related to the production casing.

9. The method of claim 8, wherein the internal element is placed in an offset position in relation to the external element to form the second eccentric annulus.

10. The method of claim 7, wherein the internal element exterior wall comprises a plurality of elements that create turbulence in a fluid that flows through the second eccentric annulus.

11. The method of claim 7, wherein the pump comprises a sucker rod pump, a progressing cavity pump or an electric submersible pump.

12. The method of claim 7, wherein the producing oil well comprises a high angle well, a horizontal well, a low angle well or a vertical well.

13. The method of claim 7, wherein the multiphase fluid comprises extra heavy oil.

14. The method of claim 7, wherein the multiphase fluid comprises light crude oil.