PRECONDITIONING FLOW TO AN ELECTRICAL SUBMERSIBLE PUMP

Abstract

A system and method of producing fluid from a wellbore by pressurizing the fluid and then directing the pressurized fluid to a centrifugal pump. Pressurizing the fluid compresses gas or vapor within the fluid, thereby decreasing the volume ratio of the gas or vapor within the fluid, which in turn increases operating efficiency of the centrifugal pump. A positive displacement pump, such as a gerotor pump, is used for pressurizing the fluid prior to sending it to the centrifugal pump.

Description

BACKGROUND OF THE INVENTION

1. Field of Invention

The present disclosure is directed to a system for artificially lifting fluid from a wellbore. More specifically, the present disclosure concerns pumping fluid from the wellbore with an electrical submersible pump (“ESP”), and pressurizing the fluid upstream of the ESP with a positive displacement pump.

2. Description of Prior Art

Electrical submersible pumping (“ESP”) systems are deployed in some hydrocarbon producing wellbores to provide artificial lift to deliver fluids to the surface. ESP systems are also sometimes used to transfer fluids from a wellsite to other equipment or facility for further processing. The fluids are usually made up of hydrocarbon and water. When installed, a typical ESP system is suspended in the wellbore at the bottom of a string of production tubing. Sometimes, ESP systems are inserted directly into the production tubing. In addition to a pump, ESP systems usually include an electrically powered motor for driving the pump, and a seal section for equalizing pressure in the motor to ambient. Centrifugal pumps usually have a stack of alternating impellers and diffusers coaxially arranged in a housing along a length of the pump. The impellers each attach to a shaft that couples to the motor; rotating the shaft and impellers forces fluid through passages that helically wind through the stack of impellers and diffusers. The produced fluid is pressurized as it is forced through the helical path in the pump. The pressurized fluid is discharged from the pump and into the production tubing, where the fluid is then conveyed to surface for distribution downstream for processing.

On occasion, the fluid being pressurized by ESP systems has some percentage of gas or vapor entrained therein. However, with increasing gas or vapor content in the downhole fluid, ESP systems generally produce less head and become less efficient. Lowering pump head results in reduced pump discharge pressure and a drop in fluid being pumped by the ESP system. Additionally, a high amount of gas or liquid in the produced fluid increases fluid pressure drop when flowing through the tubing, which further contributes to a reduction in the produced fluid flow rate. Moreover, ESP systems are operationally limited by how much gas or vapor can be present in the downhole fluid being pressurized; and can experience vapor lock when the percentage of gas or vapor exceeds a threshold value. Occasionally, the upper limit of gas or vapor percentage in the produced fluid can approach around 30% by weight.

Some of the conventional methods of tackling ESP gas problems include the use of gas separators, gas handlers, and helico-axial multiphase pumps. Some gas separators remove gas from the gas-liquid mixture into the tubing-casing annulus by centrifugal means, thereby reducing the amount of gas or vapor that actually enters the ESP system. Devices known as advanced gas handlers use centrifugal action to compress the gas before feeding the entire fluid into the ESP system. Helico-axial multiphase pumps have specially designed rotating impellers and diffusers that homogenize the gas and liquid phases prior to directing the coalesced gas-liquid mixture to the ESP system for pressurization. A limitation of conventional gas-handling systems is a high incremental cost to the total cost of the ESP string; and some systems have many internal components with moving parts, resulting in a complex system.

SUMMARY OF THE INVENTION

Disclosed herein are examples of a method and system for artificially lifting fluid from a wellbore where the fluid is pre-pressurized upstream of a pump. In one example, disclosed is an electrical submersible pumping (“ESP”) system disposable in a wellbore that includes a gerotor pump with an inlet in communication with fluid in the wellbore, and an exit through which fluid pressurized in the gerotor pump is directed away from the gerotor pump. Also included with the ESP system is a centrifugal pump having an inlet in fluid communication with the exit of the gerotor pump, and a discharge in which fluid pressurized in the centrifugal pump is directed away from the centrifugal pump. Production tubing is included that is in fluid communication with the discharge of the centrifugal pump. In one example the gerotor pump includes a body, an idler in the body having an axis, planar upper and lower surfaces, a curved outer side surface, and a chamber having profiled sidewalls that lobes at designated locations along a circumference of the chamber, and a rotor disposed in the chamber and having an axis, an outer circumference profiled to define gears that project radially outward, so that when the rotor is rotated about its axis, the gears contact the sidewall of the chamber at various locations to define sealing interfaces and define high and low pressure sides in the chamber. In one example, the rotor has n gears and the idler has n+1 lobes. In one embodiment, the centrifugal pump is equipped with a series of diffusers, impellers disposed between adjacent diffusers, and a flow path extending through the diffusers and impellers, so that when the impellers are rotated, fluid is urged through the flow path and is pressurized with distance through the flow path. In one example, an end of the production tubing distal from the centrifugal pump couples with a wellhead assembly disposed at an opening of the wellbore. The fluid being pressurized by the gerotor pump can include a fluid having phases of liquid and gas or vapor. The ESP system optionally includes a motor section mechanically coupled with the gerotor pump and the centrifugal pump, a seal section in pressure communication with the motor so that a pressure in the motor section remains at substantially ambient pressure, and a monitoring sub coupled with the motor section. The centrifugal pump operates at an increased efficiency when pressurizing fluid from the discharge of the gerotor pump than when pressurizing fluid received from the wellbore.

Also disclosed herein is an example of an electrical submersible pumping (“ESP”) system disposable in a wellbore that is made up of a positive displacement pump with a suction port in communication with fluid in the wellbore, a pressurization chamber in communication with the inlet, and a discharge port in communication with the pressurization chamber and that is at a pressure that is greater than a pressure of the suction port of the positive displacement pump; and a centrifugal pump having a suction port in communication with the discharge of the positive displacement pump and a discharge port that is at a pressure greater than a pressure of the suction port of the centrifugal pump. The ESP system can further have production tubing with an end in communication with the discharge port of the centrifugal pump, and a distal end coupled to a wellhead assembly disposed at an opening of the wellbore. In one alternative, the positive displacement pump is a gerotor pump. The ESP system can include a motor mechanically coupled to the positive displacement pump and to the centrifugal pump, and a seal section in pressure communication with the motor, so that pressure in the motor is maintained substantially at ambient pressure when the motor is in the wellbore. When fluid in the wellbore includes liquid and vapor or gas, a ratio of vapor or gas volume to liquid volume of the fluid is greater at the suction port of the positive displacement pump than at the suction port of the centrifugal pump, thereby increasing the operating efficiency of the centrifugal pump.

Also disclosed herein is a method of pumping fluid produced from within a wellbore, where the method includes pressurizing an amount of the fluid having phases of liquid and gas or vapor, so that the gas or vapor in the fluid is compressed to thereby reduce a ratio of gas or vapor volume to liquid volume, directing the pressurized amount of the fluid to a centrifugal pump, and further pressurizing the pressurized amount of the fluid with the centrifugal pump. The step of pressurizing the amount of fluid having phases of liquid and gas or vapor can be performed using a positive displacement pump. Optionally, the positive displacement pump is a gerotor pump. The fluid further pressurized by the centrifugal pump can be directed to a wellhead assembly disposed at an opening of the wellbore. Both the positive displacement pump and the centrifugal pump can be powered with a single motor.

BRIEF DESCRIPTION OF DRAWINGS

Some of the features and benefits of the present invention having been stated, others will become apparent as the description proceeds when taken in conjunction with the accompanying drawings, in which:

FIG. 1 is a partial sectional view of an example of an ESP system disposed in a wellbore.

FIGS. 2A and 2B are sectional views of an example of a portion of the ESP system of Figure 1 having a positive displacement pump in combination with an centrifugal pump.

FIG. 3 is a sectional view of an alternate example of positive displacement pump of Figure 2.

While the invention will be described in connection with the preferred embodiments, it will be understood that it is not intended to limit the invention to that embodiment. On the contrary, it is intended to cover all alternatives, modifications, and equivalents, as may be included within the spirit and scope of the invention as defined by the appended claims.

DETAILED DESCRIPTION OF INVENTION

The method and system of the present disclosure will now be described more fully hereinafter with reference to the accompanying drawings in which embodiments are shown. The method and system of the present disclosure may be in many different forms and should not be construed as limited to the illustrated embodiments set forth herein; rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey its scope to those skilled in the art. Like numbers refer to like elements throughout. In an embodiment, usage of the term “about” includes +/−5% of the cited magnitude. In an embodiment, usage of the term “substantially” includes +/−5% of the cited magnitude.

It is to be further understood that the scope of the present disclosure is not limited to the exact details of construction, operation, exact materials, or embodiments shown and described, as modifications and equivalents will be apparent to one skilled in the art. In the drawings and specification, there have been disclosed illustrative embodiments and, although specific terms are employed, they are used in a generic and descriptive sense only and not for the purpose of limitation.

One example of an electrical submersible pump (“ESP”) system 10 is shown in a partial side sectional view in FIG. 1. The ESP system 10 is illustrated disposed in a wellbore 12 which intersects a subterranean formation 14. Tubular casing 16 lines the wellbore 12 and tubing 18 is inserted coaxially within the casing 16. The ESP system 10 includes a motor 20, a seal system 22 mounted on an upper end of motor 20, wherein seal system 22 equalizes pressure within motor 20 to ambient. Also included with ESP system 10 is a positive displacement pump 24 mounted on an end of seal system 22 distal from motor 20. Further in the example of FIG. 1, a centrifugal pump 26 is shown mounted on an end of positive displacement pump 24 distal from seal system 22. Optionally, a monitoring sub 28 is included with ESP system 10, where monitoring sub may include sensors for sensing one or more of temperature, pressure, and vibration within wellbore 12. Alternatively, monitoring sub 28 may include a controller for sending and receiving control signals for controlling operations of ESP system 10.

Perforations 30 are shown projecting radially outward from wellbore 12 through casing 16, and into formation 14. Perforations 30 provide a flow path for fluid entrained in the formation to make its way into the wellbore 12. Further in this example, openings 32 are formed through sidewalls of tubing 18 to allow wellbore fluid F produced from formation 14 to flow into tubing 18. After being directed into the tubing 18, the fluid F can be pressurized by artificial lift by ESP system 10. Optionally, a packer 34 is shown formed in the annulus 36 between tubing 18 and casing 16, and is used for directing the flow of fluid F into tubing 18. Fluid F enters into ESP system 10 via an inlet 38 formed on positive displacement pump 24. From positive displacement pump 24, fluid F can then be directed to a centrifugal pump 26. A string of production tubing 40 is shown coupled to a discharge end of centrifugal pump 26. Around production tubing 40 a packer 42 is disposed and which forms a flow barrier in the annular space 44 between ESP system 10 and the inner surface of tubing 18. Packer 42 thus forces fluid F flowing upwards within tubing 18 to make its way into inlet 38.

Still referring to FIG. 1, further illustrated is that an upper end of production tubing 40 terminates within a wellhead assembly 46 depicted positioned at an opening of wellbore 12 on surface 47. Piping within wellhead assembly 46 defines a production circuit 48 for selectively directing the fluid F within production tubing 40 to designated destinations. In one example, fluid F within production circuit 48 is directed to a transfer line 50 shown having a distal end terminating at a processing facility 52. Examples of processing facilities 52 include refineries, olefins plants, and other facilities that process the fluid F for transport. Examples of processing for transport includes removing constituents from the fluid F such as water, sulfur, and other undesirable elements. Optionally, valves 54 are provided within production circuit 40 and transfer line 50 for selectively directing the flow of fluid F therethrough.

Referring now to FIGS. 2A and 2B, shown in a side sectional view is one example of an embodiment of the positive displacement pump 24A coupled with centrifugal pump 26A. As shown, included within positive displacement pump 24A is a housing 56 which defines a cavity 58 therein. A piston 60 is disposed within cavity 58, and as shown by the double-headed arrow reciprocates axially in the cavity 58. A piston rod 62 connects to an end of piston 60, and selectively provides a motive force to reciprocate piston 60 within cavity 58. A compression chamber 64 is defined within cavity 58 on a side of piston 60 opposite from piston rod 62. In the illustrated example, fluid F from within wellbore 12 (FIG. 1) is within compression chamber 64. Fluid F of FIGS. 2A and 2B includes a two-phase mixture of liquid L and vapor V, where vapor V can include gas, vapor, or a mixture of both. As shown, fluid F is directed into compression chamber 64 via an inlet line 66, which has a distal end connecting to inlet 38 illustrated disposed on an outer surface of positive displacement pump 24A. Optionally, inlet line 66 can be equipped with a check valve 68, so that during a compression cycle, fluid F cannot escape from cavity 58 back into inlet line 66. In an alternative, fluid F can have up to around 75% gas by volume or by mass, and examples exist wherein fluid F is around 100% vapor.

Depicted in FIG. 2B is the positive displacement pump 24A operating during a compression phase; wherein piston 60 is moved into the portion of cavity 58 occupied by fluid F thereby compressing fluid F. Pressurizing fluid F with pump 24A compresses the vapor V in the fluid F, thereby reducing the ratio of gas or vapor volume with respect to liquid volume of the fluid F. The compressed and pressurized fluid F is directed to centrifugal pump 26A via discharge line 70 shown having one end coupled with a discharge 71 on the outer housing of positive displacement pump 24A. In the examples of FIGS. 2A and 2B, centrifugal pump 26A includes a main body 72 through which a fluid flow path P helically courses from an inlet space 74 to an outlet space 76. Inlet and outlet spaces 74, 76 and pump body 72 are encased within a pump housing 78. Impellers 80 are shown disposed within pump body 72 and are intersected by path P. Diffusers 82 are sequentially spaced between impellers 80 and are also intersected by path P. A shaft 84 is shown that connects to the impellers 80, rotating shaft 84 correspondingly rotates impellers 80, that in turn exert a force on the fluid F that urges fluid F through the path P and pressurizes fluid F. An advantage of pressurizing the fluid F before directing it to the centrifugal pump 26A is that the gas or vapor volume in the fluid F is decreased, which increases the centrifugal pump 26A operating efficiency. When feeding “prepressurized” fluid F having a reduced gas or vapor volume ratio to the centrifugal pump 26A, the resulting pressure differential imparted on the fluid F (pump head) by the centrifugal pump 26A is greater than when fluid F from the wellbore 12 (FIG. 1) is fed directly to the centrifugal pump 26A. Further illustrated in the example of FIG. 2B is that the pressurized fluid F exits path P into outlet space 76, and then is routed into production tubing 44 for transfer to the wellhead assembly 46 (FIG. 1).

FIG. 3 shows in a plan sectional view one example of the positive displacement pump 24B, wherein the pump 24B is the same as or similar to what is commonly referred to as a gerotor pump. As shown, pump 24B has an outer housing 56B and in which an idler 86 is disposed. Idler 86 of FIG. 3 has generally planar upper and lower surfaces, and a curved outer circumference. Idler 86 is selectively rotated about an axis A_X1 with respect to housing 56B and as illustrated by arrow A₁. Provided within idler 86 is a rotor 88 shown rotatable about axis A_X2, and in a direction illustrated by arrow A₂. Discharge line 70 intersects a side of housing 56B distal from inlet 66. Formed axially through a middle portion of idler 86 is an idler chamber 90 which has an undulating curved profile and which forms lobes 92_1-5 at spaced apart angular locations around axis A_X1. Although five lobes 92_1-5 are shown in FIG. 3, the number of lobes 92_1-5 is not limited to five, but instead can be any other number. The outer circumference of rotor 88 is also profiled but semi-complementary to the idler chamber 90. The curved undulating circumference of the rotor 88 defines gears 94_1-4 that selectively fit into the lobes 92_1-5. As shown, the number of gears 94_1-4 is one less than the number of lobes 92_1-5. An inner surface of chamber 90 forms a chamber wall 96.

Strategic formation and synchronization of the lobes 92_1-5 and gears 94_1-4 causes interaction between the outer periphery of the gears 94_1-4 and various locations along chamber wall 96. Shown in the example of FIG. 3, gear 94₂ is in sealing contact with a location on the wall 96 proximate lobe 92₂, and gear 94₃ is in sealing contact with a location on the wall 96 proximate lobe 92₃. Further shown is that gear 94₄ is in sealing contact with a location on the wall 96 proximate lobe 92₄. The sealing contact between gears 94₂, 94₃ and wall 96 forms an enclosed space in idler chamber 90 to define a lower pressure side 98. Similarly the sealing contact between gears 94₄, 94₃ and wall 96 forms another enclosed space in idler chamber 90 to define a higher pressure side 100. Lower pressure side 98 is in fluid communication with inlet line 66 and higher pressure side 100 is in fluid communication with discharge line 70. Continuous rotation of both the idler 86 and rotor 88 causes the fluid initially trapped within the lower pressure side 98 to be compressed between the gears 94_1-4 and sidewall 96 thereby pressurizing the fluid F prior to being discharged through the discharge line 70. One advantage of the gerotor pump illustrated in FIG. 3, is that multiple phased fluids, i.e., those having a mixture of liquid and vapor and/or gas, can be efficiently pressurized irrespective of how compressible is the fluid F. As is known, the presence of gas, vapor, or both in the fluid F can increase compressibility of the fluid F. Accordingly, significant advantages are realized by incorporating the gerotor pump assembly with a centrifugal pump to increase the efficiency of the centrifugal pump. In one example, during gerotor rotation, due to the difference between the gears 94_1-4 and lobes 92_1-5, enlarging and decreasing cavities are created, such as illustrated by the higher pressure and lower pressure sides 98, 100. As the cavities enlarge and decrease, fluid suction and compression occur continuously, and as the gas mixture is compressed by the gerotor the gas volume is reduced considerably due to compressibility effects of the gas or vapor. This results in a more homogenized mixture as it is fed to the centrifugal pump 26 (FIG. 1). Embodiments exist where the gerotor pump includes two or more stages, and is powered by motor 20.

The present invention described herein, therefore, is well adapted to carry out the objects and attain the ends and advantages mentioned, as well as others inherent therein. While a presently preferred embodiment of the invention has been given for purposes of disclosure, numerous changes exist in the details of procedures for accomplishing the desired results. Inlet line 66 as shown is a single conduit to pumps 24A, 24B (FIGS. 2A, 2B, and 3); in an example, multiple lines are provided to the pumps 24A, 24B, and the pumps 24A, 24B have multiple ports. In an alternate embodiment, the high pressure side of the pumps 24A, 24B communicates directly into a discharge chamber (not shown), which directly feeds into the suction of centrifugal pump 26A, 26B; in this alternate embodiment discharge line 70 is not included. Optionally, a progressive cavity pump can be used as a pre-conditioning device, in lieu of a gerotor pump, and for conditioning fluid upstream of a centrifugal pump. These and other similar modifications will readily suggest themselves to those skilled in the art, and are intended to be encompassed within the spirit of the present invention disclosed herein and the scope of the appended claims.

Claims

1. An electrical submersible pumping (“ESP”) system disposable in a wellbore comprising:

a gerotor pump having, an inlet in communication with fluid in the wellbore, and an exit through which fluid pressurized in the gerotor pump is directed away from the gerotor pump;

a centrifugal pump having, an inlet in fluid communication with the exit of the gerotor pump, and a discharge in which fluid pressurized in the centrifugal pump is directed away from the centrifugal pump; and

production tubing in fluid communication with the discharge of the centrifugal pump.

2. The ESP system of claim 1, wherein the gerotor pump comprises

a body,

an idler in the body having an axis, planar upper and lower surfaces, a curved outer side surface, and a chamber having profiled sidewalls that lobes at designated locations along a circumference of the chamber, and

a rotor disposed in the chamber and having an axis, an outer circumference profiled to define gears that project radially outward, so that when the rotor is rotated about its axis, the gears contact the sidewall of the chamber at various locations to define sealing interfaces and define high and low pressure sides in the chamber.

3. The ESP system of claim 2, wherein the rotor comprises n gears, and the idler comprises n+1 lobes.

4. The ESP system of claim 1, wherein the centrifugal pump comprises a series of diffusers, impellers disposed between adjacent diffusers, and a flow path extending through the diffusers and impellers, so that when the impellers are rotated, fluid is urged through the flow path and is pressurized with distance through the flow path.

5. The ESP system of claim 1, wherein an end of the production tubing distal from the centrifugal pump couples with a wellhead assembly disposed at an opening of the wellbore.

6. The ESP system of claim 1, wherein the fluid being pressurized by the gerotor pump comprises a fluid having phases of liquid and gas or vapor.

7. The ESP system of claim 1, further comprising a motor section mechanically coupled with the gerotor pump and the centrifugal pump, a seal section in pressure communication with the motor so that a pressure in the motor section remains at substantially ambient pressure, and a monitoring sub coupled with the motor section.

8. The ESP system of claim 1, wherein the centrifugal pump operates at an increased efficiency when pressurizing fluid from the discharge of the gerotor pump than when pressurizing fluid received from the wellbore.

9. An electrical submersible pumping (“ESP”) system disposable in a wellbore comprising:

a positive displacement pump with a suction port in communication with fluid in the wellbore, a pressurization chamber in communication with the inlet, and a discharge port in communication with the pressurization chamber and that is at a pressure that is greater than a pressure of the suction port of the positive displacement pump; and

a centrifugal pump having a suction port in communication with the discharge of the positive displacement pump and a discharge port that is at a pressure greater than a pressure of the suction port of the centrifugal pump.

10. The ESP system of claim 9, further comprising production tubing having an end in communication with the discharge port of the centrifugal pump and a distal end coupled to a wellhead assembly disposed at an opening of the wellbore.

11. The ESP system of claim 9, wherein the positive displacement pump comprises a gerotor pump.

12. The ESP system of claim 9, further comprising a motor mechanically coupled to the positive displacement pump and to the centrifugal pump, and a seal section in pressure communication with the motor, so that pressure in the motor is maintained substantially at ambient pressure when the motor is in the wellbore.

13. The ESP system of claim 9, wherein when fluid in the wellbore comprises liquid and vapor or gas, a ratio of vapor or gas volume to liquid volume of the fluid is greater at the suction port of the positive displacement pump that at the suction port of the centrifugal pump, thereby increasing the operating efficiency of the centrifugal pump.

14. A method of pumping fluid produced from within a wellbore comprising:

pressurizing an amount of the fluid having phases of liquid and gas or vapor, so that the gas or vapor in the fluid is compressed to thereby reduce a ratio of gas or vapor volume to liquid volume;

directing the pressurized amount of the fluid to a centrifugal pump; and

further pressurizing the pressurized amount of the fluid with the centrifugal pump.

15. The method of claim 14, wherein the step of pressurizing the amount of fluid having phases of liquid and gas or vapor is performed using a positive displacement pump.

16. The method of claim 15, wherein the positive displacement pump comprises a gerotor pump.

17. The method of claim 14, further comprising directing the fluid further pressurized by the centrifugal pump to a wellhead assembly disposed at an opening of the wellbore.

18. The method of claim 15, further comprising powering both the positive displacement pump and the centrifugal pump with a single motor.