US20210040824A1

US20210040824A1 - Downhole Artificial Lift Compressor for Improving Unconventional Oil and Gas Recovery

Info

Publication number: US20210040824A1
Application number: US16/836,492
Authority: US
Inventors: Jason Wilkes; Timothy C. Allison; Jerry Brady; Paulo Tubel
Original assignee: Tubel LLC
Current assignee: Tubel LLC
Priority date: 2019-04-01
Filing date: 2020-03-31
Publication date: 2021-02-11

Abstract

A high-speed downhole motor-driven artificial-lift gas compressor assembly comprising an aerodynamic, gas-bearing supported, multi-stage centrifugal compressor is deployed downhole to work with other components such as electric submersible pumps and separators disposed in a multizone reservoir. Water may be injected into an injection water zone and hydrocarbons allowed to escape from a hydrocarbon producing zone to the surface. Compressed gas may be introduced into an annulus between a casing and tubing and directed into an injection gas zone. In addition, gas being produced in the hydrocarbon producing zone may flow back through the annulus between the casing and tubing or through one or more water separators and/or gas separators into the high-speed downhole motor-driven artificial-lift gas compressor assembly and, once compressed, exit the high-speed downhole motor-driven artificial-lift gas compressor assembly and routed back to the injection gas zone. Thus, water and gas may be separated from the fluid flows and injected back downhole or, alternatively, water may be separated from the fluid flows and hydrocarbons such as oil and/or gas allowed to flow to the surface.

Description

RELATION TO OTHER APPLICATIONS

This application claims priority through U.S. Provisional Application 62/827,683 filed on Apr. 1, 2019.

BACKGROUND

Ultimate recovery from unconventional reservoirs still has a long way to come. Unconventional reservoirs are described as wells produced in low permeability (tight) formations composed as tight sands, carbonates, coal, and shale. Although tight gas and coal bed natural gas are valuable sources of energy, wells produced from low permeability shale formations (shale gas) promise over 1,744 trillion cubic feet (tcf) of recoverable gas, which comprises the majority of unconventional oil and gas reserves. Shale is a sedimentary rock comprised of consolidated clay-sized particles. These are deposited as mud along with organic matter such as plants, animal remains, and the like. The end result is a rock formation with a permeability of 0.01-0.00001 millidarcies. In its natural state, this permeability prevents the migration of oil and gas within the formation over periods less than geologic expanses of time, and was initially thought to be uneconomical to produce. With the advancement of horizontal drilling and multistage hydraulic fracturing in the late 1990s, shale oil and gas reservoirs became economical to produce.
As compared to conventional oil wells, many shale gas wells are characterized by a higher gas-oil ratio (GOR). Although there are some benefits to producing high GOR wells, there are also some drawbacks. In shale gas, the migration of oil through the rock fractures is primarily due to Poiseuille flow of the shale gas, i.e. pressure-driven flow of gas carries the oil when equalizing pressure. The pressure driving this flow is due to the natural pressure gradient that is created by “uncorking” the well at the surface, causing the less dense gas to evacuate the reservoir and rise up the well bore. When this process carries substantial liquid condensates, the specific gravity of the mixture in the well-bore creates a fluid column that pushes back on the reservoir; thus, we can define the bottom-hole flowing pressure (BHFP) as the pressure at the bottom of a flowing well, and the flowing tubing head pressure (FTHP) as the pressure at the surface of a flowing well.
While gas gathering systems at the surface often operate at 40-100 psi, wellhead compression can be employed to reduce this FTHP, also improving the minimum BHFP and ultimately reducing well abandonment pressure resulting in higher recovery and increased reserves. At the surface, a facility can at most draw down the well by pulling a vacuum from atmospheric pressure. While this technology can help reduce the abandonment pressure, the hydrostatic pressure gradient in the tubing is still tied to the specific gravity of the fluid in the tubing, and can only be altered moderately by well-head compression. Low gas pressures, temperatures, and velocities in the tubing will result in liquid dropout in the tubing, which can become suspended in the tubing. This liquid loading impedes production from the well and impact its economic viability, resulting in abandonment. Ultimately, the abandonment pressure depends greatly on GOR, water production, well depth, etc. and is likely several hundred psi.
In many cases, the specific gravity of the fluid in the tubing is decreased by implementing artificial gas lift. Artificial lift describes the process of compressing dry gas and inserting it into the annulus. The dry gas passes down the annulus and mixes with the oil in the production zone of the tubing. This reduces the density of the fluid in the tubing, thus decreasing the BHFP. This process requires access to gas, surface power and compression equipment, and can be quite costly. Ultimately, this process is quite effective, and is often economical for wells whose production has been impeded by poor natural tubing flow.
Another option that has been proposed to attain better control of high GOR production is downhole gas compression. This concept is not new but its application to unconventional oil-and-gas is still in the early stages of development. While promising, continued development of this technology is likely required for successful implementation in the field. Potential issues with a downhole application include multiple challenges associated with multiphase compression (variability in performance, reliability, and mechanical loads), low specific load capacity of magnetic bearings, changing aerodynamic requirements from reservoir maturation, overall system complexity and cost, and autonomous tool installation.

FIGURES

Various figures are included herein which illustrate aspects of embodiments of the disclosed inventions.

FIG. 1 is a schematic view of an embodiment of the system illustrating a gas lift separator, gas compressor, electric motor, and pump;

FIG. 2 is a schematic view of an embodiment of the invention illustrating a well installation with a downhole fluid separator, ESP, electric motor and compressor;

FIG. 3 is a view in partial perspective of an exemplary compressor and turbine assembly; and

FIG. 4 is a cutaway view illustrating interior components of an exemplary compressor assembly.

DESCRIPTION OF EXEMPLARY EMBODIMENTS

In a first embodiment, referring generally to FIG. 3, compressor assembly 1, which is also referred to as a high-speed downhole motor-driven artificial-lift gas compressor assembly, comprises housing 10; one or more aerodynamic, gas-bearing supported, multi-stage centrifugal compressors 11 comprising a predetermined set of gas film bearings 12 disposed at least partially within housing 10; and one or more high-speed electric motor drives 21 disposed at least partially within housing 10 and operatively connected to aerodynamically designed, gas-bearing supported, multi-stage centrifugal compressor 11. Compressor assembly 1 is typically designed to be deployed in casing or well 100 (FIG. 2) such as a conventional reservoir or an unconventional reservoir, e.g. a gas reservoir, a gas condensate reservoir, or an oil reservoir with associated gas production.
Housing 10 is further typically configured to be deployable within a 4.5 inch casing but the casing can be as small as around 3.5 inches or larger than 4.5 inches.
Referring additionally to FIG. 4, compressor 11 typically comprises between 2 and 4 compression stages (two are illustrated) operating at around 40000 to around 120000 rpm. In embodiments, compressor 1 comprises impeller 13 which comprises impeller tip 14, generally having a diameter of between around 65 mm to around 68 mm.
In embodiments aerodynamically designed, gas-bearing supported, multi-stage centrifugal compressor 11 comprises turbine 20 which may comprise a hybrid gas turbine comprising a heat transfer technology optimized for high cycle efficiency of recuperation, intercooling, or turbine blade cooling over a range of operating conditions typical of a load following demand at a compressor station.
In embodiments, compressor 11 is configured to be powered with a turbo charger which may be powered with a high-pressure gas source.
In certain embodiments, referring additionally to FIG. 2, high-speed downhole motor-driven artificial-lift gas compressor 11 is adapted to be used in conjunction with one or more downhole separators 32,33 and electrical submersible pump (ESP) 30 configured to reduce gas blockage or gas lockout and improve efficiency. In these embodiments, compressor 11 is further typically adapted to allow ESP 30 to be effectively operated in hydrocarbon well 100 with gas production through a predetermined set of ranges of gas/oil ratio.
Referring additionally to FIG. 4, the aerodynamic design is configured to ensure that compressor 11 achieves a predetermined set of head rise and flow characteristics desired at a target operating point. In embodiments, the aerodynamic design comprises a 0-D or a 1-D impeller design. In certain embodiments, the aerodynamic design further impeller 13, collector 14, diffuser 15, return channel 16, gas bearings 17, turbine nozzles 18, and turbine 19 which may comprise a radial, axial, or mixed flow geometry.
High speed electric motor 21 may comprise a plurality of 2-pole motors arranged in series.
Referring back to FIG. 2, in a typical system, tubing 103 is deployed within casing 101 and compressor assembly 1 deployed within tubing 103. Umbilical 104, which may comprise an electrical pathway or otherwise be an electrical cable, may be deployed to supply electrical power as needed to various components discussed herein above.
In the operation of exemplary methods, referring back to FIG. 2 and FIG. 3, lifting a hydrocarbon from a hydrocarbon well using compressor assembly 1 comprises deploying compressor assembly 1, which is as described above, in hydrocarbon well 100 such as in casing 101. Once deployed, high-speed downhole motor-driven artificial-lift gas compressor 11 is used to reduce pressure in reservoir 120 which is exposed to hydrocarbon well 100 and hydrocarbon allowed to flow from reservoir 120 to surface 130 at the reduced pressure.
In embodiments, electric submersible pump (ESP) 30 may be present or otherwise deployed in hydrocarbon well 100 and operatively connected to high-speed downhole motor-driven artificial-lift gas compressor 11. Once connected, ESP 30 may then be used to aid with recovery of hydrocarbons from hydrocarbon well 100.
In certain embodiments, high-speed downhole motor-driven artificial-lift gas compressor 11 may be reconfigured with one or more gas and water separators 32,33. In these embodiments, electric submersible pump (ESP) 30 may be deployed and used to inject water downhole into a water zone or waterflood zones to increase production and reserves. This can result in very little water being produced to the surface requiring water disposal. For areas where gas sales are not available, ESP 30 may be used to inject both water and gas downhole, which may reduce a need for surface water handling and disposal and gas injection.
As illustrated in FIG. 2, tubing 103 and/or casing 101 are exposed to reservoir 120. Multiple zones may exist in reservoir 120, e.g. injection gas zone 121, hydrocarbon producing zone 122 which may comprise oil and/or gas, injection water zone 123 which may comprise water, or the like, or a combination thereof. Water is injected into injection water zone 123 and hydrocarbons escape from hydrocarbon producing zone 122 back into casing 101 and/or tubing 103. Compressed gas may be introduced into an annulus between casing 101 and tubing 103 and directed into injection gas zone 121, such as through packer 105. In addition, gas being produced in hydrocarbon producing zone 122 may flow back through the annulus between casing 101 and tubing 103 or through water separator 33 and gas separator 32 into compressor assembly 1 such as at intake 106. Once compressed, gas can exit compressor assembly 1 and routed back to injection gas zone 121 such as via compressed gas ports 107. Desired hydrocarbons such as oil and/or gas can pass through interior 108 back to the surface. In this manner, water and gas may be separated from the fluid flows and injected back downhole or, alternatively, water may be separated from the fluid flows and hydrocarbons such as oil and/or gas allowed to flow to the surface. This may reduce a need for surface water handling and disposal and gas injection.
The foregoing disclosure and description of the inventions are illustrative and explanatory. Various changes in the size, shape, and materials, as well as in the details of the illustrative construction and/or an illustrative method may be made without departing from the spirit of the invention.

Claims

We claim:

1. A high-speed downhole motor-driven artificial-lift gas compressor assembly, comprising

a. a housing;

b. an aerodynamic, gas-bearing supported, multi-stage centrifugal compressor comprising a predetermined set of gas film bearings disposed at least partially within the housing, the aerodynamic design configured to ensure that the compressor achieves a predetermined set of head rise and flow characteristics desired at a target operating point; and

c. a high-speed electric motor drive disposed at least partially within the housing and operatively connected to the aerodynamically designed, gas-bearing supported, multi-stage centrifugal compressor.

2. The high-speed downhole motor-driven artificial-lift gas compressor assembly of claim 1, wherein the compressor comprises between 2 and 4 compression stages.

3. The high-speed downhole motor-driven artificial-lift gas compressor assembly of claim 1, wherein the compression stages operate at around 40000 to around 120000 rpm.

4. The high-speed downhole motor-driven artificial-lift gas compressor assembly of claim 1, wherein the compressor comprises an impeller.

5. The high-speed downhole motor-driven artificial-lift gas compressor assembly of claim 4, wherein the impeller comprises an impeller tip having a diameter of between around 65 mm to around 68 mm.

6. The high-speed downhole motor-driven artificial-lift gas compressor assembly of claim 1, wherein the aerodynamic design comprises a 0-D or a 1-D impeller design.

7. The high-speed downhole motor-driven artificial-lift gas compressor assembly of claim 1, wherein the aerodynamic design further comprises:

a. a diffuser geometry;

b. an inlet guide vane (IGV); and

c. a collector.

8. The high-speed downhole motor-driven artificial-lift gas compressor assembly of claim 1, wherein the housing is further configured to be deployable within a casing comprising an inner diameter of around 3.5 inches to around 4.5 inches.

9. The high-speed downhole motor-driven artificial-lift gas compressor assembly of claim 1, wherein the high-speed electric motor comprises a plurality of 2-pole motors arranged in series.

10. The high-speed downhole motor-driven artificial-lift gas compressor assembly of claim 1, wherein the aerodynamically designed, gas-bearing supported, multi-stage centrifugal compressor comprises a turbine.

11. The high-speed downhole motor-driven artificial-lift gas compressor assembly of claim 10, wherein the turbine comprises a hybrid gas turbine comprising a heat transfer technology optimized for high cycle efficiency of recuperation, intercooling, or turbine blade cooling over a range of operating conditions typical of a load following demand at a compressor station.

12. The high-speed downhole motor-driven artificial-lift gas compressor assembly of claim 1, wherein the compressor is configured to be powered with a turbo charger powered with a high-pressure gas source.

13. The high-speed downhole motor-driven artificial-lift gas compressor assembly of claim 1, wherein the reservoir comprises a conventional reservoir or an unconventional reservoir.

14. The high-speed downhole motor-driven artificial-lift gas compressor assembly of claim 1, wherein the reservoir comprises a gas reservoir, a gas condensate reservoir, or an oil reservoir with associated gas production.

15. The high-speed downhole motor-driven artificial-lift gas compressor assembly of claim 1, wherein the high-speed downhole motor-driven artificial-lift gas compressor is adapted to be used in conjunction with a downhole separator and an Electrical Submersible Pump (ESP) configured to reduce gas blockage or gas lockout and improve efficiency.

16. The high-speed downhole motor-driven artificial-lift gas compressor assembly of claim 15, wherein the high-speed downhole motor-driven artificial-lift gas compressor is further adapted to allow the ESP to be effectively operated in a hydrocarbon well with gas production through a predetermined set of ranges of gas oil ratio.

17. A method of lifting a hydrocarbon from a hydrocarbon well using a high-speed downhole motor-driven artificial-lift gas compressor assembly comprising a housing, an aerodynamic, gas-bearing supported, multi-stage centrifugal compressor comprising a predetermined set of gas film bearings disposed at least partially within the housing, the aerodynamic design configured to ensure that the compressor achieves a predetermined set of head rise and flow characteristics desired at a target operating point, and a high-speed electric motor drive disposed at least partially within the housing and operatively connected to the aerodynamically designed, gas-bearing supported, multi-stage centrifugal compressor, the method comprising:

a. deploying the high-speed downhole motor-driven artificial-lift gas compressor assembly in a hydrocarbon well;

b. using the high-speed downhole motor-driven artificial-lift gas compressor assembly to reduce pressure in a reservoir exposed to the hydrocarbon well; and

c. allowing the hydrocarbon to flow from the reservoir to the surface at the reduced pressure.

18. The method of claim 17, further, wherein the high-speed downhole motor-driven artificial-lift gas compressor assembly is deployed within a casing.

19. The method of claim 17, further comprising:

a. deploying an electric submersible pump (ESP) in the hydrocarbon well;

b. operatively connecting the ESP to the high-speed downhole motor-driven artificial-lift gas compressor assembly; and

c. using the ESP to aid with recovery of hydrocarbons from the hydrocarbon well.

20. The method of claim 19, further comprising:

a. reconfiguring the high-speed downhole motor-driven artificial-lift gas compressor assembly with a gas and water separator;

b. deploying an electric submersible pump (ESP);

c. using the ESP to inject water downhole into a water zone or waterflood zones to increase production and reserves.

21. The method of claim 19, further comprising:

a. for areas where gas sales are not available, reconfiguring the high-speed downhole motor-driven artificial-lift gas compressor assembly with a gas and water separator;

b. deploying an electric submersible pump (ESP);

c. using the ESP to inject both water and gas downhole.