Removing liquid by subsurface compression system

Patent metadata

Field	Value
Publication number	US-10352137-B1
Application number	US-201916241673-A
Country	US
Kind code	B1
Filing date	Jan 7, 2019
Priority date	Jan 7, 2019
Publication date	Jul 16, 2019
Grant date	Jul 16, 2019

Abstract

A gas flow velocity within a horizontal wellbore section is increased by a velocity string and a downhole-type compressor. A pressure within the horizontal wellbore section is decreased by a downhole-type compressor located within a vertical wellbore section fluidically connected to the horizontal wellbore section. Liquid build-up within the horizontal wellbore section is decreased in response to the increased gas flow velocity and the decreased pressure.

First claim

What is claimed is:

1. A well production method comprising:
increasing gas flow velocity within a horizontal wellbore section by an velocity string and a downhole-type compressor;
decreasing a pressure within the horizontal wellbore section by the downhole-type compressor located within a wellbore section fluidically connected to the horizontal wellbore section, the decreased pressure in the horizontal wellbore section being sufficient to at least partially vaporize liquids within the horizontal portion; and
decreasing liquid build-up within the horizontal wellbore section in response to the increased gas flow velocity and the decreased pressure of the horizontal wellbore section.

2. The method of claim 1 , further comprising increasing a temperature of the gas flow by the downhole-type compressor.

3. The method of claim 2 , wherein the increased temperature is sufficient to prevent liquid fallout between a discharge of the downhole-type compressor and a topside facility located at an uphole end of the vertical wellbore section.

4. The method of claim 1 , further comprising sizing the downhole-type compressor to set a minimum flow velocity to remove liquids from the horizontal wellbore section.

5. The method of claim 4 , further comprising sizing the downhole-type compressor to set a maximum downhole pressure to vaporize liquids in the horizontal wellbore section.

6. The method of claim 5 , further comprising sizing the downhole-type compressor to use a specified amount of power to drive the compressor.

7. The method of claim 1 , wherein the inflow control device is a first inflow control device, and the horizontal wellbore section is a first horizontal wellbore section, the method further comprising:
increasing a gas flow velocity within a second horizontal wellbore section by a second velocity string and the downhole-type compressor.

8. The method of claim 7 , the method further comprising:
increasing a gas flow velocity within a third horizontal wellbore section by a third velocity string and the downhole-type compressor.

9. A wellbore production system comprising:
a production wellbore comprising a vertical portion and a horizontal portion, the vertical portion comprising a first end at a topside facility, the horizontal portion comprising a first end connected to a second end of the vertical portion, and a second end at a distal end of the production wellbore;
a downhole-type compressor located within the wellbore, the downhole-type compressor configured to decrease a pressure on a downhole side of the compressor and increase a pressure on an uphole side of the compressor, the decreased pressure on the downhole side being sufficient to at least partially vaporize liquids within the horizontal portion, the increased pressure on the uphole side being sufficient to flow gas from a compressor discharge to the topside facility;
a production string located within the wellbore; and
a velocity string located within the horizontal portion of the wellbore, the velocity string fluidically connected to the production string, the velocity string configured to adjust a gas velocity within the horizontal portion of the wellbore.

10. The wellbore production system of claim 9 , wherein the velocity string comprises a flow passage having a cross-sectional flow area that is less than the cross-sectional flow area of the production string.

11. The wellbore production system of claim 9 , wherein the velocity string is a first velocity string, wherein the first velocity string is located adjacent to a first production zone, the wellbore production system further comprising;
a first set of packers comprising:
a first packer located on a first end of the first velocity string; and
a second packer located on a second end of the first velocity string, the first packer and the second packer configured to fluidically isolate an annulus defined by the first velocity string and a wall of the horizontal portion adjacent to the first production zone, from a remainder of the wellbore; and

a second velocity string fluidically connected to the production string, the second velocity string being adjacent to a second production zone.

12. The wellbore production system of claim 11 , further comprising;
a third packer located on a second end of the second velocity string, the second packer and the third packer configured to fluidically isolate an annulus defined by the second velocity string and a wall of the horizontal portion adjacent to the second production zone, from a remainder of the wellbore; and
a third velocity string fluidically connected to the production string, the third velocity string being positioned on a side of the third packer opposite of the second velocity string, the third velocity string being adjacent to a third production zone.

13. The wellbore production system of claim 9 , further comprising a surface compressor fluidically connected to an uphole end of the production tubing, the surface compressor configured to further increase the gas flow velocity.

14. The wellbore production system of claim 13 , wherein the surface compressor comprises a subsea compressor.

15. The wellbore production system of claim 9 , wherein the horizontal portion is a first horizontal portion, the velocity string is a first velocity string, the system further comprising:
a second horizontal portion comprising a first end connected to the second end of the vertical portion, and a second end at a second distal end of the production wellbore; and
a second velocity string located within the second horizontal portion of the wellbore, the second velocity string fluidically connected to the production string, the second velocity string configured to adjust a gas velocity within the horizontal portion of the wellbore.

16. A well production method comprising:
increasing a gas flow velocity within a horizontal wellbore section by a velocity string and a downhole-type compressor;
decreasing a pressure within the horizontal wellbore section by the downhole-type compressor located within a vertical wellbore section fluidically connected to the horizontal wellbore section, the decreased pressure in the horizontal wellbore section being sufficient to at least partially vaporize liquids within the horizontal portion;
decreasing liquid build-up within the horizontal wellbore section in response to the increased gas flow velocity and the decreased pressure of the horizontal wellbore section; and
increasing a temperature of the gas flow by the downhole-type compressor, wherein the increased temperature is sufficient to prevent liquid fallout between a discharge of the downhole-type compressor and a topside facility located at an uphole end of the vertical wellbore section.

17. The method of claim 16 , further comprising sizing the downhole-type compressor to set a minimum flow velocity to remove liquids from the horizontal section.

18. The method of claim 16 , further comprising sizing the downhole-type compressor to set a maximum downhole pressure to vaporize liquids in the horizontal section.

19. The method of claim 16 , further comprising sizing the downhole-type compressor to use a specified amount of power to drive the compressor.

20. The method of claim 16 , wherein the velocity string is an active velocity string, the method further comprising adjusting a cross-sectional flow area of the active velocity string to adjust the gas velocity of the horizontal wellbore during a gas production operation.

21. The method of cl

Assignees

• Upwing Energy Llc

Inventors

• Chen Kuo-Chiang
• Artinian Herman
• Biddick David
• Nader Lukasz
• Sellers Christopher Matthew

Classifications

• E21B34/08

  responsive to flow or pressure of the fluid obtained (E21B34/10 takes precedence) · CPC title

• E21B43/12 Primary

  Methods or apparatus for controlling the flow of the obtained fluid to or in wells (E21B43/25 takes precedence; valve arrangements E21B34/00) · CPC title

• E21B43/13

  specially adapted to dewatering of wells of gas producing reservoirs, e.g. methane producing coal beds · CPC title

• E21B43/121 Primary

  Lifting well fluids (monitoring of down-hole pump systems E21B47/008) · CPC title