Subsea Mechanism to Circulate Fluid Between a Riser and Tubing String

• US 20170074069A1
• Filed: 08/11/2014
• Published: 03/16/2017
• Est. Priority Date: 08/11/2014
• Status: Active Grant

• Current Assignee: Halliburton Energy Services Incorporated (Halliburton Company)
• Original Assignee: Halliburton Energy Services Incorporated (Halliburton Company)
• Inventors: Perkins, Donald H., Schwendemann, Kenneth L.
• Granted Patent: US 10,006,270 B2
• Time in Patent Office: Days
• US Class Current: 1/1
• CPC Class Codes: E21B 17/01 Risers
• CPC Class Codes: E21B 2200/06 Sleeve valves
• CPC Class Codes: E21B 33/035 specially adapted for underwater installations E21B33/043, E21B33/064, E21B33/076 take precedence
• CPC Class Codes: E21B 33/064 specially adapted for underwater well heads
• CPC Class Codes: E21B 34/045 adapted to be lowered on a tubular string into position within a blow-out preventer stack, e.g. so-called test trees
• CPC Class Codes: E21B 34/12 operated by movement of casings or tubings

Abstract

A circulation mechanism in a subsea assembly is selectively actuated to allow fluid communication between the riser annulus and tubing string to immediately kill the well using heavy-weight fluid in the riser annulus; perform well control operations by adjusting the weight or other properties of fluid in the tubing string or riser annulus; and/or to circulate the riser of a deep-water well undergoing well testing or intervention.

Claims

1. A subsea assembly, comprising:

a tubing string extending within a riser, the riser having riser fluid therein and being connected to a blow-out preventer (“

BOP”

) positioned at a sea floor;

a subsea test tree (“

SSTT”

) positioned along the tubing string; and

a circulation mechanism positioned along the tubing string above the SSTT to allow selective communication of fluid between the tubing string and riser.

2. A subsea assembly as defined in claim 1, wherein the circulation mechanism comprises:

a port positioned along the tubing string; and

a sliding sleeve positioned around the tubing string to move between an open and closed position in relation to the port, the open position allowing fluid to communicate between the tubing string and riser, the closed position preventing fluid from communicating between the tubing string and riser.

3. A subsea assembly as defined in claim 1, wherein the circulation mechanism is surface-controlled.

4. A subsea assembly as defined in claim 1, wherein the circulation mechanism is positioned above the BOP.

5. A subsea assembly as defined in claim 1, wherein the riser fluid is a heavy-weight kill fluid.

6. A subsea assembly as defined in claim 1, further comprising a tubing closure mechanism positioned as part of the tubing string, wherein the circulation mechanism is positioned above or below the tubing closure mechanism.

7. A subsea assembly as defined in claim 1, further comprising a tubing closure mechanism positioned as part of the tubing string, wherein the circulation mechanism is positioned above the tubing closure mechanism and a second circulation mechanism is positioned below the tubing closure mechanism.

8. A subsea assembly as defined in claim 6, wherein the tubing closure mechanism is a ball valve, retainer valve or circulation valve.

9. A method using a subsea assembly, the method comprising:

deploying a tubing string into a riser, the riser being connected to a blow-out preventer (“

BOP”

) positioned at a sea floor above a well;

filling the riser with riser fluid; and

actuating a circulation mechanism to allow selective communication of fluid between the riser and the tubing string, the circulation mechanism being positioned as part of the tubing string above a subsea test tree (“

SSTT”

).

10. A method as defined in claim 9, wherein actuating the circulation mechanism comprises:

opening a sliding sleeve to allow the fluid to communicate between the riser and tubing string;

or

closing a sliding sleeve to prevent the fluid from communicating between the riser and tubing string.

11. A method as defined in claim 9, wherein:

filing the riser with riser fluid comprises filling the riser with a heavy-weight kill fluid; and

actuating the circulation mechanism comprises opening the circulation mechanism to allow the heavy-weight kill fluid to flow from the riser into the tubing string,

the method further comprising killing the well using the heavy-weight kill fluid.

12. A method as defined in claim 9, wherein:

the SSTT is closed;

filling the riser with riser fluid comprises filling the riser with a heavy-weight kill fluid; and

actuating the circulation mechanism comprises opening the circulation mechanism to allow the heavy-weight kill fluid to flow from the riser into the tubing string, thereby causing returns to flow up through the tubing string,

the method further comprising;

opening the SSTT; and

killing the well using the heavy-weight kill fluid.

13. A method as defined in claim 12, wherein, before the SSTT is closed, the tubing string is filled with gas or a fluid lighter than the heavy-weight kill fluid.

14. A method as defined in claim 9, wherein:

the SSTT is closed; and

actuating the circulation mechanism comprises opening the circulation mechanism,

the method further comprising;

pumping gas down the tubing string and out into the riser;

closing the circulation mechanism; and

opening the SSTT to allow production of well fluids.

15. A method as defined in claim 9, further comprising:

preventing fluid flow up the tubing string using a tubing closure mechanism positioned above the circulation mechanism, wherein actuating the circulation mechanism comprises opening the circulation mechanism to allow the riser fluid to flow from the riser into the tubing string, the riser fluid being a heavy-weight kill fluid;

killing the well using the heavy-weight kill fluid; and

closing the SSTT.

16. A method as defined in claim 9, wherein actuating the circulation mechanism comprises opening the circulation mechanism to:

adjust a weight of the riser fluid;

or

adjust a weight of fluid in the tubing string.

17. A method using a subsea assembly, the method comprising:

deploying a tubing string into a riser, the riser having riser fluid therein and being connected to a blow-out preventer (“

BOP”

) positioned at a sea floor above a well; and

selectively communicating fluid between the riser and the tubing string.

18. A method as defined in claim 17, wherein selectively communicating the fluid comprises:

flowing the riser fluid to flow from the riser and into the tubing string;

or

flowing fluid within the tubing string from the tubing string and into the riser.

19. A method as defined in claim 17, wherein selectively communicating the fluid comprises:

flowing the riser fluid from the riser and into the tubing string; and

killing the well using the riser fluid.

20. A method as defined in claim 17, further comprising:

closing a subsea test tree (“

SSTT”

) positioned along the tubing string;

flowing the riser fluid from the riser, into the tubing string, and up the tubing string;

opening the SSTT; and

killing the well with the riser fluid.

21. A method as defined in claim 17, further comprising:

closing a subsea test tree (“

SSTT”

);

pumping fluid down the tubing string and out into the riser via a port positioned along the tubing string;

closing the port; and

opening the SSTT to allow production of well fluids.

22. A method as defined in claim 17, further comprising:

preventing fluid flow up the tubing string;

flowing the riser fluid from the riser and into the tubing string;

killing the well using the riser fluid; and

closing a subsea test tree (“

SSTT”

).