Dual gradient managed pressure drilling

Patent metadata

Field	Value
Publication number	US-9328575-B2
Application number	US-201313752804-A
Country	US
Kind code	B2
Filing date	Jan 29, 2013
Priority date	Jan 31, 2012
Publication date	May 3, 2016
Grant date	May 3, 2016

Abstract

A method of drilling a subsea wellbore includes drilling the wellbore by injecting drilling fluid through a tubular string extending into the wellbore from an offshore drilling unit (ODU) and rotating a drill bit disposed on a bottom of the tubular string. The method further includes, while drilling the wellbore: mixing lifting fluid with drilling returns at a flow rate proportionate to a flow rate of the drilling fluid, thereby forming a return mixture. The lifting fluid has a density substantially less than a density of the drilling fluid. The return mixture has a density substantially less than the drilling fluid density. The method further includes, while drilling the wellbore: measuring a flow rate of the returns or the return mixture; and comparing the measured flow rate to the drilling fluid flow rate to ensure control of a formation being drilled.

First claim

The invention claimed is:

1. A method of drilling a subsea wellbore, comprising:
drilling the wellbore by injecting drilling fluid through a tubular string extending into the wellbore from an offshore drilling unit (ODU) and rotating a drill bit disposed on a bottom of the tubular string,
wherein:
the drilling fluid exits the drill bit and carries cuttings from the drill bit, and
the drilling fluid and cuttings (returns) flow to a floor of the sea via an annulus defined by an outer surface of the tubular string and an inner surface of the wellbore, and

while drilling the wellbore:
mixing lifting fluid with the returns at a flow rate proportionate to a flow rate of the drilling fluid, thereby forming a return mixture,
wherein:
the lifting fluid has a density substantially less than a density of the drilling fluid, and
the return mixture has a density substantially less than the drilling fluid density;

measuring a flow rate of the returns or the return mixture;
comparing the measured flow rate to the drilling fluid flow rate to ensure control of a formation being drilled; and
adjusting the lifting fluid flow rate in response to the comparison.

2. The method of claim 1 , wherein the returns flow from the seafloor, through a subsea wellhead, and into a pressure control assembly (PCA) connected to the subsea wellhead.

3. The method of claim 2 , wherein:
the lifting fluid is mixed with the returns in the PCA, and
the return mixture flows from the PCA to the ODU via a conduit.

4. The method of claim 3 , wherein the lifting fluid is injected into the PCA through a first auxiliary line.

5. The method of claim 4 , wherein the conduit is a second auxiliary line.

6. The method of claim 4 , wherein the conduit is a marine riser.

7. The method of claim 2 , wherein:
a marine riser is connected to the PCA and connected to the ODU by an upper marine riser package (UMRP),
the lifting fluid is mixed with the returns by injection into the UMRP and down the marine riser, and
the return mixture flows to the ODU via a conduit.

8. The method of claim 7 , wherein the conduit is an auxiliary line.

9. The method of claim 7 , wherein:
the marine riser is an outer riser,
an inner riser is disposed in the outer riser and extends from the UMRP toward the PCA along at least a portion of the outer riser,
the lifting fluid is transported down an outer annulus formed between the risers,
the lifting fluid is mixed with the returns at a shoe of the inner riser, and
the conduit is an inner annulus formed between the inner riser and the tubular string.

10. The method of claim 9 , further comprising selectively locating the inner riser shoe along the outer riser.

11. The method of claim 2 , wherein:
the lifting fluid is mixed with the returns in a conduit extending from the PCA to the ODU, and
the lifting fluid is injected into the conduit through an auxiliary line.

12. The method of claim 11 , further comprising selectively locating an injection point of the lifting fluid along the conduit.

13. The method of claim 1 , wherein the flow rate is measured using a subsea mass flow meter.

14. The method of claim 1 , wherein:
the measured flow rate is the return mixture flow rate,
the flow rate is measured using a mass flow meter located onboard the ODU, and
the lifting fluid flow rate is included in the comparison.

15. The method of claim 1 , wherein the measured flow rate is the returns flow rate.

16. The method of claim 1 , wherein:
the returns or the return mixture flows through a variable choke valve, and
the method further comprises adjusting the variable choke valve in response to the comparison.

17. The method of claim 16 , wherein:
the return mixture flows through the variable choke valve, and
the variable choke valve is located onboard the ODU.

18. The method of claim 16 , wherein the variable choke valve is located subsea.

19. The method of claim 18 , wherein the returns flow through the subsea variable choke valve.

20. The method of claim 18 , wherein the return mixture flows through the subsea variable choke valve.

21. The method of claim 1 , wherein:
drilling fluid is mud, and
the lifting fluid is base liquid of the mud.

22. The method of claim 21 , wherein:
the mud is oil based, and
the method further comprises separating the return mixture into the mud and base oil and recycling the separated mud and base oil while drilling the wellbore.

23. The method of claim 1 , wherein:
the lifting fluid density is less than a density of seawater, and
the return mixture density corresponds to the seawater density.

24. The method of claim 1 , wherein the return mixture density is one-half to three-fourths of the drilling fluid density.

25. The method of claim 1 , wherein the lifting fluid is gaseous.

26. A method of drilling a subsea wellbore, comprising:
drilling the wellbore by injecting drilling fluid through a tubular string extending into the wellbore from an offshore drilling unit (ODU) and rotating a drill bit disposed on a bottom of the tubular string,
wherein:
the drilling fluid exits the drill bit and carries cuttings from the drill bit, and
the drilling fluid and cuttings (returns) flow to a floor of the sea via an annulus defined by an outer surface of the tubular string and an inner surface of the wellbore, and

while drilling the wellbore:
mixing lifting fluid with the returns at a flow rate proportionate to a flow rate of the drilling fluid, thereby forming a return mixture,
wherein:
the lifting fluid has a density substantially less than a density of the drilling fluid,
the return mixture has a density substantially less than the drilling fluid density,
the returns flow from the seafloor, through a subsea wellhead, and into a pressure control assembly (PCA) connected to the subsea wellhead,
a marine riser is connected to the PCA and connected to the ODU by an upper marine riser package (UMRP),
the lifting fluid is mixed with the returns by injection into the UMRP and down an annulus formed between the tubular string and the marine riser, and
the return mixture flows to the ODU via an auxiliary line extending along an outer surface of the marine riser;

measuring a flow rate of the returns or the return mixture; and
comparing the measured flow rate to the drilling fluid flow rate to ensure control of a formation being drilled.

Assignees

• Weatherford Technology Holdings Llc

Inventors

• Feasey Guy F
• Pavel David
• Mitchell Mark A

Classifications

• E21B21/001

  specially adapted for underwater drilling (dual gradient drilling E21B21/082) · CPC title

• E21B7/12

  Underwater drilling (using heave compensators E21B19/09) · CPC title

• E21B21/08 Primary

  Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure (valve arrangements therefor E21B21/10) · CPC title

• E21B21/082 Primary

  Dual gradient systems, i.e. using two hydrostatic gradients or drilling fluid densities · CPC title