U.S. patent application number 10/191152 was filed with the patent office on 2006-03-30 for drilling system and method for controlling equivalent circulating density during drilling of wellbores.
This patent application is currently assigned to Baker Hughes Incorporated. Invention is credited to Peter Aronstam, Peter Fontana, Larry Watkins.
Application Number | 20060065402 10/191152 |
Document ID | / |
Family ID | 29219913 |
Filed Date | 2006-03-30 |
United States Patent
Application |
20060065402 |
Kind Code |
A9 |
Fontana; Peter ; et
al. |
March 30, 2006 |
Drilling system and method for controlling equivalent circulating
density during drilling of wellbores
Abstract
A drilling system for drilling subsea wellbores includes a
tubing-conveyed drill bit that passes through a subsea wellhead.
Surface supplied drilling fluid flows through the tubing,
discharges at the drill bit, returns to the wellhead through a
wellbore annulus, and flows to the surface via a riser extending
from the wellhead. A flow restriction device positioned in the
riser restricts the flow of the returning fluid while an active
fluid device controllably discharges fluid from a location below to
just above the flow restriction device in the riser, thereby
controlling bottomhole pressure and equivalent circulating density
("ECD"). Alternatively, the fluid is discharged into a separate
return line thereby providing dual gradient drilling while
controlling bottomhole pressure and ECD. A controller controls the
energy and thus the speed of the pump in response to downhole
measurement(s) to maintain the ECD at a predetermined value or
within a predetermined range.
Inventors: |
Fontana; Peter; (Amsterdam,
NL) ; Watkins; Larry; (Houston, TX) ;
Aronstam; Peter; (Houston, TX) |
Correspondence
Address: |
PAUL S MADAN;MADAN, MOSSMAN & SRIRAM, PC
2603 AUGUSTA, SUITE 700
HOUSTON
TX
77057-1130
US
|
Assignee: |
Baker Hughes Incorporated
Houston
TX
|
Prior
Publication: |
|
Document Identifier |
Publication Date |
|
US 20030066650 A1 |
April 10, 2003 |
|
|
Family ID: |
29219913 |
Appl. No.: |
10/191152 |
Filed: |
July 9, 2002 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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|
10094208 |
Mar 8, 2002 |
6648081 |
|
|
10191152 |
Jul 9, 2002 |
|
|
|
09353275 |
Jul 14, 1999 |
6415877 |
|
|
10094208 |
Mar 8, 2002 |
|
|
|
60303959 |
Jul 9, 2001 |
|
|
|
60304160 |
Jul 10, 2001 |
|
|
|
60323797 |
Sep 20, 2001 |
|
|
|
60108601 |
Nov 16, 1998 |
|
|
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60101541 |
Sep 23, 1998 |
|
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|
60092908 |
Jul 15, 1998 |
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60095188 |
Aug 3, 1998 |
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Current U.S.
Class: |
166/358 ;
166/367 |
Current CPC
Class: |
E21B 21/08 20130101;
E21B 43/12 20130101; E21B 47/001 20200501; E21B 21/001 20130101;
E21B 7/12 20130101; E21B 33/076 20130101 |
Class at
Publication: |
166/358 ;
166/367 |
International
Class: |
E21B 7/12 20060101
E21B007/12 |
Claims
1. A system for supporting subsea wellbore operations, comprising:
(a) a supply conduit for providing drilling fluid into a wellbore;
(b) a return conduit including a riser for conveying the drilling
fluid from the wellbore to a predetermined location, the supply
conduit and return conduit forming a fluid circuit; and (c) an
active pressure differential device ("APD device") adapted to
selectively receive the drilling fluid from a first selected
location on the riser and convey the drilling fluid to a second
selected location.
2. The system according to claim 1 further comprising a flow
restriction device positioned in the return conduit for selectively
diverting the drilling fluid from the riser to the APD device.
3. The system according to claim 1 wherein the second selected
location is one of (i) a section of the riser uphole of the first
selected location; and (ii) a separate line to a surface
location.
4. The system according to claim 1 wherein the second selected
location is a separate line to a surface location; and a section of
the riser uphole of the first selected location is at least
partially filled with a fluid having a density different from that
of the drilling fluid.
5. The system of claim 1, wherein the APD device is located at one
of (i) in the riser, (ii) outside the riser, and (iii) in an
annulus of the wellbore.
6. The system of claim 1, wherein the APD device is between 1000
ft. below the sea level and the sea bottom.
7. The system of claim 1, wherein the APD device is one of: (i) at
least one centrifugal pump; (ii) a turbine; (iii) jet pump; and
(iv) a positive displacement pump.
8. The system according to claim 1 wherein the APD device is
configured to control equivalent circulating density of the
drilling fluid in at least a portion of the fluid circuit.
9. The system of claim 1 further comprising a controller that
controls the APD device to control the equivalent circulating
density in at least a portion of the fluid circuit.
10. The system of claim 9, wherein the controller controls the APD
device in response to pressure.
11. The system of claim 10, wherein the pressure is one of: (i)
bottomhole pressure; (ii) measured at a location in the supply
conduit; (iii) measured at well control equipment associated with
the wellbore; (iv) measured in the return conduit; (v) measured in
a bottomhole assembly; (vi) measured at the surface; (vii) stored
in a memory associated with the controller; and (viii) measured
near an inlet to the APD device.
12. The system of claim 9, wherein the controller controls the
differential pressure to one of: (i) maintain the bottomhole
pressure at a predetermined value; (ii) maintain the bottomhole
pressure within a range; (iii) maintain the pressure in the
wellbore at at-balance condition; (iv) maintain the pressure in the
wellbore at under-balance condition; and (v) reduce the bottomhole
pressure by a selected amount.
13. The system of claim 9, wherein the controller controls the APD
device to maintain the equivalent circulating density at one of (i)
a predetermined value, and (ii) within a predetermined range.
14. The system of claim 9 further comprising at least one sensor
providing pressure measurements of the drilling fluid in the fluid
circuit.
15. The system of claim 14, wherein the controller controls the APD
device in response to the pressure measurement and according to
programmed instructions provided thereto.
16. The system of claim 1 further comprising drill string disposed
in the wellbore; and a drilling assembly connected to the drill
string for forming the wellbore.
17. The system of claim 1 wherein a controller operably coupled to
the APD device controls the APD device in response to a parameter
of interest.
18. The system of claim 17, wherein the parameter of interest is
one of: (i) pressure; (ii) flow rate; (iii) characteristic of fluid
in the wellbore; and (iv) a formation characteristic.
19. A method for supporting subsea wellbore operations, comprising:
(a) providing drilling fluid into a wellbore via a supply conduit;
(b) conveying the drilling fluid from the wellbore to a
predetermined location via a return conduit including a riser, the
supply conduit and return conduit forming a fluid circuit; and (c)
conveying the drilling fluid from a first selected location on the
riser to a second selected location with an active pressure
differential device ("APD device").
20. The method according to claim 19 further comprising selectively
diverting the drilling fluid from the riser to the APD device with
a flow restriction device positioned in the return conduit.
21. The method according to claim 19 wherein the second selected
location is one of (i) a section of the riser uphole of the first
selected location; and (ii) a separate line to a surface
location.
22. The method according to claim 19 wherein the second selected
location is a separate line to a surface location; and a section of
the riser uphole of the first selected location is at least
partially filled with a fluid having a density different from that
of the drilling fluid.
23. The method according to claim 19, further comprising
positioning the APD device between 1000 ft. below the sea level and
the sea bottom.
24. The method of claim 19, wherein the APD device is one of: (i)
at least one centrifugal pump; (ii) a turbine; (iii) a jet pump and
(iv) a positive displacement pump.
25. The method of claim 19 further comprising controlling the APD
device to control the equivalent circulating density in at least a
portion of the fluid circuit.
26. The method of claim 25, wherein the APD device is controlled in
response to pressure.
27. The method of claim 26, wherein the pressure is one of: (i)
bottomhole pressure; (ii) measured at a location in the supply
conduit; (iii) measured at well control equipment associated with
the wellbore; (iv) measured in the return conduit; (v) measured in
a bottomhole assembly; (vi) measured at the surface; (vii) stored
in a memory associated with the controller; and (viii) measured
near an inlet to the APD device.
28. The method of claim 19, further comprising controlling the APD
device to provide a differential pressure to control a bottomhole
pressure to one of: (i) maintain the bottomhole pressure at a
predetermined value; (ii) maintain the bottomhole pressure within a
range; (iii) maintain the pressure in the wellbore at at-balance
condition; (iv) maintain the pressure in the wellbore at
under-balance condition; and (v) reduce the bottomhole pressure by
a selected amount.
29. The method according to claim 19, wherein the controller
controls the fluid flow device to maintain the equivalent
circulating density at one of (i) a predetermined value, and (ii)
within a predetermined range.
30. The method according to claim 19 further comprising drill
string disposed in the wellbore; and a drilling assembly connected
to the drill string.
31. A wellbore system for performing subsea downhole wellbore
operations comprising: (a) a tubing receiving fluid from a source
adjacent an upper end of the tubing; (b) a subsea wellhead assembly
above a wellbore receiving the tubing, said wellhead assembly
adapted to receive said fluid after it has passed down through said
tubing and back up through an annulus between the tubing and the
wellbore; (c) a riser extending up from the wellhead assembly to
the sea level for conveying returning fluid from the wellhead to
the sea level, with the tubing, annulus, wellhead and the riser
forming a subsea fluid circulation system; (d) a flow restriction
device adapted to restrict flow of the fluid returning to the sea
level; and (e) a fluid flow device for diverting returning fluid
about the flow restriction device to control equivalent circulating
density of fluid circulating in the fluid circulation system.
32. The wellbore system of claim 31, wherein the active fluid flow
device is located at one of (i) in the riser, (ii) outside the
riser, and (iii) in the annulus.
33. The wellbore system of claim 31, wherein the active fluid flow
device is one of: (i) at least one centrifugal pump; (ii) a
turbine; (iii) and (iv) a positive displacement pump.
34. The wellbore system of claim 31 further comprising a controller
that controls the fluid flow device to control the equivalent
circulating density.
35. The wellbore system of claim 34, wherein the controller
controls the active flow fluid device in response to pressure, the
pressure being one of: (i) bottomhole pressure; (ii) measured at a
location in the drill string; (iii) measured at the well control
equipment; (iv) measured in the riser; (v) measured in a bottomhole
assembly carrying the drill bit; (vi) measured at the surface;
(vii) stored in a memory; and (viii) measured near the inlet to the
active fluid flow device.
36. The wellbore system of claim 34, wherein the controller
controls the differential pressure to control the bottomhole
pressure to one of: (i) maintain the bottomhole pressure at a
predetermined value; (ii) maintain the bottomhole pressure within a
range; (iii) maintain the pressure in the wellbore at at-balance
condition; (iv) maintain the pressure in the wellbore at
under-balance condition; and (v) reduce the bottomhole pressure by
a selected amount.
37. The wellbore system of claim 34, wherein the controller
controls the fluid flow device to maintain the equivalent
circulating density at one of (i) a predetermined value, and (ii)
within a predetermined range.
38. The wellbore system of claim 34, wherein the controller
controls the fluid flow device in response to pressure measurement
provided by a sensor positioned in the drilling fluid and according
to programmed instructions provided thereto.
38. The wellbore system of claim 31, wherein the active fluid flow
device returns the returning fluid to the surface via the
riser.
40. The wellbore system of claim 31 further comprising a drilling
assembly connected to the tubing for forming a wellbore.
41. A method for drilling a subsea wellbore wherein a riser extends
from a well control equipment at the sea bed to the surface,
comprising: (a) providing a drill string having a drill bit at a
bottom end thereof extending from the surface into the wellbore
through the riser; b) supplying drilling fluid to the drill string,
said drilling fluid discharging at the bottom of the drill bit and
returning to the surface via an annulus between the drill string
and the riser, the annulus defining a portion of the return fluid
path; (c) restricting the return fluid path in the riser at a
preselected depth; and (d) diverting returning fluid about the
restriction to control equivalent circulating density of fluid at
least downhole of the restriction.
42. The method of claim 41, wherein pumping is performed by an
active fluid flow device.
43. The method of claim 41 further comprising returning the return
fluid to the surface via a portion of the riser above the
restriction.
44. The method of claim 41 further comprising controlling the
diverting of the fluid with an active fluid flow device to create a
selected pressure differential across the active fluid flow
device.
45. The method of claim 44 further comprising providing at least
one pressure sensor to provide signals indicative of pressure in
the wellbore.
46. The method of claim 45 further comprising locating the at least
one pressure sensor at one of: (i) the annulus of the wellbore;
(ii) a location in the drill string; (iii) well control equipment;
(iv) the riser; (v) a bottomhole assembly carrying the drill bit;
(vi) the surface; (vii) a memory; and (viii) near the inlet of the
active fluid flow device.
47. The method of claim 41, further comprising controlling the
active fluid flow device to one of: (i) maintain bottomhole
pressure at a certain value; (ii) maintain bottomhole pressure
within a range; (iii) maintain wellbore at at-balance condition;
and (iv) maintain wellbore at underbalance condition.
48. A dual gradient drilling system for drilling a subsea wellbore,
the system having a riser extending from a well control equipment
at the sea bed over the wellbore to the surface, comprising: (a) a
drill string having a drill bit at a bottom end thereof extending
from the surface into the wellbore through the riser and the well
control equipment for drilling the wellbore; (b) a source of
drilling fluid supplying drilling fluid into the drill string, said
drilling fluid discharging at the bottom of the drill bit and
returning to the surface in part via an annulus between the drill
string and the riser, said annulus defining the return fluid path;
(c) a restriction device at a predetermined depth in the riser
restricting the flow of the returning fluid through the riser
uphole of the restriction device; (d) an active pressure
differential device ("APD Device") on the riser pumping fluid from
a location downhole of the restriction device to the surface by
bypassing the riser section uphole of the restriction device; and
(e) a fluid with density less than that of the returning fluid
("lower density fluid") in the riser uphole of the restriction
device.
49. The system of claim 48, wherein the APD Device is one of: (i)
at least one centrifugal pump; (ii) a turbine; (iii) and (iv) a
positive displacement pump.
50. The system of claim 48 further comprising a separate return
line outside the riser extending from the APD Device to the surface
to carry the returning fluid to the surface by bypassing the
riser.
51. The system of claim 48 further comprising a controller for
controlling the APD Device to create a pressure differential across
the APD Device to reduce a selected pressure associated with the
drilling fluid.
52. The system of claim 48, further comprising a controller
associated with the APD device to control the differential pressure
to one of: (i) maintain the bottomhole pressure at a predetermined
value; (ii) maintain the bottomhole pressure within a range; (iii)
maintain the pressure in the wellbore at at-balance condition; (iv)
maintain the pressure in the wellbore at under-balance condition;
and (v) reduce the bottomhole pressure by a selected amount.
53. The system of claim 48, further comprising a controller for
controlling the APD Device in response to one of: (i) a parameter
of interest; (ii) programmed instruction stored for use by the
controller; and (iii) signals transmitted to the controller from a
remote device.
54. A dual gradient drilling method for drilling a subsea wellbore
wherein a riser extends from a well control equipment at the sea
bed to the surface, comprising: (a) providing a drill string having
a drill bit at a bottom end thereof extending from the surface into
the wellbore through the riser; b) supplying drilling fluid to the
drill string, said drilling fluid discharging at the bottom of the
drill bit and returning to the surface in part via an annulus
between the drill string and the riser, said annulus defining a
portion of the return fluid path; (c) restricting the return fluid
path in the riser at a preselected depth; (d) pumping fluid from
the riser at a location downhole of the restriction to the surface
by bypassing the riser uphole of the restriction; and (e) filling
the riser uphole of the restriction with a lighter fluid than the
returning fluid to provide a fluid pressure gradient to the
wellbore that is less than the pressure gradient formed by the
fluid downhole of the restriction.
55. The method of claim 54, wherein pumping the fluid includes
pumping with an active pressure differential device ("APD
Device").
56. The method of claim 55, wherein the APD Device is one of: (i)
at least one centrifugal pump; (ii) a turbine; (iii) and (iv) a
positive displacement pump.
57. The method of claim 54 further comprising providing a separate
return line outside the riser and extending to the surface to carry
the returning fluid to the surface while bypassing the riser.
58. The method of claim 54 further comprising controlling the APD
Device to create a selected pressure differential across the APD
Device.
59. The method of claim 14 further comprising providing at least
one pressure sensor to provide signals indicative of pressure in
the wellbore, the at least one pressure sensor location being
selected from a group consisting of: (i) the annulus of the
wellbore; (ii) a location in the drill string; (iii) well control
equipment; (iv) the riser; (v) a bottomhole assembly carrying the
drill bit; (vi) the surface; (vii) a memory; and (viii) near the
inlet of the APD device.
60. The method of claim 19, wherein controlling the APD Device
includes one of: (i) maintaining bottomhole pressure at a certain
value; (ii) maintaining bottomhole pressure within a range; (iii)
maintaining wellbore at at-balance condition; and (iv) maintaining
wellbore at underbalance condition.
Description
CROSS-REFERENCES TO RELATED APPLICATIONS
[0001] This application takes priority from Provisional U.S. Patent
Applications Serial Nos. 60/303,959 and 60/304,160, filed on Jul.
9.sup.th, 2001 and Jul. 10.sup.th, 2001, respectively, and
Provisional U.S. Patent Application Serial No. 60/323,797, filed on
Sep. 20.sup.th, 2001. This application also takes priority from
U.S. application Ser. No. 10/094,208, filed Mar. 8.sup.th, 2002 and
Ser. No. 09/353,275, filed Jul. 14.sup.th, 1999, both of which
claim priority from U.S. application Nos.: No. 60/108,601, filed
Nov. 16.sup.th, 1998; No. 60/101,541, filed Sep. 23.sup.rd, 1998;
No. 60/092,908, filed Jul. 15.sup.th, 1998; and No. 60/095,188,
filed Aug. 3.sup.rd, 1998.
BACKGROUND OF THE INVENTION
[0002] 1. Field of the Invention
[0003] This invention relates generally to oilfield wellbore
drilling systems and more particularly to subsea drilling systems
that control bottom hole pressure or equivalent circulating density
during drilling of the wellbores.
[0004] 2. Background of the Art
[0005] Oilfield wellbores are drilled by rotating a drill bit
conveyed into the wellbore by a drill string. The drill string
includes a drilling assembly (also referred to as the "bottom hole
assembly" or "BHA") that carries the drill bit. The BHA is conveyed
into the wellbore by a tubing. Coiled tubing or jointed tubing is
utilized to convey the drilling assembly into the wellbore. The
drilling assembly sometimes includes a drilling motor or a "mud
motor" that rotates the drill bit. The drilling assembly also
includes a variety of sensors for taking measurements of a variety
of drilling, formation and BHA parameters. A suitable drilling
fluid (commonly referred to as the "mud") is supplied or pumped
from the surface down the tubing. The drilling fluid drives the mud
motor and then it discharges at the bottom of the drill bit. The
drilling fluid returns uphole via the annulus between the drill
string and the wellbore and carries with it pieces of formation
(commonly referred to as the "cuttings") cut or produced by the
drill bit in drilling the wellbore.
[0006] For drilling wellbores under water (referred to in the
industry as "offshore" or "subsea" drilling) tubing is provided at
the surface work station (located on a vessel or platform). One or
more tubing injectors or rigs are used to move the tubing into and
out of the wellbore. In sub-sea riser-type drilling, a riser, which
is formed by joining sections of casing or pipe, is deployed
between the drilling vessel and the wellhead equipment at the sea
bottom and is utilized to guide the tubing to the wellhead. The
riser also serves as a conduit for fluid returning from the
wellhead to the vessel at sea surface.
[0007] During drilling, the drilling operator attempts to carefully
control the fluid density at the surface so as to prevent an
overburdened condition in the wellbore. In other words, the
operator maintains the hydrostatic pressure of the drilling fluid
in the wellbore above the formation or pore pressure to avoid well
blow-out. The density of the drilling fluid and the fluid flow rate
largely determine the effectiveness of the drilling fluid to carry
the cuttings to the surface. One important downhole parameter
during drilling is the bottomhole pressure, which is effectively
the equivalent circulating density ("ECD") of the fluid at the
wellbore bottom.
[0008] This term, ECD, describes the condition that exists when the
drilling mud in the well is circulated. ECD is the friction
pressure caused by the fluid circulating through the annulus of the
open hole and the casing(s) on its way back to the surface. This
causes an increase in the pressure profile along this path that is
different from the pressure profile when the well is in a static
condition (i.e., not circulating). In addition to the increase in
pressure while circulating, there is an additional increase in
pressure while drilling due to the introduction of drill solids
into the fluid. This pressure increase along the annulus of the
well can negatively impact drilling operations by fracturing the
formation at the shoe of the last casing. This can reduce the
amount of hole that can be drilled before having to set an
additional casing. In addition, the rate of circulation that can be
achieved is also limited. Due to this circulating pressure
increase, the ability to clean the hole is severely restricted.
This condition is exacerbated when drilling an offshore well. In
offshore wells, the difference between the fracture pressures in
the shallow sections of the well and the pore pressures of the
deeper sections is considerably smaller compared to on-shore
wellbores. This is due to the seawater gradient versus the gradient
that would exist if there were soil overburden for the same
depth.
[0009] In order to be able to drill a well of this type to a total
wellbore depth at a subsea location, the bottom hole ECD must be
reduced or controlled. One approach to do so is to use a mud filled
riser to form a subsea fluid circulation system utilizing the
tubing, BHA, the annulus between the tubing and the wellbore and
the mud filled riser, and then inject gas (or some other low
density liquid) in the primary drilling fluid (typically in the
annulus adjacent the BHA) to reduce the density of fluid downstream
(i.e., in the remainder of the fluid circulation system). This
so-called "dual density" approach is often referred to as drilling
with compressible fluids.
[0010] Another method for changing the density gradient in a
deepwater return fluid path has been proposed. This approach
proposes to use a tank, such as an elastic bag, at the sea floor
for receiving return fluid from the wellbore annulus and holding it
at the hydrostatic pressure of the water at the sea floor.
Independent of the flow in the annulus, a separate return line
connected to the sea floor storage tank and a subsea lifting pump
delivers the return fluid to the surface. Although this technique
(which is referred to as "dual gradient" drilling) would use a
single fluid, it would also require a discontinuity in the
hydraulic gradient line between the sea floor storage tank and the
subsea lifting pump. This requires close monitoring and control of
the pressure at the subsea storage tank, subsea hydrostatic water
pressure, subsea lifting pump operation and the surface pump
delivering drilling fluids under pressure into the tubing for flow
downhole. The level of complexity of the required subsea
instrumentation and controls as well as the difficulty of
deployment of the system has delayed the commercial application of
the "dual gradient" system.
[0011] Another approach is described in U.S. patent application
Ser. No. 09/353,275, filed on Jul. 14, 1999 and assigned to the
assignee of the present application. The U.S. patent application
Ser. No. 09/353,275 is incorporated herein by reference in its
entirety. One embodiment of this application describes a riserless
system wherein a centrifugal pump in a separate return line
controls the fluid flow to the surface and thus the equivalent
circulating density.
[0012] The present invention provides a wellbore system wherein
equivalent circulating density is controlled by controllably
bypassing the returning fluid about a restriction in the returning
fluid path of a riser utilizing an active differential pressure
device, such as a centrifugal pump or turbine, located adjacent to
the riser. The fluid is then returned into the riser above the
restriction. The present invention also provides a dual gradient
subsea drilling system wherein equivalent circulating density is
controlled by controllably bypassing the returning fluid about a
restriction in a riser by utilizing an active differential pressure
device, such as a centrifugal pump or turbine located some distance
above the sea bed. The present systems are relatively easy to
incorporate in new and existing systems.
SUMMARY OF THE INVENTION
[0013] The present invention provides wellbore systems for
performing subsea downhole wellbore operations, such as subsea
drilling as described more fully hereinafter. Such drilling systems
include a rig at the sea level that moves a drill string into and
out of the wellbore. A bottom hole assembly, carrying the drill
bit, is attached to the bottom end of the tubing. A wellhead
assembly or equipment at the sea bottom receives the bottom hole
assembly and the tubing. A drilling fluid system supplies a
drilling fluid into a fluid circuit that supports wellbore
operations. In one embodiment, the fluid circuit includes a supply
conduit and a return conduit. The supply conduit includes a tubing
string that receives drilling fluid from the fluid system. This
fluid is discharged at the drill bit and returns to the wellhead
equipment carrying the drill cuttings. The return conduit includes
a riser dispersed between the wellhead equipment and the surface
that guides the drill string and provides a conduit for moving the
returning fluid to the surface.
[0014] In one embodiment of the present invention, a flow
restriction device in the riser restricts the flow of the returning
fluid through the riser. Preferably, the flow restriction device
moves between a substantially open bore and closed bore positions
and accommodates the axial sliding and rotation movement of the
drill string. In one embodiment, radial bearings stabilize the
drill string while a hydraulically actuated packer assembly
provides selective obstruction of the riser bore and therefore
selectively diverts return fluid flow into a flow diverter line
provided below the flow restriction device. Additionally, a seal
such as a rotary seal is used to further restrict flow of return
fluid through the flow restriction device. A fluid flow device,
such as a centrifugal pump or turbine in the flow diverter line
causes a pressure differential in the returning fluid as it flows
from just below the flow restriction device to above the flow
restriction device. The pump speed is controlled, by controlling
the energy input to the pump. One or more pressure sensors provide
pressure measurement of the circulating fluid. A controller
controls the operation of the pump to control the amount of the
differential pressure across the pump and thus the equivalent
circulating density. The controller maintains the equivalent
circulating density at a predetermined level or within a
predetermined range in response to programmed instructions provided
to the controller. The pump is mounted on the outside of the riser
joint, typically at a sufficient depth below the sea level to
provide enough lift to offset the desired amount of ECD.
Alternatively, the flow restriction device and the pump may be
disposed in the return fluid path in the annulus between the
wellbore and the drill string. The present system is equally useful
as an at-balance or an underbalanced drilling system.
[0015] In another embodiment of the present invention, a flow
restriction device in the riser restricts the flow of the returning
fluid through the riser. A flow diverter line, active pressure
differential device ("APD Device") and a separate return line
provide a fluid flow path around the flow restriction device. In
this embodiment, dual gradient drilling with active control of
wellbore pressure is achieved mid riser or at a selected point in
the riser, the selected point between the surface and sea bottom.
The active pressure differential device, such as centrifugal pumps
or turbines, moves the returning fluid from just below the flow
restriction device to the surface via the separate return line. The
operation of the active pressure differential device is controlled
to create a differential pressure across the device, thereby
reducing the bottomhole pressure. The pumps or turbines speeds are
controlled, by controlling the energy input to the pumps or
turbines. One or more pressure sensors provide pressure
measurements of the circulating fluid. A controller controls the
operation of the pumps or turbines to control the amount of the
pressure differential and thus the equivalent circulating density.
The controller maintains the bottom hole pressure and the
equivalent circulating density at a predetermined level or within a
predetermined range in response to programmed instructions provided
to the controller. The pumps or turbines are mounted on the outside
of the riser, typically between 1000 to 3000 ft. below sea level,
but above the sea bed. The present system is equally useful in
maintaining the bottomhole pressure at an at-balance or
under-balance condition.
[0016] Examples of the more important features of the invention
have been summarized (albeit rather broadly) in order that the
detailed description thereof that follows may be better understood
and in order that the contributions they represent to the art may
be appreciated. There are, of course, additional features of the
invention that will be described hereinafter and which will form
the subject of the claims appended hereto.
BRIEF DESCRIPTION OF THE DRAWINGS
[0017] For detailed understanding of the present invention,
reference should be made to the following detailed description of
the preferred embodiment, taken in conjunction with the
accompanying drawing:
[0018] FIG. 1 is a schematic elevation view of one embodiment of a
wellbore system for controlling equivalent circulating density
during drilling of subsea wellbores;
[0019] FIG. 2 is a schematic elevation view of a flow restriction
device and active differential pressure device made in accordance
with one embodiment of the present invention;
[0020] FIGS. 3A and 3B illustrate pressure gradient curves provided
by the FIG. 1 embodiment of the present invention;
[0021] FIG. 4 is a schematic elevation view of one embodiment of a
wellbore system for controlling equivalent circulating density and
bottomhole pressure during dual gradient drilling of subsea
wellbores with the device mounted at a point in the riser between
the surface and the seabed; and
[0022] FIGS. 5A and 5B illustrate pressure gradient curves provided
by the FIG. 4 embodiment of the present invention.
DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS
[0023] FIG. 1 shows a schematic elevational view of a wellbore
drilling system 100 for drilling a subsea or under water wellbore
90. The drilling system 100 includes a drilling platform 101, which
may be a drill ship or another suitable surface work station such
as a floating platform or a semi-submersible. A drilling ship or a
floating rig is usually preferred for drilling deep water
wellbores, such as wellbores drilled under several thousand feet of
water. To drill a wellbore 90 under water, wellhead equipment 125
is deployed above the wellbore 90 at the sea bed or bottom 123. The
wellhead equipment 125 includes a blow-outpreventer stack 126. A
lubricator (not shown) with its associated flow control valves may
be provided over the blow-out-preventer 126.
[0024] The subsea wellbore 90 is drilled by a drill bit 130 carried
by a drill string 120, which includes a drilling assembly or a
bottom hole assembly ("BHA") 135 at the bottom of a suitable tubing
121, which may be a coiled tubing or a jointed pipe. The tubing 121
is placed at the drilling platform 101. To drill the wellbore 90,
the BHA 135 is conveyed from the vessel 101 to the wellhead
equipment 125 and then inserted into the wellbore 90. The tubing
121 is moved to the wellhead equipment 125 and then moved into and
out of the wellbore 90 by a suitable tubing injection system.
[0025] To drill the wellbore 90, a drilling fluid 20 from a surface
drilling fluid system or mud system 22 is directed into a fluid
circuit that services the wellbore 90. This fluid can be
pressurized or use primarily gravity assisted flow. In one
embodiment, the mud system 22 includes a mud pit or supply source
26 and one or more pumps 28 in fluid communication with a supply
conduit of the fluid circuit. The fluid is pumped down the supply
conduit, which includes the tubing 121. The drilling fluid 20 may
operate a mud motor in the BHA 135, which in turn rotates the drill
bit 130. The drill bit 130 breaks or cuts the formation (rock) into
cuttings 147. The drilling fluid 142 leaving the drill bit travels
uphole through a return conduit of the fluid circuit. In one
embodiment, the return conduit includes the annulus 122 between the
drill string 120 and the wellbore wall 126 carrying the drill
cuttings 147. The return circuit also includes a riser 160 between
the wellhead 125 and the surface 101 that carries the returning
fluid 142 from the wellbore 90 to the sea level. The returning
fluid 142 discharges into a separator 24, which separates the
cuttings 147 and other solids from the returning fluid 142 and
discharges the clean fluid into the mud pit 26. The tubing 121
passes through the mud-filled riser 160. As shown in FIG. 1, the
clean mud 20 is pumped through the tubing 121 and the mud 142 with
cuttings 147 returns to the surface via the annulus 122 up to the
wellhead 125 and then via the riser 160. Thus, the fluid
circulation system or fluid circuit includes a supply conduit
(e.g., the tubing 121) and a return conduit (e.g., the annulus 122
and the riser 160). Thus, in one embodiment the riser constitutes
an active part of the fluid circulation system.
[0026] As noted above, the present invention provides a drilling
system for controlling wellbore pressure and controlling or
reducing the ECD effect during drilling fluid circulation or
drilling of subsea wellbores. To achieve the desired control of the
ECD, the present invention selectively adjusts the pressure
gradient of the fluid circulation system. One embodiment of the
present invention utilizes an arrangement wherein the flow of
return fluid is controlled (e.g., assisted) at a predetermined
elevation along the riser 160. An exemplary arrangement of such an
embodiment includes a flow restriction device 164 in the drilling
riser 160 and an actively controlled fluid lifting device 170.
[0027] Referring now to FIG. 2, an exemplary flow restriction
device 164 diverts return fluid flow from the riser 160 to the
fluid lifting device 170. Preferably, the flow restriction device
164 can move between a substantially open bore position (no flow
restriction) and a substantially closed bore position (substantial
flow restriction). It is also preferred that the flow restriction
device 164 accommodate both the axial sliding and rotation movement
of the drill string 121 when in the substantially closed position.
Accordingly, in a preferred embodiment of the flow restriction
device 164, upper and lower radial bearings 164A, 164B are used to
stabilize the drill string 121 during movement. Further, a
hydraulically actuated packer assembly 164D provides selective
obstruction of the bore of the riser 160. When energized with
hydraulic fluid via a hydraulic line 164G, the inflatable elements
of the packer assembly 164D expand to grip the drill string 121 and
thereby substantially divert return fluid flow 142 into the
diverter line 171. Intermediate elements such as concentric tubular
sleeve bearings (not shown) can be interposed between the packer
assembly 164D and the drill string 121. Additionally, a seal 164C
such as a rotary seal can be provide an additional barrier against
the flow of return fluid 142 through the flow restriction device
164. When de-energized, the packer assembly 164D disengages from
the drill string 121 and retracts toward the wall of the riser 160.
This retraction reduces the obstruction of the bore of the riser
160 and thereby enables large diameter equipment (not shown) to
cross the flow restriction device 164 while, for example, the drill
string 121 is tripped in and out of the riser 160. Preferably, the
flow restriction device 164 is positioned in a housing joint 164F,
which can be a slip joint housing. Elements such as the bearings
164A,B and seal 164C can be configured to reside permanently in the
housing joint 164F or mount on the drill string 121. In one
preferred arrangement, element that are subjected to relatively
high wear are positioned on the drill string 121 and changed out
when the drill string 121 is tripped. Furthermore, a certain
controlled clearance is preferably provided between the drill
string 121 and the flow restriction device 164 so that upset
portion of the drill string 121 (e.g., jointed connections) can
slide or pass through the flow restriction device 164.
[0028] The flow restriction device 164 may be adjustable from a
surface location via a control line 165, which allows the control
over the pressure differential through the riser. The depth at
which the flow restriction device 164 is installed will depend upon
the maximum desired reduction in the ECD. A depth of between 1000
ft to 3000 ft. is considered adequate for most subsea applications.
The returning fluid 142 in the riser 160 is diverted about the
restriction device 164 by a fluid lifting device, such as
centrifugal pump 170 coupled to a flow cross line or a diverter
line 171. The diverter line 171 is installed from a location below
the flow restriction device 164 to a location above the flow
restriction device 164. Thus, the lifting device 170 diverts the
returning fluid in the riser from below the flow restriction device
to above the flow restriction device 164. The fluid lifting device
170 is mounted on the exterior of the riser 160. To control the ECD
at a desired value, the pump speed (RPM) is controlled. Typically,
the energy input to (and thus the RPM of) the pump 170 is increased
as the fluid flow in the circulating path is increased and/or the
length of the circulating path increases with advancement of the
drill bit. Moreover, the energy input to (and thus the RPM of) the
lifting device is decreased as the return flow in the well 90 (FIG.
1) is decreased. In this configuration, the lifting device takes on
part of the work of pushing or lifting the drilling fluid back to
the surface from the restriction device location. The energy input
into the lifting device 170 (i.e. the work performed by the device)
results in reducing the hydrostatic pressure of the fluid column
below that point, which results in a corresponding reduction of the
pressure along the return path in the annulus below the lifting
device 170 and more specifically at the shoe 151 of the last casing
152. Any number of devices such as centrifugal pumps, turbines, jet
pumps, positive displacement pumps and the like can be suitable for
providing a pressure differential and associated control of ECD.
The terms active pressure differential device ("APD" device),
active fluid flow device and active fluid lifting device are
intended to encompass at least such devices, mechanisms and
arrangements.
[0029] Referring now to FIG. 1, in an alternative embodiment, the
flow restriction device 164 and the pump 170 may be installed at a
suitable location in the wellbore annulus, such as shown by arrow
175, or at the wellhead equipment 125. Also, the present invention
is equally applicable to under-balanced drilling systems since it
is capable of controlling the ECD effect to a desired level.
[0030] Referring now to FIGS. 1 and 2, the wellbore system 100
further includes a controller 180 at the surface that is adapted to
receive input or signals from a variety of sensors including those
in remote equipment such as the BHA 135. The system 100 includes
one or more pressure sensors, such as P.sub.1 and a host of other
sensors S.sub.1-7 that provide measurements relating to a variety
of drilling parameters, such as fluid flow rate, temperature,
weight-on bit, rate of penetration, etc., drilling assembly or BHA
parameters, such as vibration, stick slip, RPM, inclination,
direction, BHA location, etc. and formation or formation evaluation
parameters commonly referred to as measurement-while-drilling
parameters such as resistivity, acoustic, nuclear, NMR, etc.
Drilling fluid pressure measurements may also be obtained at
wellhead (P.sub.2) and at the surface (P.sub.3) or at any other
suitable location (P.sub.n) along the drill string 120. Further,
the status and condition of equipment as well as parameters
relating to ambient conditions (as well as pressure and other
parameters listed above) in the system 100 can be monitored by
sensors positioned throughout the system 100: exemplary locations
including at the surface (S1), at the fluid lifting device (S2), at
the wellhead equipment 125 (S3), at the fluid restriction device
164 (S4), near the casing shoe 151B (S5), at bottomhole assembly
(S6), and near the inlet to the active fluid lifting device 170
(S7). The data provided by these sensors are transmitted to the
controller 180 by a suitable telemetry system (not shown).
[0031] During drilling, the controller 180 receives the pressure
information from one or more of the sensors (P.sub.1-P.sub.n)
and/or information from other sensors (S.sub.1-S.sub.7) in the
system 100. The controller 180 determines the ECD and adjusts the
energy input to the lifting device 170 to maintain the ECD at a
desired or predetermined value or within a desired or predetermined
range. The controller 180 includes a microprocessor or a computer,
peripherals 184 and programs which are capable of making online
decisions regarding the control of the flow restriction device 164
and the energy input to the lifting device 170. A speed sensor
S.sub.2 may be used to determine the pump speed. Thus, the location
of the flow restriction device 164 and the pressure differential
about the restriction device controls the ECD. The wellbore system
100 thus provides a closed loop system for controlling the ECD by
controllably diverting the returning fluid about a flow restriction
device in the returning fluid path in response to one or more
parameters of interest during drilling of a wellbore. This system
is relatively simple and efficient and can be incorporated into new
or existing drilling systems.
[0032] Referring now to FIGS. 3A and 3B, there is graphically
illustrated the ECD control provided by the above-described
embodiment of the present invention. For convenience, FIG. 3A shows
the fluid lifting device 164 at a depth D1 and a representative
location in the wellbore such as the casing shoe 151 at a lower
depth D2. FIG. 3B provides a depth versus pressure graph having a
first curve C1 representative of a pressure gradient before
operation of the system 100 and a second curve C2 representative of
a pressure gradients during operation of the system 100. Curve C3
represents a theoretical curve wherein the ECD condition is not
present; i.e., when the well is static and not circulating and is
free of drill cuttings. It will be seen that a target or selected
pressure at depth D2 under curve C3 cannot be met with curve C1.
Advantageously, the system 100 reduces the hydrostatic pressure at
depth D1. and thus shifts the pressure gradient as shown by curve
C3, which can provide the desired predetermined pressure at depth
D2. This shift is roughly the pressure drop provided by the fluid
lifting device 170.
[0033] Referring now to FIG. 4, there is shown another embodiment
of the present invention that is suitable for dual gradient
drilling. Features the same as those in FIG. 1 are, for
convenience, referenced with the same numerals. The FIG. 4
embodiment includes a system 200 wherein the returning fluid 142 in
the riser 160 is diverted about the restriction device 164 by an
active pressure differential device 202 coupled to a flow cross
line or a diverter line 204. The diverter line 204 is installed at
a location below the flow restriction device 164. Thus, the active
pressure differential device 202 diverts the returning fluid 142 in
the riser 160 from below the flow restriction device 164 to the
surface. The active pressure differential device 202 is mounted
above the seabed and external to riser 160. The operation of the
active pressure differential device 202 creates a selected pressure
differential across the device 202. It also moves the returning
fluid 142 from just below the flow restriction device 164 and
discharges the diverted fluid into a separate return line 206,
which carries the fluid to the surface by bypassing the portion of
the riser 160 that is above the flow restriction device 164. FIG. 4
further illustrates a material 208, having a lower density than the
return fluid and obtained from a suitable source at or near the
surface, is maintained in the riser 160 uphole of restriction
device 164. The material 208 usually is seawater. However, a
suitable fluid could have a density less or greater than seawater.
The material 208 is used in providing a static pressure gradient to
the wellbore that is less than the pressure gradient formed by the
fluid downhole of the flow restriction device 164. Drilling is
performed in a similar manner to that described with respect to the
FIG. 1 embodiment except that the active pressure differential
device 202 discharges the return fluid 142 into the separate return
line 206 that may be external to the riser 160. Thereafter, the
return fluid 142 is discharged into the separator 24.
[0034] To achieve the desired reduction and/or control of the
bottomhole pressure or ECD, the system 200 utilizes a flow
restriction device 164 and active pressure differential device 202
in much the same manner as that described in reference to system
100 (FIG. 1). That is, briefly, the active pressure differential
device 202 provides lift to the return fluid, above its location
reducing the hydrostatic pressure of the fluid column below that
point. This results in a corresponding reduction of the pressure
along the return path and more specifically at the shoe 151 of the
last casing 152. Therefore, control of the active pressure
differential device allows for control of the wellbore pressure and
ECD.
[0035] Referring now to FIGS. 5A and 5B, there is graphically
illustrated the ECD control provided by the above-described
embodiment of the present invention. For convenience, FIG. 5A shows
the fluid lifting device 202 at a depth D3 and a representative
location in the wellbore such as the casing shoe 151 at a lower
depth D4. FIG. 5B provides a depth versus pressure chart having a
first curve C4 representative of a pressure gradient before
operation of the system 100 and a second curve C5 representative of
a pressure gradients during operation of the system 100. Curve C6
represents a theoretical curve wherein the ECD condition is not
present; i.e., when the well is static and not circulating and is
free of drill cuttings. The pressure gradient of the non-drilling
fluid material 208 (e.g., seawater) (FIG. 3) in riser is shown as
curve C7 and the pressure gradient of the drilling fluid in the
separate line 206 (FIG. 3) is shown as curve C8. It will be seen
that a target or selected pressure at depth D3 under curve C6
cannot be met with curve C4. Advantageously, the system 200 reduces
the hydrostatic pressure at depth D3 and thus shifts the pressure
gradient curve as shown by curve C5, which can provide the desired
predetermined pressure at depth D4. This shift is roughly the
pressure drop provided by the fluid lifting device 202.
[0036] Like the wellbore system 100 of FIG. 1, the system 200
includes a controller 180 that is adapted to receive input or
signals from a variety of sensors including those in the BHA 135.
For brevity, the details of the several associated components will
not be repeated. Further, also like system 100, the controller 180
of system 200 receives the pressure information from one or more of
the sensors (P.sub.1-P.sub.n) and/or information from other sensors
S1-S7 in the system 100. The controller 180 determines the
bottomhole pressure and adjusts the energy input to the pressure
differential device 202 to maintain the bottomhole pressure at a
desired or predetermined value or within a desired or predetermined
range. The wellbore system 200 thus provides a closed loop system
for controlling the ECD by controllably diverting the returning
fluid about a flow restriction device in the returning fluid path
in response to one or more parameters of interest during drilling
of a wellbore. This system is relatively simple and efficient and
can be incorporated into new or existing drilling systems.
[0037] While the foregoing disclosure is directed to the preferred
embodiments of the invention, various modifications will be
apparent to those skilled in the art. It is intended that all
variations within the scope and spirit of the appended claims be
embraced by the foregoing disclosure.
* * * * *