U.S. patent application number 10/772217 was filed with the patent office on 2007-05-31 for apparatus and methods for drilling a wellbore using casing.
This patent application is currently assigned to Weatherford/Lamb, Inc.. Invention is credited to Samir Alkhatib, William M. Beasley, David J. Brunnert, Gregory G. Galloway, Richard L. Giroux, Raymond H. Jackson, Tuong Thanh Le, Brent J. Lirette, Dave McKay, Gregory R. Nazzal, Albert C. Odell, James C. Swarr, Jim Terry, Mike Wardley.
Application Number | 20070119626 10/772217 |
Document ID | / |
Family ID | 46300777 |
Filed Date | 2007-05-31 |
United States Patent
Application |
20070119626 |
Kind Code |
A9 |
Giroux; Richard L. ; et
al. |
May 31, 2007 |
APPARATUS AND METHODS FOR DRILLING A WELLBORE USING CASING
Abstract
Apparatus and methods for drilling with casing. In an
embodiment, methods and apparatus for deflecting casing using a
diverter apparatus are disclosed. In another embodiment, the
apparatus comprises a motor operating system disposed in a motor
system housing, a shaft operatively connected to the motor
operating system, the shaft having a passageway, and a divert
assembly disposed to direct fluid flow selectively to the motor
operating system and the passageway in the shaft. In another
aspect, methods and apparatus for directionally drilling a casing
into the formation are disclosed. Methods and apparatus for
measuring the trajectory of a wellbore while directionally drilling
a casing into the formation are also described.
Inventors: |
Giroux; Richard L.;
(Cypress, TX) ; Galloway; Gregory G.; (Conroe,
TX) ; Le; Tuong Thanh; (Katy, TX) ; Jackson;
Raymond H.; (Spring, TX) ; Nazzal; Gregory R.;
(Kingwood, TX) ; Swarr; James C.; (The Woodlands,
TX) ; Brunnert; David J.; (Cypress, TX) ;
Beasley; William M.; (Waller, TX) ; Lirette; Brent
J.; (Houston, TX) ; Odell; Albert C.;
(Kingwood, TX) ; Terry; Jim; (Houston, TX)
; McKay; Dave; (Stonehaven, GB) ; Alkhatib;
Samir; (Aberdeen, GB) ; Wardley; Mike;
(Aberdeen, GB) |
Correspondence
Address: |
William B. Patterson;MOSER, PATTERSON & SHERIDAN, L.L.P.
3040 Post Oak Blvd. Suite 1500
Houston
TX
77056
US
|
Assignee: |
Weatherford/Lamb, Inc.
|
Prior
Publication: |
|
Document Identifier |
Publication Date |
|
US 20040245020 A1 US 20070056774 A9 |
March 15, 2007 |
|
|
Family ID: |
46300777 |
Appl. No.: |
10/772217 |
Filed: |
February 2, 2004 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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10257662 |
Mar 5, 2003 |
6848517 |
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PCT/GB01/01506 |
Apr 2, 2001 |
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10772217 |
Feb 2, 2004 |
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10331964 |
Dec 30, 2002 |
6857487 |
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10772217 |
Feb 2, 2004 |
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60444088 |
Jan 31, 2003 |
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60452202 |
Mar 5, 2003 |
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60452186 |
Mar 5, 2003 |
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60452317 |
Mar 5, 2003 |
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Current U.S.
Class: |
175/61 ;
175/171 |
Current CPC
Class: |
E21B 47/01 20130101;
E21B 10/61 20130101; E21B 33/14 20130101; E21B 43/105 20130101;
E21B 7/065 20130101; E21B 7/18 20130101; B05B 1/002 20180801; E21B
17/14 20130101; E21B 41/0078 20130101; E21B 2200/04 20200501; E21B
21/103 20130101; E21B 7/208 20130101; E21B 7/06 20130101 |
Class at
Publication: |
175/061 ;
175/171 |
International
Class: |
E21B 7/04 20060101
E21B007/04 |
Foreign Application Data
Date |
Code |
Application Number |
Apr 13, 2000 |
GB |
0008988.8 |
Claims
1. A method for preferentially directing a path of a casing to form
a wellbore, comprising: providing a second casing concentrically
disposed within a first casing; penetrating the first casing having
an earth removal member operatively connected thereto into a
formation to a first depth; releasing a releasable attachment
between the first and second casing; and selectively altering a
trajectory of the second casing while rotating the earth removal
member as the second casing continues into the formation.
2-3. (canceled)
4. The method of claim 1, further comprising diverting fluid flow
to a passageway through a motor system.
5. The method of claim 4, further comprising flowing a physically
alterable bonding material through the passageway to the earth
removal member.
6-21. (canceled)
22. The method of claim 1, wherein the first casing comprises a
biasing member to facilitate altering the trajectory of the
wellbore.
23. The method of claim 22, wherein the biasing member includes a
preferential jet for directing fluid flow asymmetrically through
the first casing while jetting.
24. The method of claim 22, wherein the biasing member includes a
stabilizing member disposed proximate to a midpoint of the first
casing.
25. The method of claim 22, further comprising diverting fluid flow
to a passageway through the a motor system.
26. The method of claim 25, further comprising flowing a physically
alterable bonding material through the passageway to the earth
removal member.
27. The method of claim 1, further comprising providing a motor
system releasably attached to an inner portion of the second
casing, the motor system adapted to rotate the earth removal
member.
28. The method of claim 27, further comprising providing a drilling
fluid to the motor system.
29. The method of claim 28, further comprising diverting the
drilling fluid to a passageway through the motor system.
30. The method of claim 27, further comprising: drilling the second
casing to a second depth; and expanding the second casing.
31. The method of daim 30, wherein expanding the second casing is
accomplished by retrieving the motor system from the second
casing.
32. The method of claim 27, further comprising retrieving the motor
system from the second casing.
33. The method of claim 27, further comprising selectively
introducing a surveying tool into the motor system to selectively
measure the trajectory of the wellbore.
34. The method of claim 33, wherein the surveying tool selectively
measures the trajectory of the wellbore while drilling with the
first or second casing.
35. An drilling assembly for directing a path of a wellbore,
comprising: an outer casing having a deflecting member for
deflecting a direction of the drilling assembly; an inner casing
having a motor system disposed therein, the inner casing disposed
within the outer casing and operatively attached thereto; and an
earth removal member operatively connected to a lower end of the
outer casing, wherein the earth removal member is rotatable by the
motor system.
36. The apparatus of claim 35, wherein the deflecting member
comprises an inclined wedge releasably attached to a lower portion
of the cutting apparatus.
37. The apparatus of claim 35, wherein the deflecting member
comprises an angled perforation through the lower portion of the
casing string for receiving a fluid.
38. The apparatus of claim 37, wherein the deflecting member
further comprises a bent portion in the casing string for
deflecting the casing string preferentially in a direction.
39. The apparatus of claim 35, wherein the deflecting member
comprises a second earth removal member larger in diameter than the
first earth removal member disposed on a portion of the casing
assembly above the first earth removal member.
40. The apparatus of claim 35, wherein the deflecting member
further comprising a landing seat for securing a survey tool
therein.
41. The apparatus of claim 35, wherein the earth removal member
includes at least one nozzle extending therethrough, the at least
one nozzle having an extended straight bore extending
longitudinally therethrough.
42. The apparatus of claim 41, wherein the at least one nozzle is
drillable.
43. The apparatus of claim 41, wherein the at least one nozzle
comprises a soft material.
44. The apparatus of claim 43, wherein the soft material is
copper.
45. The apparatus of claim 43, wherein the at least one nozzle
comprises a thin coating of a hard material, the hard material
having a hardness greater than a hardness of a soft material.
46. The apparatus of claim 45, wherein the hard material is
ceramic.
47. The apparatus of claim 45, wherein the hard material is
tungsten carbide.
48. The apparatus of claim 35, wherein the motor system is
releasable from the inner casing and retrievable therefrom.
49. The apparatus of claim 35, wherein the motor system comprises:
a motor operating system disposed in a motor system housing; a
shaft operatively connected to the motor operating system, the
shaft having a passageway; and a divert assembly disposed to direct
fluid flow selectively to the motor operating system and the
passageway in the shaft.
50. The apparatus of claim 49, further comprising a latch for
releasably latching the motor system onto the inner casing.
51. The apparatus of claim 49, wherein the divert assembly
comprises a closing sleeve having one or more ports, the closing
sleeve disposed in the shaft.
52. The apparatus of claim 49, wherein the divert assembly
comprises a rupture disk disposed to block fluid flow to the
passageway in the shaft.
53. The apparatus of claim 49, wherein the motor operating system
comprises a hydraulic system.
54. The apparatus of claim 49, wherein the motor operating system
comprises a system selected from a turbine system and a stator
system.
55. The apparatus of claim 49, wherein the earth removal member
includes a drill face and a spindle connected to the shaft.
56. The apparatus of claim 55, wherein the earth removal member
includes a fluid connection to the passageway in the shaft.
57. The apparatus of claim 56, wherein the earth removal member
includes a shut off mechanism for stopping fluid flow through the
fluid connection.
58. The apparatus of claim 49, further comprising a casing latch
attached to the motor system housing, the casing latch adapted to
releasably secure the motor system to an internal surface of the
inner casing.
59. The apparatus of claim 58, wherein the casing latch includes a
fluid passage connected to the passageway in the shaft.
60. The apparatus of claim 58, further comprising a guide assembly
connected to the casing latch, the guide assembly having one or
more seats for receiving a device selected from an inter string and
an orientation device.
61. The apparatus of claim 49, wherein the motor system housing
includes an enlargement portion for expanding a casing size.
62. A method of initiating and continuing a path of a wellbore,
comprising: providing a first casing having a first earth removal
member operatively disposed at a lower end thereof; penetrating a
formation with the first casing to form the wellbore; selectively
altering a trajectory of the wellbore while penetrating the
formation with the first casing; flowing drilling fluid to a motor
system disposed in a second casing, the second casing being
releasably attached to an inner diameter of the first casing and
having a second earth removal member; and rotating the second earth
removal member with the motor system.
63. The method of claim 62, wherein the trajectory of the second
casing is altered more than the trajectory of the first casing.
64. A method of altering a path of a casing into a formation,
comprising: providing an outer casing with a deflector releasably
attached to its lower end; penetrating the formation with the
deflector; releasing the deflector from the outer casing; and
deflecting the path of the outer casing in the formation by moving
the casing string along the deflector.
65. The method of claim 64, further comprising releasing an inner
casing from the outer casing.
66. The method of daim 65, further comprising flowing drilling
fluid to a motor system disposed within the inner casing to rotate
an earth removal member operatively attached to the motor system
while altering a trajectory of the inner casing drilling into the
formation.
67. The method of claim 1, wherein penetrating the first casing
into the formation comprises jetting the first casing.
68. The method of claim 1, further comprising measuring a
trajectory of the wellbore while drilling with the first or second
casing.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is a continuation-in-part of U.S. Patent
Application No. 10/257,662 filed on Apr. 2, 2001, which application
is herein incorporated by reference in its entirety. U.S. Patent
Application Ser. No. 10/257,662 is the national phase application
of PCT/GB01/01506 filed on Apr. 2, 2001.
[0002] This application claims benefit of U.S. Provisional Patent
Application Ser. No. 60/444,088 filed on Jan. 31, 2003, which
application is herein incorporated by reference in its entirety.
This application further claims benefit of U.S. Provisional Patent
Application Ser. No. 60/452,202 filed on Mar. 5, 2003, which
application is herein incorporated by reference in its entirety.
This application further claims benefit of U.S. Provisional Patent
Application Ser. No. 60/452,186 filed on Mar. 5, 2003, which
application is herein incorporated by reference in its entirety.
This application further claims benefit of U.S. Provisional Patent
Application Ser. No. 60/452,317 filed on Mar. 5, 2003, which
application is herein incorporated by reference in its
entirety.
BACKGROUND OF THE INVENTION
[0003] 1. Field of the Invention
[0004] Embodiments of the present invention generally relate to
methods and apparatus for drilling and completing a well. More
particularly, embodiments of the present invention relate to
methods and apparatus for directionally drilling with casing. Even
more particularly, embodiments of the present invention generally
relate to the field of well drilling, particularly to the field of
well drilling for the extraction of hydrocarbons from subsurface
formations, wherein the direction of the drilling of the wellbore
is steered and the need to determine the orientation of the drill
bit within the earth is present.
DESCRIPTION OF THE RELATED ART
[0005] In conventional well completion operations, a wellbore is
formed by drilling to access hydrocarbon-bearing formations.
Drilling is accomplished utilizing a drill bit which is mounted on
the end of a drill support member, commonly known as a drill
string. The drill string is often rotated by a top drive or a
rotary table on a surface platform or rig. Alternatively, the drill
bit may be rotated by a downhole motor mounted at a lower end of
the drill string. After drilling to a predetermined depth, the
drill string and drill bit are removed (e.g., pulled out), and a
section of the casing is lowered into the wellbore. An annular area
is formed between the string of casing and the formation, and a
cementing operation may then be conducted to fill the annular area
with cement. The combination of cement and casing strengthens the
wellbore and facilitates the isolation of certain areas of the
formation behind the casing for the production of hydrocarbons.
[0006] It is common to employ more than one string of casing in a
wellbore. Typically, the well is drilled to a first designated
depth with a drill bit on a drill string. The drill string is then
removed, and a first string of casing or conductor pipe is run into
the wellbore and set in the drilled out portion of the wellbore.
Cement is circulated into the annulus outside the casing string.
Next, the well is drilled to a second designated depth, and a
second string of casing or liner is run into the drilled out
portion of the wellbore. The second string is set at a depth such
that the upper portion of the second string of casing overlaps the
lower portion of the first string of casing. The second liner
string is fixed or hung off the first string of casing utilizing
slips to wedge against an interior surface of the first casing. The
second string of casing is then cemented. The process may be
repeated with additional casing strings until the well has been
drilled to a target depth. In this manner, wells are typically
formed with two or more strings of casing of an ever-decreasing
diameter.
[0007] As an alternative to the conventional method, a method of
drilling with casing is often utilized to position casing strings
of decreasing diameter within a wellbore. Drilling with casing
utilizes a cutting structure (e.g., drill bit or drill shoe)
attached to the lower end of the same casing string which will line
the wellbore. The entire casing string may be rotated by mechanical
devices at the surface, which ultimately rotates the drill bit so
that the drill bit drills into the formation. Once the well has
been drilled to the target depth with the casing in place, the
casing may be cemented to complete the well. Additional casing
strings may be run through the first casing string and drilled
further into the formation to form a wellbore of a second depth,
and this process may be completed with subsequent additional casing
strings. Drilling with casing is often the preferred method of well
completion because only one run-in of the working string into the
wellbore is necessary to form and line the wellbore.
[0008] Drilling with casing is useful in drilling and lining a
subsea wellbore, particularly in a deep water well completion
operation. When forming a subsea wellbore, the length of wellbore
that has been drilled with a drill string is subject to potential
collapse because of the soft formations present at the ocean floor.
Also, sections of the wellbore intersecting regions of high
pressure can cause damage to the drilled wellbore during the time
lapse between the formation of the wellbore and the lining of the
wellbore. Drilling with casing removes such time lapses and
alleviates these problems.
[0009] An alternative drilling with casing method which is
sometimes practiced instead of rotating the casing string to drill
into the formation involves "jetting" or pushing the casing into
the formation. Because hydraulic energy from nozzles in a drill bit
is often sufficient to remove the formation without using bit
cutters, it is often necessary to jet the pipe into the ground by
forcing pressurized fluid through the inner diameter of the casing
string concurrent with lowering the casing string into the
wellbore. The fluid and the mud are thus forced to flow upward
outside the casing string, so that the casing string remains
essentially hollow to receive the casing strings of decreasing
diameter which contribute to lining the wellbore. To accomplish
jetting of the pipe, holes or nozzles may be formed through the
lower end of the drill bit to allow fluid flow through the casing
string and up into the annular space between the outside of the
casing string and the wellbore. The holes may be essentially
symmetric with respect to the drill bit so that a uniform amount of
fluid is released along the diameter of the casing string.
[0010] In a further alternate drilling with casing method, a motor
and a drill bit may be attached to a drill pipe and positioned at a
terminal portion of the first casing string to allow rotational
drilling of the casing string into the formation if desired, as
well as allowing jetting by lowering the casing string into the
formation to continue. The drill bit may be rotated while the first
casing string is lowered into the formation to facilitate drilling
the first casing string to a desired depth. Upon reaching the
desired depth, the drill bit and the drill pipe may continue to
drill down to a target depth to enable placement of the second
casing string. When casing string reaches the target depth, the
drill pipe, motor, and drill bit are pulled out of the wellbore
while the casing string remains within the wellbore prior to
cementing the casing string into the wellbore. The second casing
string is run in and placed in the wellbore at the target depth,
the motor system retrieved, and then the second casing string is
cemented therein. Additional cost and time for completing a
wellbore are inherent results of the current drilling with casing
operation because the motor system must be retrieved from the
wellbore prior to the cementing operation.
[0011] For various reasons, it may be necessary to deviate from the
natural (e.g., substantially vertical) direction of the wellbore
and drill a deviated hole. Drilling with casing techniques may also
be utilized to drill a deviated hole, commonly referred to as
"directional drilling with casing."
[0012] In subsea drilling operations, a drilling platform is
supported by the subterranean formation at the bottom of a body of
water. The drilling platform is the surface from which the casing
sections and strings, cutting structures, and other supplies are
lowered to form a subterranean wellbore lined with casing. Each
drilling platform represents a relatively significant cost. Also,
governmental regulations allow only a limited number of platforms
over a given surface area of the body of water. Accordingly,
platforms must be spaced a predetermined distance apart for
drilling subterranean wellbores. Additionally, each platform must
only occupy a specified area of the surface of the body of water.
Because only a certain number of platforms of a given dimension are
allowed over a given surface area and because of the possibly
prohibitive economic cost of multiple platforms, the number of
wellbores drilled into the subterranean formation should be the
maximum amount of wellbores which can be drilled into the
subterranean formation from the permitted platforms. In this
manner, hydrocarbon production is maximized, because increasing the
producing wells increases the hydrocarbons obtainable at the
surface of the wellbore. Each wellbore formed is therefore valuable
as an independent producing well which directly increases
production from the hydrocarbon source.
[0013] A common problem with drilling subsea wellbores is
encountered due to the attempt to maximize hydrocarbon production
by maximizing the number of wellbores drilled from slots in a
platform of limited surface area. To drill the maximum amount of
wells, the slots in the platform must exist at extremely close
proximity to one another. The closer the proximity of the slots to
one another, the more wellbores which can be drilled over a given
surface area. Unfortunately, drilling the wellbores through the
slots which are so close to one another leaves little room for even
small directional deviations when the wellbore is not drilled
directly downward into the subsea formation. Sometimes, the
wellbores are accidentally deflected and drilled into one another,
causing the wellbores to intersect. When two or more wellbores
intersect, at least one wellbore is eliminated as an independent
hydrocarbon production source. Thus, the allowed drilling area from
the platform is reduced, causing a decrease in the production of
hydrocarbons from the subsea formation.
[0014] To avoid the intersection of wellbores, the wellbores are
often drilled at an angle from the slots in the platform. The
wellbores drilled from the outermost slots on the platform are
typically drilled at an angle outward from the platform, and the
outward angle decreases progressively for the inward slots. Thus,
wellbores should deviate slightly away from other wellbores to
avoid interference with one another. Other instances exist when it
would be desirable to directionally drill a wellbore, such as when
drilling at an angle is necessary to reach a production zone.
[0015] Various methods of deviated drilling or nudging are
currently practiced. One method involves pre-drilling a hole
directionally with a drill bit on a drill string. In this method, a
wellbore is drilled into the formation at an angle. The drill
string is then removed and a string of casing placed into the
pre-drilled hole. This method fails to prevent caving in of the
wellbore between the time in which the hole is drilled and the time
in which the casing is inserted into the wellbore. Moreover, the
increased time and expense inherent in running the drill string and
the casing string into the wellbore separately are disadvantages of
this method.
[0016] Another method to accomplish the deviation involves first
drilling a pilot hole which is smaller in diameter than the desired
wellbore and angled in the desired direction. The hole is then
enlarged to subsequently run the casing therethrough. This method
involves at least two run-ins of the drill string to drill two
holes of different diameter, increasing time, expense, and wellbore
collapse potential.
[0017] There is a need, therefore, for apparatus and methods which
are effective for drilling the casing into the formation in subsea
well completion operations. There is a further need for nudging
methods and apparatus which effectively deviate the subterranean
wellbore while drilling the string of casing into the formation to
prevent intersection of the wellbores.
[0018] Additionally, with the current drilling systems, drilling
tools and casing strings need to be run and/or retrieved a
plurality of times into and/or out of the wellbore to complete
drilling, casing, casing expansion, and cementing operations,
resulting in substantial costs and length of time for completing a
well. Therefore, there is a need for an apparatus and method for
performing drilling, casing, expansion, and cementing operations
which substantially reduce the time and costs for completing a
well. Particularly, there is a need for an apparatus and method for
performing a drilling operation while casing the wellbore which
allows a cement operation to be performed subsequently without
having to first retrieve the motor system utilized for the drilling
operation. Additionally, it would be desirable for the apparatus to
be able to perform these operations in a variety of settings
utilizing different equipment and tools. It would be desirable for
the apparatus to perform deviated drilling or nudging operations
which produce deviated wells.
[0019] As an alternate technique of drilling with casing which may
be utilized instead of merely attaching a cutting structure to the
casing, a bottomhole assembly ("BHA") having a drill bit may be
lowered into the formation with a casing. The drill bit is exposed
through the lower end of the casing, and the BHA is secured to a
bottom portion of the inner diameter of the casing. After lowering
the casing into the formation, the drill bit is rotated either in a
rotary mode by rotating the casing (e.g., utilizing the casing as a
drill string) or in a slide mode by rotating the bit independently
of the casing with a downhole drill motor. In either case, as the
wellbore is extended, additional lengths of casing are added to the
wellbore from the surface as the casing string advances with the
wellbore.
[0020] FIG. 32 illustrates a conventional system for directional
drilling with casing using a BHA 3100. As illustrated, the BHA 3100
with a pilot drill bit 3108 is typically run through the casing
3104 (lining a wellbore 3102) and secured to a bottom portion of
the casing 3104 with a casing latch 3106. As previously described,
the BHA 3100 may be operated in a rotary mode, by rotating the
casing from the surface of the wellbore. As an alternative, the BHA
3100 may include a downhole motor 3112 above the pilot bit 3108. As
illustrated, the motor 3112 may be integral with a bent subassembly
(or housing) 3114 to bias the pilot in the desired deviated
direction (thus, the motor 3112 is commonly referred to as a "bent
housing motor"). The deviated hole is drilled by adjusting the bent
subassembly 3114 to point the pilot bit 3108 in the desired
deviated direction. The trajectory of the deviated hole is
typically dictated by the curvature that passes through the centers
of the pilot bit 3108, the bend in the motor 3112, and the casing
latch 3106.
[0021] The deviated wellbore must be larger than the outside
diameter of the casing 3104 to allow the casing to advance as the
wellbore is extended. This is typically accomplished by utilizing
an underreamer 3110 to enlarge a pilot hole drilled with the pilot
bit 3108. In other words, as the motor 3112 is operated, the pilot
bit 3108 is rotated forming the pilot hole, which is then enlarged
by the underreamer 3110 following behind. To run the BHA 3100
through the casing 3104, expandable blades of the underreamer 3110
may be placed in a retracted position. The blades may be expanded
prior to drilling the deviated hole and again retracted to retrieve
the BHA 3100, through the casing 3104, after drilling. The BHA 3100
may also include sensing equipment 3109, commonly referred to as a
logging-while-drilling (LWD) or measuring-while-drilling (MWD), to
take trajectory measurements (e.g., inclination and azimuth) and
possibly formation measurements (e.g., resistivity, porosity,
gamma, density, etc.) at several points along the wellbore which
may be later used to approximate the wellbore path. MWD equipment
usually contains the wellbore surveying sensors, while LWD
equipment usually contains formation logging sensors.
[0022] The typical BHA 3100, when connected to the casing 3104 with
the casing latch 3106, extends about 90 to 100 feet below the lower
end of the casing 3104. The extension of the BHA 3100 below the
casing 3104 allows the pilot drill bit 3108 to form a rat hole
(extended wellbore) below the lower end of the casing 3104. The rat
hole has a diameter larger than the outer diameter of the casing
3104 due to the underreamer 3110. In the typical directional
drilling process utilizing the BHA 3100, the pilot bit 3108 is
rotated to drill directionally the casing 3104 into a formation.
The casing 3104 is then released from engagement with the casing
latch 3106 of the BHA 3100, and the casing 3104 is lowered over the
BHA 3100 to the bottom of the rat hole. The BHA 3100 is eventually
removed from the wellbore, and the casing 3104 is left in the
wellbore.
[0023] The rat hole formation step and the step of lowering the
casing 3104 over the BHA 3100 are required when using the current
system of drilling with casing 3104 using a BHA 3100 because the
bent housing 3114 must have a bend extending below the casing 3104
sufficient to introduce the desired trajectory into the deviated
hole. Thus, the directional force for drilling the directional
wellbore is supplied by the motor 3112 bend of the bent housing
3114 of the BHA 3100, as the bent housing motor 3112 pushes
directly on and against the side of the wellbore. Because the bent
housing motor 3112 pushes against the side of the wellbore, a
resultant force is caused on the opposite side, of the underreamer
3110 and pilot drill bit 3108.
[0024] While the system illustrated in FIG. 32 may allow for the
drilling of a deviated wellbore without removing casing, the system
suffers a number of disadvantages. As an example, one disadvantage
arises due to a lack of proper support between the casing latch
3106 and the point of contact of the pilot bit 3108. As the typical
length between the casing latch 3106 and the pilot bit 3108 may be
in the range of between 40 feet to 120 feet, the BHA 3100 may
buckle and lean towards a lower end of the deviated hole as
downward force (i.e., "weight on bit") is applied from the surface.
This leaning is difficult to control and can severely affect the
intended curvature and trajectory of the deviated hole. Further,
without proper support, excessive lateral and axial vibrations in
the BHA 3100 may reduce removal rate, reduce operating lifetime,
and/or cause damage to the various components of the BHA 3110,
particularly when drilling in rotary mode.
[0025] A further disadvantage of the system of FIG. 32 lies in the
large length of the rat hole drilled below the lower end of the
casing 3104, into which the casing 3104 must be lowered over the
BHA 3100. Lowering the casing 3104 over the BHA 3100 in the 90-100
foot rat hole adds an extra step to the directional drilling with
casing operation. Additionally, the system places unnecessary
directional force directly on the BHA 3100. Still another
disadvantage in conventional drilling with casing systems is that
the MWD 3109 does not provide real time survey information and,
thus, the trajectory of the deviated hole can only be verified
after drilling. This is unfortunate because real time feedback
regarding the trajectory of the wellbore as it is being extended
could be used to control the drilling process (e.g., adjust
rotation speed of the bit, weight-on-bit, steer a rotary-steerable
assembly or downhole motor, etc.), to control the trajectory of the
wellbore.
[0026] When directionally drilling with a drill string, as the well
is drilled, the bore direction must be checked or monitored, to
ensure that the bore direction is not deviating from its intended
direction. Such monitoring is typically provided by positioning a
survey tool in a downhole location, in a rotationally fixed or
known position, and monitoring signals therefrom to determine the
orientation of the drill string in the earth. Where the drill
string is pulled from the well after the wellbore is drilled, and
the well is then cased, this is easily accomplished by fixing the
survey tool in a subassembly in the drill string, and thus the
survey tool is continuously in the borehole when the drill bit is
at the bottom of the hole. However, where the drill string is later
used as the casing, this is not practicable because the orientation
tool is expensive, and therefore it is undesirable to abandon it in
the well. Also, the survey tool, if left in the well, would create
an obstruction to well fluid recovery, or for the passage of an
additional drilling element therepast and thence through the end of
the casing to continue drilling the borehole to greater extent, and
thus would need to be drilled or milled out of the bore hole.
Therefore, there exists a need in the art for a mechanism to
provide downhole orientation tools in situations where the drill
string is subsequently used, in situ, as the well casing, without
creating an undue impediment to well fluid recovery, and without
the economic consequences of leaving the survey tool in the hole
after the well is complete.
SUMMARY OF THE INVENTION
[0027] Embodiments of the invention provide systems and methods for
performing drilling, casing, and cementing operations which
substantially reduce the time and costs for completing a well. More
particularly, embodiments of the invention provide systems and
methods for performing a drilling operation while casing the
wellbore which allows a cement operation to be performed
subsequently without having to first retrieve the motor system
utilized for the drilling operation.
[0028] In one aspect, embodiments of the present invention provide
a method for directing a trajectory of a lined wellbore comprising
providing a drilling assembly comprising a wellbore lining conduit
and an earth removal member, directionally biasing the drilling
assembly while operating the earth removal member and lowering the
wellbore lining conduit into the earth, and leaving the wellbore
lining conduit in a wellbore created by the biasing, operating and
lowering.
[0029] Embodiments of the invention are capable of performing these
operations in a variety of settings utilizing different equipment
and tools and perform deviated drilling or nudging operations which
produce deviated wells. For example, embodiments of the invention
may be utilized with an inter string, a bent pup joint, an
orientation device, or without such tool. Furthermore, the
apparatus may be utilized to perform a casing expansion operation
concurrently with the retrieval of the motor system utilized for
the drilling operation.
[0030] In one embodiment, an apparatus for drilling is provided.
The apparatus comprises a motor operating system disposed in a
motor system housing, a shaft operatively connected to the motor
operating system, the shaft having a passageway, and a divert
assembly disposed to direct fluid flow selectively to the motor
operating system and the passageway in the shaft. The divert
assembly facilitates switching of fluid flow to the motor operating
system during a drilling operation and fluid flow through the
passageway in the motor system during a cementing operation such
that the motor system need not be removed to perform a cementing
operation for the well.
[0031] Another embodiment provides an apparatus for drilling with
casing, comprising a casing, a motor system retrievably disposed in
the casing, and a drill face operably connected to shaft of the
motor system. The motor system comprises a motor operating system
disposed in a motor system housing; a shaft operatively connected
to the motor operating system, the shaft having a passageway; and a
divert assembly disposed to direct fluid flow selectively to the
motor operating system and the passageway in the shaft.
[0032] In another embodiment, a method for drilling and completing
a well is provided. The method comprises pumping drilling fluid or
drill mud to a motor system disposed in a casing; rotating an earth
removal member, preferably a drill face, connected to the motor
system; diverting fluid flow to a passageway through the motor
system; and pumping cement through the passageway to the drill
face. The motor system may be retrieved after the cement operation,
and a casing expansion operation may be performed while retrieving
the motor system.
[0033] An additional aspect of the present invention involves a
method of initiating and continuing the formation of a wellbore by
selectively altering the path of the casing string inserted into
the formation as it travels downward into the formation. In one
embodiment, the diverting apparatus comprises the casing string and
cutting apparatus, along with a bend introduced into the casing
string which influences the casing string to follow the general
direction of the bend when forming a wellbore.
[0034] In another embodiment, the diverting apparatus comprises the
casing string and cutting apparatus, as well as a diverter in the
form of an inclined wedge releasably attached to a lower end of the
casing string. In yet another embodiment, the diverting apparatus
comprises the casing string, the cutting apparatus, and a fluid
deflector. The diverting apparatus in yet another embodiment
comprises the casing string, the cutting apparatus, the fluid
deflector, and pads placed on the outer diameter of the casing
string.
[0035] Another embodiment of the diverting apparatus also involves
diverting fluid. In yet another embodiment, the diverting apparatus
comprises the casing string, the cutting apparatus, and a second
cutting apparatus disposed on the outer diameter of a portion of
the casing string above the cutting apparatus.
[0036] A further aspect of the present invention is an apparatus
and method for use with the diverting apparatus embodiments. The
diverting apparatus is releasably connected to a drilling
apparatus. In operation, after the wellbore path has been diverted
by the diverting apparatus, the releasable connection between the
drilling apparatus and the diverting apparatus is released. The
drilling apparatus is then pulled upward to drill through the inner
diameter of the casing string to remove any obstructions present
inside the casing string which were previously used to divert the
wellbore. Additional casing strings may then be hung off of the
casing string, and further operations may then be conducted through
the casing string. An even further aspect of the present invention
involves a method and apparatus for surveying the path of the
wellbore while penetrating the formation with the casing string to
form the wellbore.
[0037] One embodiment provides a drilling assembly for extending a
wellbore, the drilling assembly adapted to be run through casing
lining the wellbore. The drilling assembly generally includes a
casing latch for securing the drilling assembly to the casing, a
bit attached to a bottom portion of the drilling assembly, a
biasing member for providing the bit with a desired deviation from
a center line of the wellbore, and at least one adjustable
stabilizer for supporting the drilling assembly between the casing
latch and the bit.
[0038] Another embodiment provides a drilling assembly for
extending a wellbore, the drilling assembly attachable to casing
lining the wellbore. The drilling assembly generally includes a bit
disposed on a bottom portion of the drilling assembly, the bit
adapted to be expanded from a first position for running through
the casing to a second position for drilling a hole below the
casing, the hole having a greater diameter than an outer diameter
of the casing, and at least one stabilizer positioned between the
bit and the bottom portion of the casing, the stabilizer adapted to
be adjusted from a first position for running through a casing
lining the wellbore to a second position for engaging an inner
surface of the wellbore.
[0039] Another embodiment provides a method for drilling with
casing. The method generally includes lowering a drilling assembly
down a wellbore through casing, the drilling assembly comprising an
adjustable stabilizer and one or more drilling elements, adjusting
one or more support members of the stabilizer to increase a
diameter of the stabilizer, and operating the drilling assembly to
extend a portion of the wellbore below the casing, the extended
portion having a diameter greater than an outer diameter of the
casing.
[0040] The present invention generally provides methods and
apparatus for positioning a downhole tool, such as a survey tool,
in a downhole location in a fixed position relative to the drill
string, both with respect to the distance between the survey tool
and the drill bit, as well as the rotational alignment or
orientation of the tool to the drill string and drill bit
structure, and the capability to retrieve such tool before the well
is used for production. In one embodiment, the drill string is
provided with a drillable float sub, which includes an orientation
member therein into which a survey tool, such as an orientation
tool, is received in a known orientation when the survey tool is
positioned in a downhole location within such drill string, and
which is also useable as a cement float shoe, for traditional
cementing operation to cement the casing in place in the borehole.
The survey tool is thereby orientable in the drill string to enable
meaningful orientation survey of the drill bit and bore
orientation, either on a sampling or continuous basis. In another
aspect, the survey tool may communicate information relating to
orientation to the surface using via mud pulse telemetry, or other
methods known to a person of ordinary skill in the art.
[0041] In a further embodiment, the float sub includes a muleshoe
profile which receives a mating muleshoe profile of the survey
tool. The muleshoe profile is positioned in a sleeve, into which
the survey tool may be positioned, such that the muleshoe profile
on the survey tool will align on the muleshoe profile of the float
sub, thereby orienting the survey tool in the drill string. In a
still further embodiment, the mule shoe profile of the float sub
may include a secondary alignment member, to enable the landing of
survey tools therein which do not include such mule shoe
profile.
BRIEF DESCRIPTION OF THE PREFERRED EMBODIMENT
[0042] So that the manner in which the above recited features of
the present invention can be understood in detail, a more
particular description of the invention, briefly summarized above,
may be had by reference to embodiments, some of which are
illustrated in the appended drawings. It is to be noted, however,
that the appended drawings illustrate only typical embodiments of
this invention and are therefore not to be considered limiting of
its scope, for the invention may admit to other equally effective
embodiments.
[0043] FIG. 1 is a schematic view of one embodiment of a system for
drilling and completing a well in a formation under water.
[0044] FIGS. 2A and 2B show a cross-sectional view of one
embodiment of a hollow shaft motor drilling system disposed in a
casing.
[0045] FIG. 3 is a cross-sectional view of one embodiment of a
hollow shaft motor drilling system illustrating a fluid divert
operation.
[0046] FIG. 4 is a partial cross-sectional view of one embodiment
of the divert system of FIG. 3.
[0047] FIG. 5 is a cross-sectional view of one embodiment of a
hollow shaft motor drilling system illustrating a cementing
operation.
[0048] FIG. 6 is a cross-sectional view of one embodiment of a
hollow shaft motor drilling system illustrating a system retrieval
operation.
[0049] FIG. 7 illustrates one embodiment of the drill system which
may be utilized for a drilling and casing operation in which casing
may be added during the operation.
[0050] FIG. 8 is a cross-sectional view of one embodiment of a
hollow shaft motor drilling system illustrating a drilling
operation utilizing a bent pup joint.
[0051] FIG. 9 is a cross-sectional view of one embodiment of a
hollow shaft motor drilling system illustrating a drilling
operation utilizing a bent pup joint and an inter string.
[0052] FIG. 10 is a cross-sectional view of one embodiment of a
hollow shaft motor drilling system illustrating a surveying
operation.
[0053] FIG. 11 is a cross-sectional view of one embodiment of a
hollow shaft motor drilling system disposed in an expandable
casing.
[0054] FIG. 12 is a cross-sectional view of one embodiment of a
hollow shaft motor drilling system disposed in an expandable casing
illustrating an operation for expanding the casing after
cementing.
[0055] FIG. 13 is cross-sectional view of an embodiment of a
diverting apparatus of the present invention disposed within a
subterranean wellbore. A diverter is located below a casing with an
earth removal member attached thereto.
[0056] FIG. 14 is a cross-sectional view of an alternate embodiment
of a diverting apparatus of the present invention disposed within a
subterranean wellbore. A fluid deflector is disposed within the
earth removal member attached to the casing.
[0057] FIG. 15 is a cross-sectional view of an alternate embodiment
of the diverting apparatus of FIG. 14 disposed within a
subterranean wellbore. Stabilizer pads are disposed on the outer
diameter of the casing.
[0058] FIG. 16 is a cross-sectional view of a further alternate
embodiment of a diverting apparatus of the present invention
disposed within a subterranean wellbore. A cutting apparatus in the
form of an elongated coupling extends outward from the outer
diameter of the casing. The right side of the casing axis in FIG.
16 is cut away to show a threadable connection.
[0059] FIG. 17 shows an alternate embodiment of the diverting
apparatus of the present invention having an eccentric stabilizer
disposed thereon.
[0060] FIG. 18 is a cross-sectional view of a drilling apparatus
for use with the diverting apparatus of the present invention in
the run-in configuration. The drilling apparatus is shown after
drilling a wellbore into the formation.
[0061] FIG. 19 is a cross-sectional view of the drilling apparatus
of FIG. 18 drilling through the diverting apparatus upon removal
from the wellbore.
[0062] FIG. 20 is a cross-sectional view of the drilling apparatus
of FIG. 18 upon removal of the drilling apparatus after drilling
through the diverting apparatus.
[0063] FIGS. 21 and 22 illustrate a process for drilling through
casing.
[0064] FIGS. 23A and 23B are perspective views of first and second
ends of an embodiment of a drillable nozzle.
[0065] FIGS. 24A and 24B are perspective view of first and second
ends of an alternative embodiment of a drillable nozzle.
[0066] FIG. 25 is a section view of a first embodiment of a nozzle
assembly disposed in a tool body.
[0067] FIG. 26 is a section view of a second embodiment of a nozzle
assembly disposed in a tool body.
[0068] FIGS. 27 is a section view of a third embodiment of a nozzle
assembly disposed in a tool body.
[0069] FIGS. 28 is a section view of a fourth embodiment of a
nozzle assembly disposed in a tool body.
[0070] FIG. 29 is a section view of a tool body having nozzle
assemblies disposed therein for drilling with casing.
[0071] FIG. 30 is a cross-sectional view of a lower end of an earth
removal member having fluid passages therethrough.
[0072] FIG. 31 is a section view of a casing string capable of use
in the present invention.
[0073] FIG. 32 illustrates an exemplary system for directional
drilling according to the prior art.
[0074] FIGS. 33A-D illustrate a system for directional drilling
according to an embodiment of the present invention.
[0075] FIG. 34 is a flow diagram illustrating exemplary operations
for directional drilling with casing according to an embodiment of
the present invention.
[0076] FIG. 35 shows a sectional view of an alternate embodiment of
a system for directional drilling with casing according to the
present invention. An eccentric casing bias pad is shown on
casing.
[0077] FIG. 36 shows a sectional view of a further alternate
embodiment of a system for directional drilling with casing.
[0078] FIG. 37 is a crosssectional view of another embodiment of a
directional drilling assembly equipped with an articulating
housing.
[0079] FIGS. 38A-B show an exemplary articulating housing according
to aspects of the present invention.
[0080] FIG. 39 shows another embodiment of a directional drilling
assembly.
[0081] FIG. 40 shows the directional drilling assembly of FIG. 45
after the BHA has reached the bottom of the wellbore.
[0082] FIG. 41 shows the directional drilling assembly of FIG. 45
in operation.
[0083] FIG. 42 is a schematic view, in section, of a directional
borehole being drilled.
[0084] FIG. 43 is a sectional view of a float sub in a downhole
location indicated in FIG. 42 and a sectional view of a survey tool
receivable therein..
[0085] FIG. 43A shows a side view of the survey tool of FIG.
43.
[0086] FIG. 44 is a sectional view of the float sub of FIG. 43,
showing a survey tool in section, received and landed therein.
[0087] FIG. 45 is a sectional view of a float sub as in FIG. 44,
showing an alternative embodiment of a survey tool shown partially
in section to be received therein.
[0088] FIG. 46 is a partial sectional view of the float sub of FIG.
45, showing the survey tool in and landed on the float sub.
[0089] FIG. 47 shows a partial view of a float sub having a
wellbore survey tool or sensor disposed therein.
[0090] FIG. 48 shows an embodiment of a survey tool assembly
according to aspects of the present invention.
[0091] FIG. 49 shows the survey tool assembly of FIG. 48 in the
survey mode.
[0092] FIG. 50 shows the survey tool assembly of FIG. 48 in the
drilling mode.
[0093] FIG. 51 shows the bypass valve of the survey tool assembly
of FIG. 48 in the closed position.
[0094] FIG. 52 shows the bypass valve of the survey tool assembly
of FIG. 48 in the open position.
[0095] FIG. 53A is a sectional elevation of an earth boring bit
nozzle.
[0096] FIG. 53B is a sectional view through the section y--y of
FIG. 53A.
[0097] FIG. 54 shows an alternate embodiment of a bit nozzle made
substantially of a non-metallic metal.
[0098] FIG. 55 shows a cross-sectional view of an alternate
embodiment of a diverting apparatus disposed within a subterranean
wellbore for use in directional drilling.
[0099] FIG. 56A is a cross-sectional view of a diverting apparatus
used for expanding a casing.
[0100] FIG. 56B is a cross-sectional view of the diverting
apparatus of FIG. 56A in the process of expanding the casing.
[0101] FIG. 57 is an upward sectional view of an earth removal
member for use in the present invention.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT
[0102] In the following embodiments of the present invention, the
casing may be alternately jetted and rotated to form a wellbore.
The rotation of the casing string may be accomplished either by
rotating the entire casing or by rotating the cutting structure
relative to the casing using a mud motor operatively attached to
the casing.
[0103] Embodiments of the present invention provide systems and
methods for performing drilling with casing operations which
substantially reduce the time and costs for completing a well. More
particularly, some embodiments of the present invention provide
systems and methods for performing a drilling operation while
casing the wellbore which allows a cement operation to be performed
subsequently without having to first retrieve the motor system
utilized for the drilling operation.
[0104] FIG. 1 is a schematic view of one embodiment of a system 100
for drilling and completing a well in a formation 112 under water
108. Although the system 100 is shown in context of a deep sea
drilling operation, embodiments of the invention may be utilized in
drilling operations on land as well as under water 108. As shown in
FIG. 1, the system 100 includes a first, outer casing 185, a
second, inner casing 195, and a drilling system 157. The inner
casing 195 is releasably connected, preferably releasably latched,
onto the outer casing 185, and the drilling system 157 is
releasably connected, preferably releasably latched, in the inner
casing 195. The drilling system 157 includes an earth removal
member, preferably in the form of a drill bit or drill shoe 167
which protrudes outside a terminal portion 147 of the outer casing
185. An inter string or drill string 165 connects the drilling
system 157 to a ship or platform 155 at the surface of water 108.
The system 100 may be utilized to drill and case a well in the
formation 112 under the sea floor or mud line 160.
[0105] Typically, casing 185 or 195 is made up of sections of
casing. Each section of casing has a pin end and a box end for
threadedly connecting to another section of casing above and/or
below the casing section. A casing string includes more than one
section of casing threadedly connected to one another. As used
herein, casing may include a section of casing or a string of
casing.
[0106] FIGS. 2A and 2B show a cross-sectional view of one
embodiment of a hollow shaft motor drilling system 200 disposed in
a casing 219. The hollow shaft motor drilling system 200
illustrates one embodiment of the drilling system 157, and the
casing 219 is representative of the second casing 195. The hollow
shaft motor drilling system 200 generally comprises a casing latch
211, a hollow shaft motor 221, and a drill shoe 270. The hollow
shaft motor drilling system 200 may include a guide assembly 203
attached to the casing latch 211. In one embodiment, the guide
assembly 203 includes a conical portion 204 and a tubular portion
206. The conical portion 204 guides mechanical devices run in from
the surface or drilling fluid or drill mud into the tubular portion
206. Such mechanical devices may include an inter string or drill
string 207, a closing ball, a latching dart 286 (see FIGS. 5 and
6), and other devices attached to a wireline. The tubular portion
206 also provides a plurality of receptacle seats such as a spear
seat 208 for receiving a stinger attached to an inter string 207
and a orientation tool landing seat 209 for receiving an
orientation tool for performing a survey. The tubular portion 206
is attached to the casing latch 211 and provides a fluid passageway
which connects to a fluid passageway in the casing latch 211.
[0107] The casing latch 211 is fixedly attached to the hollow shaft
motor 221 and provides a mechanism for securing the hollow shaft
motor drilling system 200 against an interior surface of the casing
219. In one embodiment, the casing latch 211 includes a set of
gripping members, preferably retractable slips 212, disposed
between an upper body 214 and a lower body 216. The lower body 216
includes one or more angled surfaces 218 which urge the slips 212
outwardly when the slips 212 are pushed against the angled surfaces
218. A locking mechanism, preferably a locking ring 213, is
utilized to keep the slips 212 in the set position against the
interior surface of the casing 219 once the slips 212 are extended.
The locking ring 213 may be spring loaded by a coil spring 222 and
released from a locking position by breaking one or more release
shear pins 224.
[0108] An upper cup seal assembly 226 is disposed on an outer
surface of the upper body 214 to provide a seal between the casing
latch 211 and the casing 219. The casing latch 211 includes an
axial tube 228 which provides a fluid passageway through the casing
latch 211 to the hollow shaft motor 221. One or more bypass ports
217 may be disposed on the axial tube 228 and on the upper body 214
to facilitate fluid flow (e.g., drilling fluid or drill mud) during
retrieval of the hollow shaft motor drilling system 200. The lower
body 216 of the casing latch 211 is attached to the hollow shaft
motor 221.
[0109] The hollow shaft motor 221 provides the mechanism for
rotating the drilling member 270 (e.g., a rotating drill face on a
drill shoe). In one embodiment, the hollow shaft motor 221 includes
a housing 242, a motor operating system 244, a shaft 246, and a
fluid divert assembly 248. The housing 242 includes an upper
opening 249 which provides the connection to the casing latch 211
and continues the axial passageway 228 from the casing latch 211. A
lower cup seal 251 may be disposed on an outer surface of the
housing 242 to provide a seal against the interior surface of the
casing 219.
[0110] In one embodiment, the motor operating system 244 is a
hydraulic motor system which is operated by fluids (e.g., drilling
fluid or drill mud) pumped through the motor operating system 244.
The motor operating system 244 may be a stator system or a turbine
system and turns the shaft 246. The shaft 246 is disposed axially
along the hollow shaft motor 221 and includes an axial passageway
223 which is connected to the axial passageway 228 from the casing
latch 211. The fluid divert assembly 248 is disposed at an upper
portion of the axial passageway 223 to divert fluids into the motor
operating system 244 or to direct fluid flow through the passageway
223.
[0111] In one embodiment, the fluid divert system 248 includes a
closing sleeve 252, one or more divert ports 254, and a shear ring
256. In normal drilling operation, the shear ring 256 keeps the
closing sleeve 252 in the open position which allows the divert
ports 254 to divert fluids into the motor operating system 244. To
move the closing-sleeve 252 to the closed position (i.e., where the
divert ports 254 are blocked from directing fluids into the motor
operating system 244), the shearing ring 256 is broken by
mechanical means, for example, by dropping a ball 261 (see FIG. 3)
from the surface. The fluid divert system 248 also includes a
rupture disk 258 and an extrudable ball seat 260 for facilitating
moving the closing sleeve 252 to a closed position which shuts off
fluid delivery to the motor operating system 244 and diverts fluid
flow through the axial passageway 223 in the shaft 246.
[0112] The extrudable ball seat 260 includes a seat opening and may
be made from a frangible material such as brass, aluminum, rubber,
plastic, mild steel, and other material which may be opened,
extruded or expanded when a predetermined pressure is applied to
the seat opening. For example, when a ball 261 (see FIG. 3) has
been dropped into the extrudable ball seat 260 with fluids
continually pumped behind the ball 261, pressure builds up against
the extrudable ball seat 260, and when a predetermined pressure has
been reached, the shear ring 256 breaks and the sleeve 252 shifts
down and closes port(s) 254. Next, a second predetermined pressure
is reached and the extrudable ball seat 260 opens up and allows the
ball 261 to travel through the seat opening, with sufficient force
to break through the rupture disk 258. The rupture disk 258 may be
made from a flangeable material which, when ruptured or broken by a
ball 261, opens up in a clover leaf pattern generally and does not
break off into pieces. When a rupture disk 258 has been broken,
fluid flow is directed through the passageway 223 in the shaft 246
to the drill shoe 270.
[0113] The drill shoe 270 is disposed at a terminal portion of the
casing 219. The drill shoe 270 includes a mounting portion 272 for
connecting to the end of the casing 219. The mounting portion 272
secures the drill shoe 270 to the casing 219. The drill shoe 270
includes a rotating drill face 274 which is rotatably disposed on
the mounting portion 272. A set of bearings 276 is disposed between
the mounting portion 272 and the rotating drill face 274 to
facilitate rotational movement of the rotating drill face 274.
Alternatively, a ball joint (not shown) can be utilized instead of
the bearings 276. Utilizing a ball joint would facilitate
adjustment of the drill face 274 angle (or azimuth of the bit face)
relative to the axis of the casing 219. A spindle 278 is attached
to the rotating drill face 274. The spindle 278 is connected to a
terminal portion of the shaft 246 of the hollow shaft motor 221
which provides the rotational movement to the rotating drill face
274. The spindle 278 includes a central passageway 229 which is
connected to the axial passageway 223 in the shaft 246 of the
hollow shaft motor 221. The central passageway 229 facilitates
fluid flow (e.g., drill mud or cement) to one or more nozzles 227
(preferably bit nozzles) in the rotating drill face 274. The
nozzles 227 allow fluid flow out of the drill face 274 and into the
annulus between the casing 219 and the formation to facilitate
drilling operations and cementing operations. A dart seat 282 is
positioned on the central passageway 229 for receiving a dart which
may be utilized to seal the central passageway 229.
[0114] FIGS. 2A and 2B illustrate one embodiment of the drill
system 200 which may be utilized for a drilling and casing
operation in which the casing 219 is of a set length and the drill
pipe (or inter string) 207 may be added from the surface during the
operation. In one embodiment, the hollow shaft motor drilling
system 200 may be utilized in offshore deep sea drilling in which
the distance from the water surface to the sea floor is greater
than the length of the casing 219. The hollow shaft motor drilling
system 200 may be disposed on an inner casing 195 of a nested
casing configuration, as shown in FIG. 1. The inner casing 195 may
be latched to an outer casing 185 utilizing a J-slot mechanism (not
shown). In one embodiment, the outer casing 185 is a 36-inch
diameter casing, while the inner casing 195 is a 22-inch diameter
casing, and a drill shoe 270 or 135 having a 26-inch drill surface
or drill bit is attached to the tip of the inner casing 195. The
nested casing configuration is attached to the surface platform 155
utilizing an inter string 165 and lowered down to the sea floor
160.
[0115] To begin the drilling operation, referring again to FIGS. 2A
and 2B, drilling fluid or drill mud is pumped from the surface
through the inter string 207 attached to the hollow shaft motor
drilling system 200 to provide the hydraulic power to drive the
motor operating system 221 which rotates the drill shoe 270. The
outer casing 185 (see FIG. 1) is jetted/drilled to a first target
depth with the inner casing 195, 219 latched inside. The outer
casing 195, 219 may be directionally drilled into the formation
using any of the embodiments shown in FIGS. 13-20 and described
below. By nudging the outer casing 195, 219, the direction of the
wellbore may be started so that subsequent casing may be drilled
further into the wellbore at an angle.
[0116] Once this first target depth has been reached, the inner
casing 195, 219 is released from the outer casing 185 (e.g., by
turning the inner casing 195, 219 through the J-slot mechanism) and
continued to be drilled/jetted down until a second target depth is
reached. The methods and apparatus of FIGS. 13-20 described below
may also be used on the outer casing 185. Once the inner casing
195, 219 has reached the target depth, as shown in FIG. 3, a ball
261 is dropped from the surface-through the casing 195, 219 and
into the extrudable ball seat 260 to shut off fluid flow to the
motor operating system 244 and divert the flow to the passageway
223 in the shaft 246. The ball 261 is then pressured from the
surface to a first predetermined pressure to shear ring 256, thus
moving the sleeve 252 to a closed position. At a second
predetermined pressure, ball 261 extrudes through the seat 260,
then impacts and breaks rupture disc 258, as shown in FIG. 3.
[0117] FIG. 3 is a cross-sectional view of one embodiment of a
hollow shaft motor drilling system 200 illustrating a fluid divert
operation. FIG. 4 is a partial cross-sectional view of one
embodiment of a divert system 248 in a closed position in which the
ports 254 are closed off from delivering fluid flow to the motor
operating system 244. To open fluid flow to the passageway 223 in
the shaft 246, fluid (e.g., drilling fluid, drill mud, or cement)
may be pumped in behind the ball 261 to build up pressure against
the ball seat 260, and once sufficient pressure is reached, the
shear ring 256 breaks and the sleeve 252 closes the port(s) 254.
When a second predetermined pressure is reached, the ball 261
shoots through the extrudable ball seat 260 and breaks through the
rupture disk 258, allowing fluid flow through the passageway 223.
The ball 261 travels through the passageway 223 and falls into a
cavity 284 (shown in FIG. 2) in the spindle 278. Once the divert
system 248 is set to direct fluid flow through the passageway 223,
a cementing operation may be performed.
[0118] FIG. 5 is a cross-sectional view of one embodiment of a
hollow shaft motor drilling system 200 illustrating a cementing
operation. A physically alterable bonding material, preferably
cement, may be pumped from the surface through hollow shaft motor
drilling system 200 and through one or more bit nozzles 227 in the
drill face 274, filling or partially filling gaps between the
casing 219 and the formation. After sufficient cement has been
pumped through to cement the casing 219 in place, a latching dart
286 is inserted from the surface to close off the central
passageway 229 in the spindle 278. The latching dart 286 is
utilized to prevent back flow through the central passageway 229 in
the spindle 278 and to stop flow through the one or more bit
nozzles 227 in the drill face 274. Alternatively, instead of or in
addition to the latching dart 286, a float valve may be utilized to
prevent back flow fluid pumped down through the drill shoe 270. The
latching dart 286 is displaced down to the dart seat 282 by mud
pumped in behind the dart 286 from the surface. Once the latching
dart 286 is secured onto the dart seat 282, a system retrieval
operation may be performed to retrieve the motor system 221 and the
casing latch 211.
[0119] FIG. 6 is a cross-sectional view of one embodiment of a
hollow shaft motor drilling system 200 illustrating a system
retrieval operation. With the latching dart 286 in the dart seat
282, the slips 212 on the casing latch 211 may be released by a
mechanical jerking action (e.g., utilizing the inter string 207 or
a wireline) which shears the releasing shear pin 224. Once the
releasing shear pin 224 is broken, the slips 212 collapse inwardly
and release from the interior surface of the casing 219, and the
motor system 221 and the casing latch 211 may be retrieved (e.g.,
physically picked up) from the surface by retracting or pulling up
on the inter string 207. In the retrieving operation, the shaft 246
of the motor system 221 is detached from the spindle 278 of the
drill shoe 270, leaving the latching dart 286 in the dart seat 282.
As the casing latch 211 is moved up toward the surface, the bypass
ports 217 may be opened to allow remaining mud in the system to
flow through the bypass ports 217 into the casing 219. If a float
valve is utilized in the drill shoe 270, the motor system 221 may
be retrieved utilizing mechanical means other than the inter string
(or drill pipe) 207, such as, for example, cable wireline, coiled
tubing, coiled sucker rod, etc.
[0120] As described above, the hollow shaft motor drilling system
200 facilitates drilling with casing and enables cementing the well
in one single trip down without having to first retrieve the motor
system 221 and the drill bit 270. Considerable time is reduced in
drilling and casing a well, resulting in substantial economic
saving. Embodiments of the hollow shaft motor drilling system 200
may be utilized in a variety of applications.
[0121] FIG. 7 illustrates one embodiment of the drilling system 200
which may be utilized for a drilling and casing operation in which
casing may be added during the operation. To begin the drilling
operation, drilling fluid or drill mud is pumped from the surface
through the inner diameter of the casing 219 to the hollow shaft
motor drilling system 200 to provide the hydraulic power to drive
the motor operating system 221 which rotates the drill shoe 270.
The casing 219 is jetted/drilled to a target depth. The ability to
drill a hole without rotating the casing 219 while adding casing at
the surface may reduce the time needed to perform the drilling
operations. Alternatively, the casing 219 may be rotated by surface
equipment (e.g., top drive, rotary table, etc.) during the
jetting/drilling operation without or in addition to rotating the
drill shoe 270. Once the casing 219 has reached the target depth, a
fluid divert operation, a cementing operation, and a retrieval
operation may be performed, similar to the description above
relating to FIGS. 3-6, except fluids are pumped down from the
surface through the interior diameter of the casing 219 instead of
the inter string 207.
[0122] Embodiments of the invention may also be utilized to perform
directional drilling. FIG. 8 is a cross-sectional view of one
embodiment of a hollow shaft motor drilling system 800 illustrating
a drilling operation utilizing a bent pup joint 802. As shown in
FIG. 8, the motor system 221 and the drill shoe 270 are latched
onto a bent pup joint 802. The bent pup joint 802 is threaded onto
casing with casing 219 being rotated at the surface during straight
hole sections and being slid during directional sections to drill
the casing 219 into the formation at an angie .alpha.. FIG. 9 is a
cross-sectional view of one embodiment of a hollow shaft motor
drilling system 800 illustrating a drilling operation utilizing a
bent pup joint 802 and an inter string 207. This embodiment
facilitates addition of inter string 207 to a bent pup joint
assembly 800 from the surface. The casing 219 is of a set length
while drill pipe (e.g., inter string) 207 is added at the surface.
Both FIGS. 8 and 9 shows a bent angle a (e.g., one degree bend)
from the main drilling axis. Utilizing a bent pup joint 802 allows
for drilling a deviated hole or performing a nudging operation,
without having to depend on a jetting/sliding operation. Typically,
to keep the drilled hole straight, the casing 219 is rotated when
the casing 219 is not sliding or in a slide mode. In an alternate
embodiment, the inter string 207 may not be attached during the
drilling operation, but may be utilized to retrieve the motor
system 221. When an inter string 207 is utilized, it would be
advantageous (e.g., faster) to perform the cementing operation
utilizing the inter string 207.
[0123] Embodiments of the invention may be utilized to perform a
survey operation to determine the direction of drilling. FIG. 10 is
a cross-sectional view of one embodiment of a hollow shaft motor
drilling system 200 illustrating a surveying operation. At any time
during the drilling operation, if a survey is needed to determine
or confirm the direction of drilling, a survey operation may be
performed by lowering an orientation device 1010 into the guide
204. In a survey operation, the inter string 207, if utilized, is
withdrawn to allow usage of the orientation device 1010. The
orientation device 1010 is inserted into the landing seat 209 to
determine the azimuth deviation of the drilled well. After the
survey has been performed, normal drilling operations may be
resumed and corrections may be made to direct or deviate the well
in the desired direction. The surveying operation may also be
conducted while drilling in a measuring-while-drilling operation,
so that the angle of the casing may be continuously adjusted while
drilling without interrupting the drilling and casing
operation.
[0124] Embodiments of the invention may be utilized in a drilling
with casing operation in which the casing 1102 may be cemented and
expanded with the same run of the casing 1102. FIG. 11 is a
cross-sectional view of one embodiment of a hollow shaft motor
drilling system 1100 disposed in an expandable casing 1102. The
hollow shaft motor drilling system 1100 includes similar components
as the drilling system 200 described above except the housing 1142
of the hollow shaft motor drilling system 1100 is enlarged (as
compare to housing 242) to conform with an enlarged terminal
portion 1103 of the expandable casing 1102. Also, the casing latch
1110 does not include bypass ports such as the bypass ports 217 on
the casing latch 211. Drilling and cementing operations as
described above may be performed similarly utilizing the hollow
shaft motor drilling system 1100. After the drilling and cementing
operations have been performed, the expandable casing 1102 may be
expanded or enlarged from the inside utilizing the enlarged housing
1142.
[0125] FIG. 12 is a cross-sectional view of one embodiment of a
hollow shaft motor drilling system 1100 disposed in an expandable
casing 1102 illustrating an operation for expanding the casing 1102
after cementing. After the cement has been pumped into the annulus
between the casing 1102 and the formation and the latching dart
1186 has been placed into the dart seat 1182, the slips 1112 on the
casing latch 1110 are released to allow retrieval of the motor
system 1140 which causes expansion the casing 1102. The casing 1102
may be expanded by mechanically pulling up the enlarged housing
1142 (e.g., utilizing an inter string such as 207) or by pumping
fluids (e.g., mud) down to push the housing 1142 up, or by a
combination of both of these methods. In one embodiment, as the
motor system 1140 is pulled up (e.g., utilizing inter string), mud
is pumped through the passageways 1128 and 1150, filling the space
inside the casing 1102 between the housing 1142 and the spindle
1178 of the drill shoe 1170. With more mud being pumped down from
the surface, pressure builds up between the housing 1142 and the
spindle 1178 and pushes the housing 1142 upwards. The housing 1142
pushes against the interior surface of the casing 1102, expanding
the casing 1102 as the housing 1142 travels upwardly toward the
surface. With the retrieval of the motor system 1140, the casing
1102 is expanded to a larger internal diameter. Furthermore, since
the cement between the casing 1102 and the formation has just
recently been pumped there and has not set or dried, expansion of
the casing 1102 squeezes the cement into remaining voids in the
formation, resulting in a better seal or stronger cement job of the
casing 1102 in the formation.
[0126] With the embodiments of FIGS. 1-12, additional casing (not
shown) may be used to drill through the remaining tools and any
cement in the cemented casing 202, 802, 1102. The additional casing
may include the motor drilling system therein, as described in
relation to FIGS. 1-12. Additionally, the additional casing may be
cemented into the formation and expanded by the motor drilling
system.
[0127] In an additional aspect of the present invention, the motor
drilling system 200 or 1100 described in relation to FIGS. 1-12 may
be used in conjunction with preferentially deflecting a casing in
the form of a casing section or casing string in the wellbore in a
direction using the casing, as shown and described in relation to
FIGS. 13-20. In the embodiments described herein, "casing string"
refers to one or more sections of casing. More than one sections of
casing are threadedly connected to one another. FIG. 13 shows a
diverting apparatus 10 of the present invention disposed in a
wellbore 30. The wellbore 30 is a hole drilled in a subterranean
formation 20. The diverting apparatus 10 comprises a cutting
apparatus 50 connected to a lower end of a casing string 40. The
casing string 40 is inserted into the formation 20. The cutting
apparatus 50 has perforations 55 therethrough which allow fluid
circulation between the wellbore 30 and the casing string 40.
[0128] The diverting apparatus 10 also comprises a diverter 60
connected to the lower end of the casing string 40 below the
cutting apparatus 50. The diverter 60 is connected to the lower end
of the casing string 40 by a releasable attachment 65. The
releasable attachment 65 is preferably a shearable connection. The
diverter 60 is preferably an inclined wedge attached to a portion
of the casing string 40 by the releasable attachment 65. The
diverter 60 has securing profiles 70 disposed at the lower end
thereof, which are slots formed within the diverter 60 for grabbing
the formation 20. The securing profiles 70 provide traction for the
diverter 60 while the casing string 40 is penetrating the formation
20, preventing rotational movement of the diverter 60.
[0129] Optionally, the casing string 40 of the diverting apparatus
10 may have a landing seat 45 disposed therein above the cutting
apparatus 50. The landing seat 45 is a slot in which to fit a
survey tool (not shown). Placing the survey tool into the landing
seat 45 allows the angle at which the wellbore 30 is being drilled
with respect to a surface 5 of the wellbore 30 to be ascertained
and permits appropriate adjustment to the direction and/or angle of
the wellbore 30. To determine the angle at which the wellbore 30 is
being drilled, the survey tool is first calibrated at the surface
5. The survey tool is then run through the casing string 40 and
into the landing seat 45. Once it is secured within the landing
seat 45, a second reading of the survey tool is taken, which
reveals the angle at which the wellbore 30 is drilled in relation
to the surface 5. The survey tool and landing seat 45 permit
continuous drilling with casing while surveying the conditions and
direction of the wellbore 30. Adjustment to the direction of the
wellbore 30 can be made during the drilling operation. The survey
tool is preferably a gyroscope, which is known to those skilled in
the art.
[0130] In operation, the diverting apparatus 10 is drilled into the
formation 20 by axial movement to form a wellbore 30. As the casing
40 penetrates the formation 20 to form the wellbore 30, pressurized
fluid is introduced into the casing 40 concurrent with the axial
movement of the casing 40 so that fluid flows downward through the
inner diameter of the casing 40, through the one or more nozzles
55, into the wellbore 30, and up through an annular space 90
between the outer diameter of the casing 40 and the inner diameter
of the wellbore 30 to the surface 5. Once the diverting apparatus
10 has reached a predetermined depth within the wellbore 30, in one
embodiment a downward axial force calculated to release the
releasable attachment 65 is exerted on the casing 40 from the
surface 5. The releasable attachment 65 releases so that the casing
40 with the cutting apparatus 50 attached thereto is moveable in
relation to the diverter 60. Other embodiments not shown may allow
the dropping of an object from the surface, such as a ball or dart,
to release the diverting apparatus 10 from the casing 40. Other
embodiments not shown may also include signals from the surface
such as mud pulses to cause the release of the diverting apparatus
10 from the casing 40. Still other embodiments not shown may
include the use of hydraulic pressure applied from the surface
through the casing 40 or through a separate line such as an inter
string to cause the release of the diverting apparatus 10 from the
casing 40. Downward force from the surface 5 is applied to the
casing 40, urging the casing 40 along an upper side 61 of the
diverter 60, which remains at the same position within the wellbore
30. The obstruction caused by the diverter 60 forces the lower end
of the casing 40 to deviate from its original axis at an angle
essentially consistent with the slope of the upper side 61 of the
diverter 60, causing the casing 40 to move preferentially in a
direction. The survey tool may be placed within the landing seat 45
to determine the point at which the desired deviation angle has
been reached. Once the desired angle of deviation is accomplished,
a setting operation is conducted, as setting fluid such as cement
is introduced into the casing 40 from the surface 5. The setting
fluid flows downward into the casing 40, through the one or more
nozzles 55, into the wellbore 30 and up into the annular space 90.
The setting fluid then fills the annular space 90 to anchor the
casing 40 within the wellbore 30. The diverter 60 remains
permanently within the wellbore 30.
[0131] Additional casing (not shown) may then be drilled into the
formation 20 below the casing 40 by rotational and/or axial force.
The casing 40 serves as a template for the angle followed by the
additional casing strings, so that the additional casing strings
are biased in the preferential direction. Because the additional
casing strings are hung from the casing 40, the additional casing
strings divert in the desired direction at the angle in which the
casing 40 was biased. A setting operation with setting fluid is
conducted on additional casing strings as described above in
relation to the casing 40.
[0132] FIG. 14 shows an alternate embodiment of a diverting
apparatus 110 of the present invention. The diverting apparatus 110
is used to form a wellbore 130 in a formation 120. The diverting
apparatus 110 comprises a casing string 140 wherein a bend is
introduced into a portion of the casing string 140 to deflect the
path of the wellbore 130 according to the bend in the casing string
140. The casing string 140 is used to penetrate the formation 120.
The bend is not co-axial relative to the axis of the casing string
140. An arc is therefore integrated into the casing string 140 to
urge the casing string 140 to form the diverted path for the
wellbore 130. FIG. 14 illustrates introducing the bend into the
casing string 140 by connecting component parts of the casing
string 140 by male threads 135 which engage female threads 125 to
form a threadable connection. In the shown embodiment of the
diverting apparatus 110, the male and female threads 135 and 125
are oriented on the casing string 140 so that the connection of the
component parts disposes a lower portion 136 of the casing string
140 below the threadable connection at an angle off of the vertical
axis, so that the lower portion 136 of the casing string 140 is at
an angle with respect to an upper portion 137 of the casing string
140. The female threads are not cut co-axially into the lower
portion 136 of the casing string 140, so that the lower portion 136
of the casing string 140 is bent or slanted relative to the upper
portion 137 of the casing string 140. As shown in FIG. 14, the
lower portion 136 of the casing string 140 is at an angle biased to
the right of the upper portion 137 of the casing string 140, which
is essentially vertically disposed relative to a surface 105 of the
wellbore 130.
[0133] The diverting apparatus 110 further comprises a cutting
apparatus 150 connected to a lower end of the casing string 140. At
a location which is off center from the vertical axis of the casing
string 140, one or more fluid deflectors 175 are formed through the
casing string 140 and the cutting apparatus 150. The fluid
deflector 175 is preferably one or more nozzles through the casing
string 140 and cutting apparatus 150 which is angled outward with
respect to the axis of the casing string 140 in the same direction
in which the fluid deflector 175 is biased. The fluid deflector 175
is biased and angled in the direction in which it is desired for
the wellbore 130 to be diverted, which is the preferential
direction of the wellbore 130.
[0134] Also part of the diverting apparatus 110 is a float sub 115.
A float sub 115 is a tubular-shaped body which prevents fluid from
flowing back up through the inner diameter of the casing string 140
after the setting fluid has been forced downward into the casing
string 140 for the setting or cementing operation (described
below). Also, the float sub 115 prevents fluid from flowing from
the formation 120 in the casing string 140 to reduce frictional
resistance while running the casing string 140 into the formation
120. The float sub 115 comprises a ball seat 102 with a ball 101
initially disposed therein, as shown in FIG. 14. The ball seat 102
may also be any type of one-way check valve, include a flapper-type
valve. The diverting apparatus 110 further includes a landing seat
145 for a survey tool (not shown), which operates in the same
manner as described above with respect to the landing seat 45 of
FIG. 13. The float sub 115 and the landing seat 145 are preferably
made of drillable material such as aluminum or plastic, so that
they may be drilled through after the casing string 140 is set
within the wellbore 130.
[0135] FIG. 15 is an alternate embodiment of the diverting
apparatus 110 of FIG. 14. The diverting apparatus 210 of FIG. 15,
which forms a wellbore 230, comprises the same parts as those in
FIG. 14; therefore, like parts are designated with the same last
two numbers. For example, the wellbores are 130 and 230, the
surfaces are 105 and 205, the formations are 120 and 220, and so
on.
[0136] The diverting apparatus 210 of FIG. 15 also comprises one or
more pads 285 which are disposed on the outer diameter of the
casing string 240. Preferably, the pads 285 are located on the
outer diameter of the casing string 240 on the side opposite the
fluid deflector 275. As the casing string 240 is drilled deeper
into the formation 220, the diverting apparatus 210 encounters
increasing friction, making it increasingly difficult to drill the
wellbore 230 into the formation 220. The pads 285, which are spaced
vertically along the casing string 240, serve to reduce friction
encountered in the formation 220. Furthermore, the pads 285 help to
bias the casing string 240 outward at the desired angle in the
preferred direction by keeping the casing string 240 from direct
contact with the inner diameter of the wellbore 230. The pads 285
maintain the cutting structure 250 heading outward, preventing it
from falling back to vertical with respect to the axis of the upper
portion of the casing string 240.
[0137] The operation of the diverting apparatus 110 and 210 of
FIGS. 14 and 15 is similar, so they will be described in
conjunction with one another. In operation, the diverting apparatus
110, 210 is drilled into the wellbore 130, 230 axially by downward
force applied from the surface 105, 205. The cutting apparatus 150,
250 drills into the formation 120, 220 due to the axial force. At
the same time, pressurized fluid is introduced into the casing
string 140, 240 from the surface 105, 205 to facilitate the
downward movement of the diverting apparatus 110, 210 into the
formation 120, 220. The fluid forms a path for the diverting
apparatus 110, 210 in the formation and prevents mud and rock from
the formation 120, 220 from filling the inner diameter of the
casing string 140, 240. The fluid flows through the casing string
140, 240, through the float sub 115, 215, through the fluid
deflector 175, 275, and into an annular space 190, 290 between the
outer diameter of the casing string 140, 240 and the inner diameter
of the wellbore 130, 230. Along the way, the fluid tends to flow
into the area with the least obstruction. The fluid deflector 175,
275 urges the fluid outward into the formation 120, 220 at the
angle in the preferred direction with respect to the vertical axis
of the casing string 140, 240, where no obstruction is present. In
this way, fluid flow is selectively diverted out of a portion of
the casing string 140, 240 to form a deflected path for the
wellbore 130, 230. The concentrated fluid flow into only one
portion of the formation 120, 220 causes a profile 180, 280 in a
portion of the formation 120, 220 to develop, forming a path
through which the casing string 140, 240 may travel with less
frictional resistance than the alternative paths through the
formation 120, 220. The lower portion 136, 236 of the casing string
140, 240 is thus biased at an angle off of the vertical axis of the
upper portion 137, 237 casing string 140, 240, in the general
direction and at the general angle of the fluid deflector 175, 275,
so that the wellbore 130, 230 is angled in the preferential
direction and the path of the wellbore 130, 230 is deflected
accordingly.
[0138] Additionally, the fluid tends to flow outward at the angle
off of the vertical axis at which the bend in the casing string
140, 240, in this case the bend produced by the male and female
threads 125, 225 and 135, 235, biased the diverting apparatus 110,
210. The lower portion 136, 236 of the casing string 140, 240 is
thus urged at an angle in the preferential direction with respect
to the upper portion 137, 237 of the casing string 140, 240 due to
the fluid deflector 175, 275 and the threadable connections 125,
225 and 135, 235. In the embodiment of FIG. 15, the pads 285
further urge the diverting apparatus 210 in the desired direction
by reducing friction of the casing string 240 against the formation
220 along the way downward, as well as by propping the lower end of
the casing string 240 with the cutting apparatus 250, thus
preventing the cutting apparatus 250 from falling back into the
vertical angle with respect to the axis of the casing string 140,
240. In this way, in either embodiment, the path of the casing
string 140, 240 and, thus, of the wellbore 130, 230, is deflected
in the desired direction to avoid intersection with other
wellbores.
[0139] After the casing string 140, 240 penetrates into the
formation 120, 220 to form the wellbore 130, 230 at the desired
angle at the desired depth, pressurized setting fluid such as
cement may optionally be introduced into the wellbore 130, 230 from
the surface 105, 205 through the casing string 140, 240. The
setting fluid flows through the casing string 140, 240, through the
float sub 115, 215, through the fluid deflector 175, 275, and then
outward into the annular space 190, 290. The float sub 115, 215
functions much like a check valve, in the open position allowing
setting fluid to flow downward through the casing string 140, 240,
and in the closed position preventing setting fluid from flowing
back upward through the casing string 140, 240 toward the surface
105, 205. Specifically, the setting fluid, when flowing into the
casing string 140, 240 from the surface 105, 205, forces the ball
101, 201 downward within the float sub 115, 215 and out of the ball
seat 102, 202. The setting fluid can thus flow around the ball 101,
201 and through the float sub 115, 215 to flow into the annular,
space 190, 290. The setting fluid solidifies within the annular
space 190, 290 to secure the casing string 140, 240 within the
wellbore 130, 230. When setting fluid is no longer introduced into
the casing string 140, 240 to force the ball 101, 201 out of the
ball seat 102, 202, the ball 101, 201 is again seated in the ball
seat 102, 202 so that setting fluid cannot flow back upward within
the casing string 140, 240 toward the surface 105, 205.
[0140] After setting the casing string 140, 240, the float sub 115,
215 and the landing seat 145, 245 may be drilled through by a
cutting structure. Additional strings of casing (not shown) may
then be hung off of the casing string 140, 240. The additional
casing strings are biased at an angle with respect to the vertical
axis because the casing string 140, 240 leads the additional casing
strings in its general direction and angle. The additional casing
strings are set with setting fluid just as the casing string 140,
240 was set.
[0141] FIGS. 14 and 15 show a bend introduced into the casing 140,
240 at the threadable connection of male and female threads 125,
225 and 135, 235. In the alternative, a bend in the casing 140, 240
could be integrally machined in the casing 140, 240. It is also
contemplated that embodiments of the present invention may include
merely bending the casing 140, 240. The bend in the casing 140, 240
would provide directional force for directionally drilling with the
casing 140, 240.
[0142] FIG. 55 shows a further alternate embodiment of a nudging
operation of the present invention. In this embodiment, no bend is
introduced into the casing as is shown in FIGS. 14 and 15, and no
eccentric pads 285 are located on the outer diameter of the casing
as shown in FIG. 15. Rather, in the embodiment of FIG. 55, one or
more fluid deflectors (nozzles) 475 are located on one side of an
earth removal member 350 operatively attached to a lower end of a
casing 440 and are angled outward with respect to the vertical axis
of the casing 440, which may include a casing section or a casing
string having a plurality of casing sections. As shown and
described in relation to FIGS. 14-15, a fluid deflector 475 is
formed through the casing 440 and the earth removal member 450,
which is preferably a cutting apparatus such as a drill bit. The
earth removal member 450 may be a bi-center bit, expandable bit,
drillable cutting structure, or the like, depending upon the
application. The fluid deflector 475 is biased and angled in the
direction in which it is desired to divert the wellbore, or in the
preferential direction of the wellbore. The fluid deflector 475 is
substantially the same as the fluid deflectors 175 and 275 of FIGS.
14 and 15, respectively. As in the embodiments shown in FIGS. 14
and 15, any number of fluid deflectors 475 may be utilized in the
present invention.
[0143] As in the embodiments shown in FIGS. 14 and 15, a float sub
415 and landing seat 445 for a survey tool (not shown) may be
located within the diverting apparatus 410. Because the float sub
415 is substantially the same as the float subs 115, 215 shown and
described with respect to FIGS. 14 and 15, the above description of
the float subs 115, 215 of FIGS. 14 and 15 and their operation
applies equally to the float sub 415 of FIG. 55. Similarly, because
the landing seats 45, 145, and 245 of FIGS. 13, 14, and 15,
respectively, are substantially the same as the landing seat 445,
the above description of the landing seats 45, 145, and 245 and
their operation applies equally to the embodiment of FIG. 55.
[0144] In a preferred embodiment, the diverting apparatus 410
includes a plurality of fluid deflectors or nozzles 475 grouped
together on one side of the cutting apparatus 450. FIG. 57
illustrates a particularly preferred embodiment, which includes
three fluid deflectors or nozzles 475A, 475B, and 475C through the
casing 440 and cutting apparatus 450 for preferentially directing
the fluid flow into the formation. The fluid deflectors 475A, B,
and C may be pointed straight down, where the axes of the fluid
deflector 475A, B, and C are parallel to the axis of the cutting
apparatus 450. Alternately, the fluid deflectors 475A, B, and C may
be angled radially outward from the cutting apparatus 450, so that
the axes of the fluid deflectors 475A, B, and C are at an angle
with respect to the axis of the cutting apparatus 450. In one
embodiment, one or more of the fluid deflectors 475A, B, and C may
be angled, while the remainder of the fluid deflectors 475A, B, and
C may be straight. In a preferred embodiment, the vertical axes of
the fluid deflectors 475 A, B, and C are angled approximately 30
degrees radially outward from the vertical axis of the cutting
apparatus 450.
[0145] In operation, to form a deflected wellbore, the diverting
apparatus 410 may be alternately jetted by flowing fluid through
the casing 440 and into the fluid deflector 475 while
simultaneously lowering the casing 440 into the formation, and
rotated by rotating the entire casing 440 within the formation.
During jetting of the fluid through the deflector 475, fluid
through the deflector 475 forms a path for the diverting apparatus
410 in the formation in the same way as described above in relation
to the fluid deflectors 175, 275 shown and described in relation to
FIGS. 14 and 15. Namely, the fluid flows into the area of the
formation having the least obstruction, and the angled orientation
of the fluid deflector 475 urges the fluid outward from the casing
440 into the formation at the angle in the preferred direction with
respect to the vertical axis of the casing 440. Concentrated fluid
flow in a portion of the formation causes a profile in a
corresponding portion of the formation to form so that the casing
440 travels through the path of least resistance to form a
deflected wellbore path.
[0146] After the casing 440 has reached the desired depth within
the formation, a physically alterable bonding material such as
cement may be flowed through the casing 440 to set the casing 440
within the wellbore, in the same manner as described in relation to
setting the casing 140, 240 of FIGS. 14 and 15, using the float sub
415. After possibly retrieving the survey tool which may optionally
be located within the landing seat 445, if the float sub 415,
landing seat 445, and cutting apparatus 450 are drillable, the
float sub 415, landing seat 445, and cutting apparatus 450 may each
be drilled through by a subsequent cutting structure, e.g., a
cutting structure located on a subsequent drill string or
subsequent casing. If the components are drilled through by a
subsequent cutting apparatus on a subsequent casing, the additional
casing may then be hung off the casing 440 (preferably at a lower
end of the casing 440) and possibly set with a physically alterable
drilling material within the wellbore. This process may be repeated
as desired to drill and case the wellbore to a total depth. The
additional casing strings are biased at an angle with respect to
the vertical axis of the casing 440 because of the casing 440
deflection.
[0147] In a preferred operation of the embodiment shown in FIG. 55,
the casing 440 may be alternately jetted and/or rotated to form a
wellbore within the formation. To form a deviated wellbore, the
rotation of the casing 440 is halted, and a surveying operation is
performed using the survey tool (not shown) to determine the
location of the one or more fluid deflectors 475 within the
wellbore. Stoking may also be utilized to keep track of the
location of the fluid deflector(s) 475, the method of which is
described in relation to FIG. 31 (see below).
[0148] Once the location of the fluid deflector(s) 475 within the
wellbore is determined, the casing 440 is rotated if necessary to
aim the fluid deflector(s) 475 in the desired direction in which,
to deflect the casing 440. Fluid is then flowed through the casing
440 and the fluid deflector(s) 475 to form a profile (also termed a
"cavity") in the formation. Then, the casing 440 may continue to be
jetted into the formation. When desired, the casing 440 is rotated,
forcing the casing 440 to follow the cavity in the formation. The
locating and aiming of the fluid deflector(s) 475, flowing of fluid
through the fluid deflector(s) 475, and further jetting and/or
rotating the casing 440 into the formation may be repeated as
desired to cause the casing 440 to deflect the wellbore in the
desired direction within the formation.
[0149] A further alternate embodiment of the present invention
involves accomplishing a nudging operation to directionally drill
the casing 440 into the formation and expanding the casing 440 in a
single run of the casing 440 into the formation, as shown in FIGS.
56A and 56B. Additionally, cementing of the casing 440 into the
formation may optionally be performed in the same run of the casing
440 into the formation. FIGS. 56A-B show the diverting apparatus
410, including casing 440, the earth removal member or cutting
apparatus 450, the one or more fluid deflectors 475 (which may be a
plurality of fluid deflectors arranged as shown and described in
relation to FIG. 57), and the landing seat 445 of FIG. 55.
[0150] Additional components of the embodiment of FIGS. 56A and 56B
include an expansion tool 442 capable of radially expanding the
casing 440, preferably an expansion cone 442; a latching dart 486;
and a dart seat 482. The expansion cone 442 may have a larger outer
diameter at its upper end than at its lower end, and preferably
slopes radially outward from the upper end to the lower end. The
expansion cone 442 may be mechanically and/or hydraulically
actuated. The latching dart 486 and dart seat 482 are used in a
cementing operation.
[0151] In operation, the diverting apparatus 410 is lowered into
the wellbore with the expansion cone 442 located therein by
alternately jetting and/or rotating the casing 440, most preferably
by nudging the casing 440 according to the preferred method
described in relation to FIG. 55. Next, a running tool 425 is
introduced into the casing 440. A physically alterable bonding
material, preferably cement, is pumped through the running tool
425, preferably an inner string. Cement is flowed from the surface
into the casing 440, out the fluid deflector(s) 475, and up through
the annulus between the casing 440 and the wellbore. When the
desired amount of cement has been pumped, the dart 486 is
introduced into the inner string 425. The dart 486 lands and seals
on the dart seat 482. The dart 486 stops flow from exiting past the
dart seat, thus forming a fluid-tight seal. Pressure applied
through the inner string 425 may help urge the expansion cone 442
up to expand the casing 440. In addition to or in lieu of the
pressure through the inner string 425, mechanical pulling on the
inner string 425 helps urge the expansion cone 442 up.
[0152] Rather than using the latching dart 486, a float valve 415
as shown and described in relation to Figure. 55 may be utilized to
prevent back flow of cement. The latching dart 486 is ultimately
secured onto the dart seat 482, preferably by a latching
mechanism.
[0153] The running tool 425 may be any type of retrieval tool.
Preferably, the retrieval of the expansion cone 442 involves
threadedly engaging a longitudinal bore through the expansion cone
442 with a lower end of the running tool 425. The running tool 425
is then mechanically pulled up to the surface through the casing
440, taking the attached expansion cone 442 with it. Alternately,
the expansion cone 442 may be moved upward due to pumping fluid,
down through the casing 440 to push the expansion cone 442 upward
due to hydraulic pressure, or by a combination of mechanical and
fluid actuation of the expansion cone 442. As the expansion cone
442 moves upward relative to the casing 440, the expansion cone 442
pushes against the interior surface of the casing 440, thereby
radially expanding the casing 440 as the expansion cone 442 travels
upwardly toward the surface. Thus, the casing 440 is expanded to a
larger internal diameter along its length as the expansion cone 442
is retrieved to the surface.
[0154] Preferably, expansion of the casing 440 is performed prior
to the cement curing to set the casing 440 within the wellbore, so
that expansion of the casing 440 squeezes the cement into remaining
voids in the surrounding formation, possibly resulting in a better
seal and stronger cementing of the casing 440 in the formation.
Although the above operation was described in relation to cementing
the casing 440 within the wellbore, expansion of the casing 440 by
the expansion cone 442 in the method described may also be
performed when the casing 440 is set within the wellbore in a
manner other than by cement.
[0155] As mentioned in relation to the embodiment of FIG. 55, the
cutting apparatus 450 may be drilled through by a subsequent
cutting structure (possibly attached to a subsequent casing) or may
be retrieved from the wellbore, depending on the type of cutting
structure 450 utilized (e.g., expandable, drillable, or bi-center
bit). Regardless of whether the cutting structure 450 is
retrievable or drillable, the subsequent casing may be lowered
through the casing 440 and drilled to a further depth within the
formation. The subsequent casing may optionally be cemented within
the wellbore. The process may be repeated with additional casing
strings.
[0156] FIG. 16 shows a diverting apparatus 310 drilled into a
formation 320 to form a wellbore 330. The diverting apparatus 310
includes an upper casing 340, as well as a lower casing 341. The
upper and lower casings 340 and 341 are inserted into the formation
320 as a unit. The lower casing 341 has a first cutting apparatus
350 attached to its lower end. At least one nozzle 355 runs through
the lower end of the lower casing 341 as well as through the first
cutting apparatus 350. The at least one nozzle 355 allows for fluid
circulation between the casings 340, 341 and the wellbore 330.
[0157] The diverting apparatus 310 also includes an elongated
coupling 391, which is a collar used to connect the upper and lower
casing strings 340 and 341 to one another. An upper portion of the
elongated coupling 391 is connected to a lower portion of the upper
casing 340 by a threadable connection 342. Similarly, a lower
portion of the elongated coupling 391 is attached to an upper
portion of the lower casing 341 by a threadable connection 343. The
elongated coupling 391 has a second cutting apparatus 395 located
on its outermost portion. In the alternative, only one casing (not
shown) may have a second cutting apparatus 395 disposed thereon,
which is not necessarily attached by a threadable connection. The
outer diameter of the second cutting apparatus 395/elongated
coupling 391 is larger than the outer diameter of the first cutting
apparatus 350. The second cutting apparatus 395 extends along a
substantial portion of the length of the elongated coupling 391,
and even along the lower portion of the elongated coupling 391, so
that the cutting apparatus 395 cuts into the formation 320 as the
diverting apparatus 310 is forced progressively downward to form
the wellbore 330. The second cutting apparatus 395 possesses
hole-opening blades which increase the inner diameter of the upper
portion of the wellbore 330.
[0158] In operation, the diverting apparatus 310 is urged into the
formation 320 by downward axial force applied from a surface 305 of
the wellbore 330. The elongated coupling 391 of the diverting
apparatus 310 allows the two casings 340 and 341 to be threaded
together at the well site, so that the diverting apparatus 310 does
not have to be pre-manufactured on the casing 340 or 341. In the
alternative, the second cutting apparatus 395 may be
pre-manufactured on the casing string (not shown). As described
above in relation to the other embodiments, pressurized fluid is
introduced into the diverting apparatus 310 through the inner
diameter of the upper casing 340 as the casing 340, 341 penetrates.
into the formation 320 to form the wellbore 330, and then the fluid
flows into the lower casing 341, through the at least one nozzle
355, up through a second annular space 389 between an inner
diameter of the wellbore 330 and an outer diameter of the lower
casing 341, up through a first annular space 390 between the inner
diameter of the wellbore 330 and an outer diameter of the upper
casing 340, and to the surface 305 of the wellbore 330
[0159] While the diverting apparatus 310 is moving axially downward
through the formation 320 and the fluid is circulating, the first
cutting apparatus 350 cuts into the formation 320 to form a lower
portion of the wellbore 330 approximately equal to its diameter.
Likewise, the second cutting apparatus 395 at the same time cuts
into the formation 320 to form an upper portion of the wellbore 330
approximately equal to its diameter. The outer diameter of the
upper portion of the wellbore 330 is larger than the outer diameter
of the lower portion of the wellbore 330 because of the difference
in diameter between the first cutting apparatus 350 and the second
cutting apparatus 395.
[0160] Because of the difference in diameters between the upper and
lower portions of the wellbore 330, the first annular space 390
between the outer diameter of the upper casing 340 and the inner
diameter of the upper portion of the wellbore 330 is larger than
the second annular space 389 between the outer diameter of the
lower casing 341 and the inner diameter of the lower portion of the
wellbore 330. The axial movement is halted when the diverting
apparatus 310 reaches its desired depth in the wellbore 330.
[0161] The first annular space 390 at the top of the wellbore 330
is larger than the second annular space 389 at the bottom of the
wellbore 330 as a result of the enlarged diameter second cutting
apparatus 395, so that a larger diametral clearance exists at the
upper portion of the wellbore 330 than at the lower portion of the
wellbore 330. The larger diametral clearance allows gravity to
cause the casing to buckle in a direction. The direction in which
gravity causes the casing to buckle is illustrated by the arrows
disposed within the first annular space 390. Fulcrum force is
illustrated by the arrows perpendicular to the axis of the casing
340, 341 and adjacent to the second cutting structure 395. A force
in the opposite direction caused by formation 320 frictional
resistance is depicted by the arrow perpendicular to the axis of
the first cutting apparatus 350. The effect of the forces shown by
the arrows in FIG. 16 is that the upper casing 340 moves laterally
through the first annular space 390 while staying essentially
anchored at the lower portion of the lower casing 341 by the second
annular space 389, so that the diverting apparatus 310 angles in
the preferred direction. The second cutting apparatus 395, or the
additional dressing on the outer diameter of the casing 340 and/or
341, thus creates a larger cavity in the upper portion of the
wellbore 330 than in the lower portion of the wellbore 330, which
facilitates lateral movement of the casing 340 in the preferred
direction to create a deflected path for the wellbore 330.
[0162] Again, a survey tool (not shown) placed in a landing seat
(not shown) as described above may be used to determine whether the
diverting apparatus 310 is bent in the desired direction at the
desired angle. Once the diverting apparatus 310 is deviated into
the desired angle, the first and second casings 340 and 341 are
cemented into place by a setting operation as described above. All
of the components disposed within the inner diameter of the casing
340 are preferably made of drillable material so that they may be
drilled through after the setting operation so that the inner
diameter of the casing 340 is essentially hollow for subsequent
wellbore operations. Subsequent casings (not shown) are then run
into the wellbore 330 and hung from the existing lower casing 341.
The subsequent casings are biased in the desired direction at the
desired angle because they essentially conform to the angle set by
the original casings 340 and 341.
[0163] FIG. 17 shows an alternative embodiment of a diverting
apparatus of the present invention. The diverting apparatus 1310 is
substantially similar to the diverting apparatus 310 shown and
described in relation to FIG. 16; as such, like parts will not be
described again herein. The embodiment shown in FIG. 17 is
different from the embodiment shown in FIG. 16 because instead of
the concentric stabilizer acting as the second cutting apparatus,
an eccentric stabilizer 1395 disposed asymmetrically on one side of
the outer diameter of the casing 1340, 1341 adds additional
directional force to the diverting apparatus 1310. In the depiction
of the diverting apparatus 1310 shown in FIG. 17, the stabilizer
1395, which is preferably a 1-bladed actuable kick-pad, causes the
upper portion of the casing 1340 to angle in the opposite direction
from the eccentric stabilizer 1395. As an additional directional
force acting in the same direction as the stabilizer 1395 is
biasing the casing 1340, 1341, a fluid deflector 1355, or a
perforation in the cutting apparatus 1350 angled in a direction
with respect to vertical, may also be utilized to further deflect
the path of the wellbore 1330 in a preferential direction at an
angle with respect to the vertical axis of the casing.
[0164] In the operation of the embodiments of FIGS. 16-17, a
two-step process may be utilized. First, oriented jetting through
the one or more fluid deflectors (bit nozzles) 1355 may be
accomplished to establish an initial inclination and direction of
the casing. Then, the casing 340 and 341, 1340 and 1341 may be
rotary drilled further into the formation using the second cutting
apparatus 395, 1395 to build the angle. To rotary drill, the entire
casing 340 and 341, 1340 and 1341 is rotated while lowering the
casing into the formation 320, 1320. By using this two-step
process, the more efficient rotary drilling method may be utilized
to build the angle of the wellbore 330, 1330.
[0165] Finally, FIGS. 18-20 illustrate an apparatus and method
which may be utilized with a diverting apparatus 510 to drill
through the inner diameter of the diverting apparatus 510 and
remove obstructions so that additional casing strings (not shown)
may be hung from the diverting apparatus 510 after the initial
diversion. The apparatus and method of FIGS. 18-20 may be used with
any of the above embodiments to remove obstructing portions of the
diverting apparatus residing within the inner diameter of the
casing string after the casing string has been set within the
wellbore. Referring to FIG. 18, the diverting apparatus 510
includes a casing string 540 with a second cutting apparatus 595
disposed on its outer diameter. The casing string 540 is inserted
into a formation 520 to form a wellbore 530. The inner diameter of
the casing string 540 has a drillable member 521 attached thereto
which is connected to a drilling apparatus 522 through releasable
connections 506. The releasable connections 506, which are
preferably shearable connections, are used to fix the diverting
apparatus 510 relative to the drilling apparatus 522 torsionally
and axially.
[0166] The drilling apparatus 522 includes a drill string 523 with
a first cutting apparatus 550 connected to its lower end. The first
cutting apparatus 550 is smaller in diameter than the second
cutting apparatus 595, so that the second cutting apparatus 595
possesses hole-opening blades which enlarge the inner diameter of
the upper portion of the wellbore 530. The first cutting apparatus
550 has a cutting structure 551 attached to its lower end, at least
one side parallel to a wellbore 530, and its backside 526 at an
angle from the wellbore 530. The first cutting apparatus 550 has at
least one nozzle 555 which allows fluid to flow into and in from a
formation 520. Threads 501 are preferably located on an upper end
of the drill string 523 on its inner diameter.
[0167] The operation of the diverting apparatus 510 and the
drilling apparatus 522 is shown in FIGS. 18-20. FIG. 18 illustrates
the diverting/drilling apparatus 510/522 during run-in of the
casing string 540. The diverting apparatus 510 with the drilling
apparatus 522 attached thereto is pushed downward axially into the
formation 520 to form the wellbore 530. The diverting/drilling
apparatus 510/522 may also be rotated from a surface 505 of the
wellbore 530 if desired to drill through the formation 520. The
first cutting apparatus 550 drills into the formation 520 due to
the pressure placed on the casing string 540, which translates to
the drilling apparatus 522. During the run-in of the casing string
540, the first cutting apparatus 550 on the drilling apparatus 522
initially forms a portion of the wellbore 530 of a first diameter.
The second cutting apparatus 595 enlarges the diameter of the
wellbore 530 in the portion of the wellbore 530 that it is forced
into, as the second cutting apparatus 595 is larger in diameter
than the first cutting apparatus 550. Thus, a first annular space
590 between the outer diameter of the casing string 540 and the
inner diameter of the wellbore 530 is larger than a second annular
space 589 between the outer diameter of the drill string 523 and
the inner diameter of the wellbore 530. The second cutting
apparatus 595, or the additional dressing on the outer diameter of
the casing string 540, thus creates a larger cavity in the upper
portion of the wellbore 530 than in the lower portion of the
wellbore 530, which facilitates lateral movement of the casing
string 540 in the preferred direction to create a deflected path
for the wellbore 530. Pressurized fluid is introduced into the
casing string 540 while the casing string 540 penetrates into the
formation 520 to form the wellbore 530 to flush mud and other
substances out of the casing string 540 through the at least one
nozzle 555 in the cutting apparatus 550, outside the drill string
523 and the casing string 540, and up to the surface 505.
[0168] After the diverting/drilling apparatus 510/522 is drilled
into the desired depth in the wellbore 530 at which to divert and
set the casing string 540, a working string 503 or some other
retrieving tool is lowered into the inner diameter of the casing
string 540 (the working string 503 is shown in FIG. 19). The
working string 503 retrieves the drill string 523 using a pulling
tool profile on its lower end, preferably male threads 502 on the
working string 503 which threadedly engage female threads 501 of
the drill string 523.
[0169] FIG. 19 illustrates the next step in the operation of the
diverting/drilling apparatus 510/522. The working string 503 is
pulled upward axially from the surface 505 to release the
releasable connection 506. The releasable connection 506 is
preferably sheared off. As a consequence of the release, the drill
string 523 is moveable axially and rotationally relative to the
diverting apparatus 510. The drilling apparatus 522 is then pulled
upward and rotated through the wellbore 530 by the working string
503. The cutting structure 551 on the backside 526 of the first
cutting apparatus 550 contacts the lower end of the drillable
member 521 and the portion of the releasable connection 506
remaining on the drillable member 521.
[0170] As seen in FIG. 20, the cutting structure 551 drills
completely through the drillable member 521 and the remaining
portion of the releasable connection 506 so that the drillable
member 521 and releasable connection 506 are essentially destroyed.
The inner diameter of the casing string 540 is therefore left
effectively unobstructed so that wellbore operations may be
performed or additional casing strings (not shown) may eventually
be hung from the casing string 540. The drilling apparatus 522 is
then removed from the wellbore 530 by the working string 503.
[0171] Finally, the casing string 540 is bent from the surface 505
to a side at an angle. Because of the larger first annular space
590 at the upper portion of the casing string 540, the casing
string 540 is fixed at its lower end but moves through the first
annular space 590 at its upper portion so that the casing string
540 is biased at an angle. The additional casing strings may then
be hung off of the casing string 540 at the angle at which the
casing string 540 is biased, allowing the wellbore 530 to deviate
in the desired direction at the desired angle.
[0172] In the embodiments shown in FIGS. 13-20, the float sub may
include, but is not limited to, the following: a check valve,
poppet valve, flapper valve, or any other type of one-way valve.
Drillable material utilized to form the float sub may include, but
is not limited to, one or more of the following: aluminum, plastic,
metal, cement, or combinations thereof.
[0173] Furthermore, in any of the embodiments shown in FIGS. 13-20,
the cutting structure may be a drillable drill bit or an expandable
bit latched into the casing. For an example of an expandable bit
suitable for use in the present invention, refer to U.S. Patent
Application Publication No. 2003/111267 or U.S. Patent Application
Publication No. 2003/183424, each which is incorporated by
reference herein in its entirety.
[0174] The diverting apparatus of the present invention and methods
for their use allow effective diversion of a wellbore in a
direction by deflecting a string of casing inserted into the
wellbore. The apparatus and methods are simple to build and permit
the wellbore diversion to be accomplished while drilling with
casing in a subterranean wellbore. Accordingly, the apparatus and
methods of the present invention aid in preventing the unwanted
intersection of valuable subterranean wellbores.
[0175] The diverting apparatus of FIGS. 13-20 used for nudging may
be utilized as the outer casing 185 shown in FIG. 1, while the
inner casing 195 may be any of the embodiments depicted in FIGS.
1-12. In this manner, referring to FIG. 1, the system 100 is jetted
and/or rotated to lower the outer casing 185 into the earth
formation 112 at the desired depth to form a deviated wellbore.
Next, the releasable connection between the inner casing 195 and
the outer casing 185 is released, and the inner casing 195 is
jetted and/or rotated, and the drilling system 157 may also be
utilized to drill the inner casing 195 to the desired depth within
the formation 112 while continuing to bias the direction and angle
of the wellbore. The drilling system may include any of the
embodiments shown in FIGS. 1-12.
[0176] In the most preferable embodiment of FIGS. 13-20, the casing
is alternately rotated and/or lowered or jetted into the formation.
The rotation and jetting alternation aids in achieving the desired
trajectory of the wellbore.
[0177] In conventional drilling operations, hydraulic horsepower is
delivered to the cutting structure through one or more very
restrictive orifices or nozzles (commonly termed "bit nozzles")
located in the cutting structure. The nozzles are usually located
in the body of the cutting structure proximate to the bottom of the
wellbore. The function of the nozzles is primarily to puncture the
earth formation with "jet" impacts to facilitate formation of the
wellbore, then to carry the cuttings up to the surface through the
annulus between the wellbore and the casing. Additional functions
of nozzles and the fluid flow therethrough include cleaning the
cutting structure, cooling the bit cutters, and cleaning the bottom
of the wellbore. For the nozzles to perform this function, the
horsepower of the fluid flowing through the nozzles must be high
during jetting. Because of the high horsepower of the hydraulic
fluid traveling through the nozzles while jetting, the nozzles are
subjected to extremely high erosion caused by pressure drop of the
drilling fluid across the nozzles (e.g., from 500 to 3000 psi) and
high velocity of the fluid through the nozzles (e.g., from 200 to
800 ft/s).
[0178] The necessary high flow rate of fluid through the nozzles to
perform an adequate jetting operation requires that the nozzles be
made of materials which allow the nozzles to be sufficiently hard
and tough to withstand the erosion due to the fluid through the
nozzles. Typically, therefore, a hard and tough material such as
tungsten carbide and/or ceramic is used to jet into the formation
with a drill string in conventional drilling operations, as nozzles
constructed from one or more of these materials may endure for
thousands of hours without suffering fatal damage from erosion.
Drilling with casing operations, however, such as those that are
shown in FIGS. 1-22, may require that the nozzles be drillable, and
the current ceramic or tungsten carbide nozzles used for jetting in
the drill string are not drillable.
[0179] Drilling with casing operations may require the same fluid
intensity while jetting and/or rotating the casing as is required
when circulating drilling fluid in the drill string while drilling.
The amount of time that the fluid intensity must be maintained
during drilling may be less for drilling with casing operations
than in traditional drilling operations, however.
[0180] In the embodiments of the present invention shown in FIGS.
1-20, an expandable cutting structure or a drillable cutting
structure may be utilized. An alternate embodiment may include a
drillable cutting structure, possible including drillable nozzles.
FIG. 21 shows a process for drilling through a drillable cutting
structure 1615 such as a drill bit or drill shoe operatively
attached to a casing 1610. The drillable cutting structure 1615 has
drillable nozzles 1616 therein. The casing 1610 is lowered into the
earth formation 1605 to form a wellbore 1630 by rotating the casing
1610 and/or by jetting the casing 1610. After the casing 1610 is
lowered and/or drilled into the earth formation 1605 to the desired
depth, in one embodiment the casing 1610 may be set therein using a
physically alterable bonding material such as cement (not
shown).
[0181] As shown in FIG. 21, a casing 1620 is lowered into the inner
diameter of the casing 1610 while introducing fluid F through the
inner diameter of the casing 1620, out through nozzles 1626 in a
cutting structure 1625 in the casing 1620, and up to the surface.
The cutting structure 1625 may, but does not necessarily have to
be, drillable. The cutting structure 1625 may in the alternative be
expandable and retrievable from the wellbore 1630.
[0182] FIG. 22 illustrates the next step in an embodiment of the
method for drilling through a cutting structure on a casing. The
casing 1620 is lowered and/or rotated through the casing 1610 to
drill through at least a portion of the cutting structure 1615. The
nozzles 1616 are preferably also drillable, as described below.
FIG. 22 shows the casing 1620 drilling to a further depth within
the formation 1605. After the casing 1620 is lowered to the desired
depth within the formation 1605, the casing 1620 may be expanded in
one embodiment. If desired, the casing 1620 may also be set therein
using the physically alterable bonding material. Subsequently, the
cutting structure 1625 may be left in the wellbore 1630 or may be
drilled through by an additional casing (not shown) or by a drill
string or other cutting device.
[0183] The present invention provides drillable nozzles for use
while drilling with casing. For the cutting structure 1615 to be
drillable, the base material and the nozzle(s) of the cutting
structure 1615 must be soft enough to allow subsequent casing 1620
to drill therethrough. However, a nozzle constructed of a
sufficiently soft material used in a drilling with casing
application may only last a few hours under intense fluid erosion
due to jetting. While enlarging the nozzle diameter to reduce
velocity of the fluid through the nozzle aids in increasing nozzle
longevity, this design remains problematic because the velocity of
the fluid through the nozzle(s) may be so decreased that the casing
no longer sufficiently drills through the formation during the
jetting process.
[0184] FIGS. 23A-23B, 24A-B, and 25-29 show embodiments of the
present invention of a drillable nozzle, of which one or more may
be used in any of the embodiments in FIGS. 1-22. The nozzles shown
in FIGS. 23A-23B, 24A-B, and 25-29 are insertable into the cutting
structures of FIGS. 1-22 to provide a fluid path from the inner
diameter of the casing into the wellbore. The drillable nozzle
breaks into portions, preferably fragments or "cuttings", to be
flowed to the surface using drilling fluid through the casing (not
shown) which is used to drill through the drillable nozzle. The
drillable nozzles of FIGS. 23A-23B, 24A-B, and 25-29 are drillable
while remaining sufficiently devoid of erosive deconstruction to
allow functional jetting through the nozzles with drilling fluid or
any other fluid introduced into the nozzles.
[0185] In the embodiment shown in FIGS. 23A and 23B, the drillable
nozzle 1700 is constructed of a hard, brittle, and wear-resistant
material. Exemplary base materials which may be utilized to form
the drillable nozzle 1700 include, but are not limited to, tungsten
carbide, ceramic, and polycrystalline diamond (PDC). FIG. 23B shows
a first end 1751 of the nozzle 1700, through which fluid F is
flowable during a drilling with casing operation. While drilling
with the casing attached to the cutting structure having at least
one drillable nozzle 1700 therein, fluid F is flowable through the
casing, into the first end 1751, through a bore 1761 disposed
within the nozzle 1700, out through a second end 1741 of the nozzle
1700 (shown in Figure 23A), then up through an annulus between the
casing and the wellbore (or another casing disposed therearound) to
the surface.
[0186] The drillable nozzle 1700 has one or more stressed portions
therein, specifically shown as one or more stressed notches 1710 in
FIGS. 23A-B. Preferably, the stressed notches 1710 are disposed
within the outer diameter of the nozzle 1700 and are at least
partially subflushed to the surface of the nozzle 1700. The
stressed notches 1710 preferably extend the length of the nozzle
1700 coaxially with the bore 1761 of the nozzle 1700; however, it
is contemplated that the stressed notches 1710 may extend only a
portion of the length of the nozzle 1700. The stressed notches 1710
provide a stress point to cause the nozzle 1700 to break into
portions or fragments when drilled through with a subsequent
casing, drill string, or other cutting device. While not a
requirement for use in the present invention, a preferred
embodiment provides that the notches 1710 are spaced substantially
equidistant from one another along the outer diameter of the nozzle
1700. The notches 1710 are preferably relatively narrow cuts
throughout the length of the nozzle 1700.
[0187] An o-ring groove 1705 may exist within the outer diameter of
the body of the nozzle 1700 around its circumference for disposing
an o-ring (not shown) therein to seal the nozzle 1700 within a body
of the tool in which the nozzle 1700 is disposed, such as a cutting
tool (not shown). In one embodiment, a filler material 1715,
preferably an extrudable material such as epoxy or vulcanized
rubber, is disposed at least partially within the notches 1710 when
the notches 1710 extend the length of the nozzle 1700 so that the
o-ring may seal in the o-ring groove 1705.
[0188] FIGS. 24A and 24B illustrate another embodiment of a
drillable nozzle 1800. A first end 1851 of the nozzle 1800 is shown
in FIG. 24B, while a second end 1841 of the nozzle 1800 is depicted
in FIG. 24A. When the drillable nozzle 1800 is disposed in a
cutting tool (not shown) operatively connected to a lower end of a
casing (not shown), fluid F flows through the casing, into the
first end 1851 of the nozzle 1800, through a bore 1861 within the
nozzle 1800, out through the second end 1841, then up through the
annulus between the casing and the wellbore or between the casing
and another casing disposed within the wellbore therearound.
[0189] The embodiment shown in FIGS. 24A and 24B is substantially
the same as the embodiment shown in FIGS. 23A and 23B, except for
the following aspects. The stressed notches 1810 extend only
through a portion of the nozzle 1800, coaxial with the bore 1861.
The notches 1810, which are again at least partially subflushed to
the surface of the nozzle 1800, are interrupted along at least a
portion of the outer diameter of the nozzle 1800. Preferably, the
portion of the outer diameter of the nozzle 1800 over which the
notches 1810 are interrupted is at least the at o-ring groove 1805,
negating the need to fill the notches 1810 with filler material
1715 as in FIGS. 23A-B. An additional difference between the nozzle
1700 and the nozzle 1800 is that the notches 1810 are preferably
substantially wider than the notches 1710.
[0190] In the embodiments of FIGS. 23A-B and 24A-B, the nozzles
1700 and 1800 provide longevity to and allow high flow rates of
fluid to pass through the cutting structure operatively connected
to the casing. At the same time, when the nozzles 1700 and 1800 are
drilled through by a subsequent cutting structure placed on a
subsequent casing or drill string, the broken nozzle portions may
be circulated to the surface through an annulus between the
subsequent casing or drill string and the wellbore.
[0191] FIGS. 25-28 show nozzle assemblies which may be utilized in
a drillable cutting structure operatively attached to casing. FIGS.
25 and 26 show extended flow tubes 1910, 2010 having a minimum
thickness and a substantially uniform inner diameter or bore along
each of their lengths. The flow tubes 1910, 2010 each represent a
portion of the nozzle assemblies 1900, 2000. FIGS. 27 and 28 show
relatively thin profiled flow tubes 2180, 2280, each of which
represent a portion of the nozzle assemblies 2100, 2200.
[0192] In the embodiment of the present invention illustrated in
FIG. 25, the nozzle assembly 1900 includes a flow tube 1910
disposed within a nozzle retainer 1920. The flow tube 1910 is
substantially tubular-shaped with a longitudinal bore therethrough.
Additionally, the flow tube 1910, which is preferably constructed
of a relatively hard material such as ceramic, tungsten carbide, or
PDC, is relatively thin (i.e., has a low thickness, as measured
from an outer diameter to an inner diameter of the flow tube 1910)
to facilitate drillability of the flow tube 1910 when a cutting
structure, such as an earth removal member attached to a casing or
a drill string, is drilled through the flow tube 1910.
[0193] The flow tube 1910 has a substantially uniform inner
diameter bore along its length to form a substantially straight
bore through the flow tube 1910. The substantially straight bore of
the flow tube 1910 maintains a minimal thickness along the length
of the flow tube 1910, thus enhancing drillability of the flow tube
1910 with a subsequent cutting structure, as any profile of the
flow tube 1910 other than a straight bore therethrough would
require an increase in material thickness perpendicular to the axis
of the flow tube 1910. The material thickness perpendicular to the
axis of the flow tube 1910 is presented to the subsequent cutting
structure for drilling therethrough. Also, the internal profile of
the flow tube 1910 formed by the substantially straight bore
therethrough potentially decreases erosion of one or more portions
of the nozzle 1900 because the fluid does not have to change
direction due to obstructions within the bore when flowing through
the nozzle 1900.
[0194] The nozzle retainer 1920, which is preferably constructed of
a relatively soft, drillable material such as copper or plastic,
retains the flow tube 1910 therein. The flow tube 1910 is
preferably mounted within the nozzle retainer 1920, which is a
tubular-shaped body with a longitudinal bore therethrough. The
nozzle retainer 1920 may include an installation and removal
feature, such as slots 1940 shown in FIG. 25 in an exit side face
1970 of the nozzle retainer 1920. The slots 1940 facilitate
installation and removal of the nozzle assembly 1900 from a tool
body 1925.
[0195] An integral feature of the nozzle assembly 1900 is the
extended length of the flow tube 1910. Due to the extended length
of the flow tube 1910, the flow tube 1910 may be positioned as
desired within the nozzle retainer 1920 by moving the flow tube
1910 up or down (right or left as shown in FIG. 25) within the
nozzle retainer 1920. Moving the flow tube 1910 up or down coaxial
with the retainer 1920 allows entry and exit points of the fluid
(shown in FIG. 25, as the fluid flow moves left to right in the
depicted assembly 1900) to be positioned as required either closer
to or away from areas which may be susceptible to fluid erosion as
a result of high velocity of the fluid and turbulence caused by the
high flow rate of the fluid while the fluid is entering or exiting
the flow tube 1910. Additionally, moving the flow tube 1910 down
relative to the tool body 1925 would allow the exit point of the
fluid from the nozzle assembly 1900 to be positioned closer to the
formation than a typical nozzle design, thus improving
effectiveness of the jetting through the nozzle assembly 1900 to
remove portions of the formation by enabling increased control of
exit standoff 1960 and entry standoff 1950. Exit standoff 1960 is
the distance of fluid flow through the flow tube 1910 measured from
between the exit side face of the tool body 1925 and the exit point
of the fluid from the flow tube 1910, while entry standoff 1950 is
the distance of fluid flow within the flow tube 1910 measured from
between the entry side face of the tool body 1925 and the entry
point of the fluid into the flow tube 1910.
[0196] The nozzle retainer 1920 is preferably constructed of a
relatively soft, drillable material such as copper or plastic. The
material that the retainer 1920 is made from is softer than the
material of the flow tube 1910. Also, the material of the flow tube
1910 is more resistant to corrosion than the material of the
retainer 1920. The internal bore of the retainer 1920 is profiled
to produce a controlled fit over the outer diameter of the flow
tube 1910, with a gap 1947 left between the flow tube 1910 and the
retainer 1920 which is preferably substantially filled with a
suitable adhesive 1945 for retaining the flow tube 1910 in the
desired position within the retainer 1920.
[0197] The retainer 1920 is seated within a nozzle profile 1965 in
a tool body 1925. The tool is preferably an earth removal member
for cutting into an earth formation, and even more preferably a
cutting structure such as a drill bit or drill shoe. The tool body
1925 is preferably constructed of a relatively soft, drillable
material such as copper or plastic. An outer surface of the
retainer 1920 has a seal groove 1907 having a seal 1905 therein for
preventing fluid flow across the interface of the outer surface of
the retainer 1920 and the nozzle profile 1965 of the tool body
1925. An external thread 1915 secures the nozzle assembly 1900
within the tool body 1925.
[0198] Advantageously, the embodiment of FIG. 25 allows
adjustability of the entry and exit points away from the tool body
1925, creating a dead area 1930 in the fluid flow where high
velocities and turbulence do not exist and directing fluid away
from the retainer 1920 and tool body 1925 made of the soft,
drillable material which is more susceptible to erosion due to
fluid flow than the harder material of the flow tube 1910.
[0199] An alternate embodiment of a nozzle assembly 2000 of the
present invention is shown in FIG. 26. The nozzle assembly 2000 is
substantially similar to the nozzle assembly 1900 shown and
described in relation to FIG. 25; therefore, like parts are labeled
with like numbers (the last two digits of the numbers are the
same). The difference between the assembly 2000 and the assembly
1900 is that the entire nozzle assembly 2000, including the nozzle
retainer 2020 and the flow tube 2010, may be constructed of a soft,
drillable material such as copper or plastic or of a non-drillable
material (such as when used in a retrievable cutting structure
rather than a drillable cutting structure, as described below).
This design allows for ease of construction of the nozzle assembly
2000 because the nozzle assembly 2000 can be made in one piece. No
adhesive 1945 is required in the embodiment of FIG. 26 because the
nozzle assembly 2000 is one piece. The embodiment shown in FIG. 26
may be utilized in drilling applications when the flow regime is
such that easily drillable materials such as copper or plastic may
be used while still gaining the benefits of the removal of
localized turbulence from the tool body 2025 itself due to the
straight-bore flow tube 2010. This design allows for sleeving of
the inner diameter of the flow tube 2010 by platting, shrink
fitting, or any other suitable method to apply a wear-resistant
material such as tungsten carbide and/or ceramic, where the
thickness of the wear-resistant material is not so great as to
detract from the process of drilling through the nozzle. The
wear-resistant materials may be layered to obtain increased wear
resistance and flexibility.
[0200] The nozzle assemblies 1900, 2000 shown in FIGS. 25-26 allow
for adjustment of the entry and exit standoff 1950 and 2050,1960
and 2060 by moving the flow tube 1910, 2010 within the tool body
1925, 2025. The flow tube 1910, 2010 may be moved towards the entry
or exit point of the fluid from the flow tube 1910, 2010 as
desired.
[0201] FIGS. 27 and 28 show further alternate embodiments of a
nozzle assembly 2100, 2200. The embodiment shown in FIG. 27
includes the nozzle assembly 2100, which includes a nozzle retainer
2120 and a flow tube 2180. The flow tube 2180 is a profiled sleeve
through which fluid flows from a tool such as a cutting structure
attached to casing into the formation while jetting and/or
drilling. In FIG. 27, the fluid enters into the flow tube 2180 from
the left at an entry point and exits from the flow tube 2180 at an
exit point. An inner diameter of the flow tube 2180 at the entry
point of the fluid is larger than an inner diameter of the flow
tube 2180 at the exit point of the fluid into the formation.
Between the entry point of the fluid and a distance A along the
flow tube 2180, the flow tube 2180 is of a first inner diameter.
The flow tube 2180 then converges at an angle over a distance B to
a second inner diameter, which is smaller than the first inner
diameter. The second inner diameter is maintained over a distance C
along the flow tube 2180 until the exit point of the flow tube
2180.
[0202] The flow tube 2180 is constructed from a relatively hard
material such as ceramic, tungsten carbide, or PDC to limit erosion
of the flow tube 2180, as described in relation to FIGS. 23A-B,
24A-B, and 25-26 above. The flow tube 2180 is relatively thin, as
measured from the inner diameter of the flow tube 2180 to the outer
diameter of the flow tube 2180, to facilitate drilling through the
relatively hard material of the flow tube 2180 by the subsequent
cutting structure, as described above in relation to FIGS.
25-26.
[0203] A relatively soft, drillable material such as copper or
plastic is utilized to form the nozzle retainer 2120. The material
making up the flow tube 2180 is harder than the material of the
retainer 2120 and tool body 2125, and the material of the flow tube
2180 is more resistant to corrosion than the material of the
retainer 2120. The drillability of the soft material allows the
nozzle retainer 2120 to be of a larger thickness at the portion
adjacent to the smaller diameter portion of the flow tube 2180 than
its thickness at the other portions of the flow tube 2180. The
retainer 2120 inner diameter thus essentially conforms to the outer
diameter of the flow tube 2180.
[0204] The nozzle assembly 2100 is disposed in a tool body 2125,
which is preferably an earth removal member such as a drill shoe or
a drill bit. The tool body 2125 is preferably constructed of a
relatively soft (at least compared to the flow tube 2180),
drillable material such as copper, aluminum, cast iron, plastic, or
combinations thereof. The material of the tool body 2185 may or may
not be the same as the material of the retainer 2120. A seal 2105
is disposed within a seal groove 2107 formed in an outer diameter
of the retainer 2120 to prevent fluid from traveling in the area
between the inner diameter of the tool body 2125 and the outer
diameter of the retainer 2120. Retaining threads 2115 are located
between the tool body 2125 and the retainer 2120 for connecting the
nozzle assembly 2100 to the tool body 2125.
[0205] The nozzle assembly 2100 is characterized by an extended
exit. The extended exit is represented by an exit standoff 2160,
which is the length of the flow tube 2180 which extends past the
end of the tool body 2125 from which fluid flows upon exit from the
flow tube 2180. The exit standoff 2160 diverts the flow turbulence
into an area away from the nozzle retainer 2120 and the tool body
2125.
[0206] FIG. 28 shows an additional embodiment of the present
invention. The embodiment shown in FIG. 28 is substantially the
same as the embodiment shown in FIG. 27; therefore, substantially
similar elements to FIG. 27 which are in the "21" series are
labeled in FIG. 28 with the "22" series. The difference between the
embodiment of FIG. 27 and the embodiment of FIG. 28 is that the
embodiment shown in FIG. 28 not only includes the extended exit in
the form of the exit standoff 2260, but also includes the extended
entry in the form of the entry standoff 2250. The entry standoff
2250 is the length of the flow tube 2280 which extends past the end
of the tool body 2225 into which fluid flows upon entry into the
flow tube 2280. The extended entry of fluid through the flow tube
2280 provides an area of low turbulence next to the tool body 2225
at entry. In addition to their use in drillable application, the
embodiments of FIGS. 27 and 28 may all be utilized in non-drillable
applications such as in expandable cutting structures when drilling
with casing.
[0207] Shown in FIG. 29 is an embodiment of an earth removal member
1925 ("tool body"), preferably a cutting structure in the form of a
drill shoe or drill bit, which includes two nozzle assemblies 1900
therein. The nozzle assemblies 1900 are shown, but one or more of
the nozzle assemblies 2000, 2100, 2200 may alternately be disposed
within the tool body 2125. The upper nozzle assembly 1900 shown in
FIG. 29 is oriented at an angle with respect to the vertical axis
of the casing connected to the tool, thus illustrating the use of
the nozzle assembly 1900, 2000, 2100, 2200 to directionally drill
by jetting through a fluid diverter, or an oriented nozzle or jet,
as shown and described in relation to FIGS. 14-15 and 17. FIG. 29
also demonstrates by the lower nozzle assembly 1900 shown in the
figure that the nozzle assembly 1900, 2000, 2100, 2200 may also be
utilized in casing drilling operations which do not involve nudging
and directionally drilling.
[0208] In addition to their use in drillable applications, the
above embodiments shown in FIGS. 25-29 may also be utilized in a
retrievable cutting structure when a retrievable cutting structure
is used with the embodiments of the invention shown in FIGS. 1-22,
such as an expandable bit. The embodiment of FIG. 26 is especially
applicable to non-drillable nozzles, where protection of the tool
body 2025 at the entry and exit points is required, or when it is
required to position the nozzle exit point closer to the
formation.
[0209] FIG. 30 is a cross-sectional view of the lower end of a
cutting structure having nozzles therethrough. In directional
jetting, as shown and described in relation to FIGS. 14-15 and 17,
one or more of the nozzles of the cutting structure may be blocked
to prevent fluid flow therethrough. The unobstructed nozzles will
produce selective fluid flow from only a portion of the cutting
structure, so that fluid flow is asymmetrically introduced into the
wellbore and forms a diverted path for the casing within the
formation.
[0210] The alternate embodiments of FIGS. 53A, 53B, and 54 provide
drill bit nozzles that are constructed to withstand the abrasive
and erosive impact of jetted drilling fluid, while also being
suitable for subsequent drilling operations intended to drill
through drill bit bodies to which the nozzles are attached, and
indeed the nozzles themselves. The embodiments of FIGS. 53A-B and
54 further provide a method of drilling a wellbore, wherein the
drilling method is that commonly known as drilling with casing and
wherein subsequent drilling may be undertaken by a subsequent drill
bit, without the requirement of the removal of the earlier or first
drill bit from the well bore, and wherein the earlier or first
drill bit includes nozzles.
[0211] FIGS. 53A-B and 5 show embodiments of a new and improved
drill bit nozzle comprising a body defining a through-bore, wherein
the through-bore defines a passage for drilling fluid in use,
wherein the surface of the through-bore within the body has a
relatively high resistance to erosion and wherein the nozzle is
characterized in that the body is made substantially of a material
or materials that allow for the nozzle to be subsequently drilled
through by standard wellbore drilling equipment. Preferably, the
through bore has an enlarged concave portion at an inlet side of
the nozzle, communicating with a smaller diameter cylindrical
portion.
[0212] The nozzle body may be made of two materials, wherein the
surface of the through-bore is made of a first material, wherein
said first material is of relatively thin construction and has a
high resistance to erosion, and wherein the remainder of the nozzle
body is made of a second material that is easily drillable. The
first or surface material may be a hard chrome. Alternatively,
tungsten carbide or suitable alloys may be used, their suitability
being assessed by their ability to withstand erosive forces from
the well fluid jetted through the through-bore.
[0213] The second material forming substantially the majority of
the nozzle body may be made typically of a softer metal, such as
nickel, aluminum, copper or alloys of these. Preferably, the second
material may be copper and the surface or first material is hard
chrome, wherein the hard chrome is applied to the. copper body by
electro-plating.
[0214] Alternatively, a nozzle in accordance with the present
invention may be made of a rubber material. In this respect, it is
noted that while rubber is typically not a "hard" material, it does
nevertheless have a high resistance to erosion. Moreover, rubber
materials may be easily drilled by subsequent drilling bits. A
nozzle in accordance with invention may be made of one or more
materials and need not be made entirely or even partially of a
metal material. Polyurethane or other elastomers may also be
used.
[0215] Referring firstly to FIGS. 53A and 53B, there is shown a
drill bit nozzle 1. The drill bit nozzle 1 is adapted to be
threadably engaged with a drill bit body (not shown) by virtue of
the threaded portions 2. The nozzle 1 is provided with an annular
body 3 that defines a through-passage or through-bore 4. The
through-bore 4 is formed with an inlet having a concave enlarged
portion 4a which communicates with a cylindrical smaller diameter
portion 4b leading to an outlet 7. The geometry of the through-bore
4 is such that well fluid is jetted at high velocity out the outlet
7.
[0216] It is recognized in the invention that the nozzle
through-bore 4 is intended to receive drilling fluid at high
velocities and with high pressure differentials. Accordingly, the
surface 5 of the through-bore 4 is constructed of a material that
is suitable for withstanding the abrasive and eroding nature of the
drilling fluid in use. Not only must the surface of the
through-passage withstand the eroding forces of the drilling fluid,
but in view of the proximity of the nozzles to the cutting surface
of the drill bit, excessive wear may be induced in the event of a
nonresistant material being employed as a result of the impact of
small rock particles and other debris cut by the drill bit from the
well formation. The erosive effect of rock particles within drill
bit nozzles is well known and documented. For this reason, the
surface of the through-bore 4 is preferably made from a hard
material which, in an example embodiment of FIGS. 53A-B, is a hard
chrome material. In another example, tungsten carbide may be used
as the surface material.
[0217] The surface material will typically be chosen as one which
is able to be combined with a softer, drillable material whereby
this softer, drillable material may form substantially the body of
the drill bit nozzle, with the exception of the surface herein
before mentioned. In the example embodiment illustrated in FIG.
53A-B, the second material from which substantially all of the
nozzle body is made is copper. Copper is selected as one suitable
material as the surface coating of hard chrome may be easily
applied to the copper body by electroplating means. Additionally,
copper is sufficiently soft to allow a subsequent drill bit to
drill through the body of the nozzle.
[0218] In FIG. 54, an alternative nozzle 12 is made substantially
of a single non-metallic material, preferably rubber. However, to
enable the rubber nozzle 12 to be attached to a drill bit body, the
nozzle 12 is provided with a threaded insert made of a metallic
material. The threaded insert 11 is, nevertheless, made of a
material which is sufficiently soft to allow a subsequent drill bit
to drill through it.
[0219] An advantage of the present invention will be apparent from
the method of use of the drill bit nozzle as shown in FIGS. 53A-B
and 54 and described above which allows for a drill bit bearing
drill bit nozzles to be left in a wellbore during the cementing of
casing and subsequently drilled through by standard wellbore
drilling equipment to allow for the well to be extended. The
invention may be seen to overcome the difficulty of providing drill
bit nozzles in a manner that allowed for their resistance to wear
from the erosive characteristics of jetted drilling fluid, while
nevertheless enabling subsequent conventional or standard wellbore
drilling equipment to drill through them.
[0220] When nudging casing into the formation, it is sometimes
useful to form a casing string made up of a plurality of casing
sections. Making up the casing string involves rotating one casing
section relative to another casing section to threadedly connect
the casing sections together. Many of the directional drilling
tools described in the figures of the present application include
biasing tools (e.g., eccentric stabilizer and/or directional jet)
disposed on the casing or within the casing, the location of which
must be tracked from the surface of the wellbore to allow the
operator to maintain the direction and angle of the deviated
wellbore while drilling with the casing. One method of tracking the
position of the biasing tool on the casing involves marking the
position of the biasing tool when the casing having the biasing
tool thereon is first lowered into the formation ("stoking or
scribing in the hole"). Marking the position may be accomplished by
drawing a vertical chalk line along the casing as one casing
section is threaded onto another. Then, when the made-up casing
string is lowered into the wellbore, the portion of the marked
casing section which remains located above the wellbore (e.g., by a
spider on a rig floor) becomes the reference point for marking a
chalk like after the next section of casing is threaded onto the
casing string.
[0221] An additional method of tracking the position of the biasing
tool, which may be used in addition to the scribing method, is
accomplished by the mechanism shown in FIG. 31. A casing string
2300 which may be utilized in the present invention while jetting
into the formation includes a casing section 2320 having male
threads 2321 threaded to a casing section 2330 having male threads
2331 by a collar 2315 having female threads 2311 and 2312. Disposed
within the collar 2315 is a buttress torque ring 2310. The buttress
torque ring 2310 is a spacer placed in between the ends of the pins
2331, 2321 of the casing sections 2330, 2320 to provide a stop
mechanism to stop torquing of the casing sections 2330, 2320 at a
given point. The buttress torque ring 2310 may be used to hold the
chalk line when scribing in the hole so that the chalk mark does
not lose accuracy as to the location of the biasing tool because
the rotational position of the casing sections 2330, 2320 relative
to one another changes.
[0222] Additional embodiments of the present invention generally
provide improved methods and assemblies for drilling with casing
(DWC). In contrast to the prior art, drilling assemblies according
to the present invention are supported between an attachment point
at a bottom of the casing and the point of drilling contact by one
or more adjustable stabilizers. The stabilizers may have one or
more adjustable support members that may be placed in a first
(run-in) position giving the stabilizer a sufficiently small outer
diameter to be run in through the casing with the drilling
assembly. The support members may then be placed in a second
position giving the stabilizer a sufficiently large outer diameter
to engage an inner wall of the wellbore to provide support for the
drilling assembly during drilling.
[0223] Additional embodiments of the present invention provide
directional force for directionally drilling the assembly on the
casing rather than the BHA. Moreover, embodiments of the present
invention reduce the requisite length of the rat hole below the
casing, thereby decreasing the amount by which the casing must be
lowered into the rat hole after the BHA has drilled to the desired
depth at which to place the casing within the wellbore.
[0224] For different embodiments, the drilling assemblies of the
present invention may be adapted to operate in either a rotary or
slide mode. For some embodiments, in an effort to decrease drilling
time, an expandable bit having a higher removal rate than the
conventional combination of an under-reamer and pilot bit may be
utilized. While embodiments of the present invention may be
particularly advantageous to directional drilling with casing, some
embodiments may also be used to advantage in non-directional DWC
systems. Such embodiments may lack the bent subassemblies shown in
the following figures.
[0225] FIGS. 33A-D illustrate an exemplary DWC system for
directionally drilling of a wellbore 4102 through a formation 4103
utilizing a drilling assembly, according to an embodiment of the
present invention, comprising a bottom hole assembly (BHA) 4200
attached to a portion of casing 4104. As illustrated, the drilling
assembly generally includes at least one adjustable stabilizer
4202. For some embodiments, the adjustable stabilizer 4202 may be
positioned to provide support to the BHA 4200 between a casing
latch 4106 and a earth removal member or drilling member, such as
an expandable bit 4204. Accordingly, the adjustable stabilizer 4202
may decrease the amount of deflection of the BHA 4200, thereby
improving directional control, increasing bit life, and increasing
formation removal rate.
[0226] As illustrated, for some embodiments, the stabilizer 4202
may be positioned above a biasing member, such as a bent
subassembly 4114 ("bent sub") used to bias the BHA 4200 in the
desired direction. The bent sub 4114 may be fixed or adjustable to
tilt the face of the bit 4204, typically from 0.degree. to
approximately 3.degree. with respect to the centerline of the BHA
4200. As previously described, the bent sub 4114 may be integral
with a downhole motor 4112. The number of adjustable stabilizers
4202 utilized in a system may depend on a number of factors, such
as the weight-on-bit applied to the BHA 4200, the length of the BHA
4200, desired wellbore trajectory, etc.
[0227] While a conventional pilot bit and under reamer may be used
for some embodiments, the expandable bit 4204 generally provides an
increased removal rate and performs the same operations (e.g.,
forming an expanded hole below the casing 4104, allowing the casing
string to advance with the wellbore). The increased removal rate
may be accomplished by providing a greater density of cutting
elements ("cutter density") in contact with the wellbore surface.
For example, cutting members 4205 of the bit 4204 may include
cutting elements arranged in full complement with the hole profile
to achieve an optimal penetration rate. An example of an expandable
bit is disclosed in International Publication Number WO 01/81708
A1, which is incorporated herein in its entirety. As described in
the above referenced publication, cutting elements of the bit 4204
may be made of any suitable hard material, such as tungsten carbide
or polycrystalline diamond (PDC).
[0228] Operation of the BHA 4200 may be best described with
reference to FIG. 34, which illustrates a flow diagram of exemplary
operations 3300 for directional DWC, according to one embodiment of
the present invention. At step 3302, a drilling assembly (e.g., the
BHA4200) is run down a wellbore 4102 through casing 4104, the
drilling assembly having an (at least one) adjustable stabilizer
4202 and an expandable bit 4204. As illustrated in FIG. 33A, in
order to run the BHA 4200 through the casing 4104, support members
4203 of the stabilizer 4202 and cutting members 4205 of the
expandable bit 4204 may be placed in a first (run-in) position,
wherein the stabilizer 4202 and expandable bit 4204 each have a
total outer diameter less than the inner (drift) diameter of the
casing 4104. The BHA 4200 is generally run until a securing
mechanism, such as a casing latch 4106, is aligned with a bottom
portion of the casing 4104. At step 3304, the drilling assembly is
secured to a bottom portion of the casing 4104, for example, with
the casing latch 4106.
[0229] At step 3306, the bit 4204 is expanded to have an outer
diameter greater than an outer diameter of the casing 4104. For
example, as illustrated in FIG. 33B, the cutting members 4205 of
the expandable bit 4204 may be expanded into an open position.
Generally, movement of the cutting members 4205 between the
retracted and expanded positions may be controlled through the use
of hydraulic fluid flowing through the center of the expandable
bit. For example, increasing the hydraulic pump pressure (i.e., by
increasing the flow of drilling fluid) may move the cutting members
4205 into the expanded position while decreasing the hydraulic
pressure may return the blades to the retracted position (e.g., for
retrieval of the BHA 4200 after drilling operations are completed,
for bit replacement, etc.).
[0230] At step 3308, the stabilizer 4202 is adjusted for
directional control of the drilling assembly. For example,
initially, an outer diameter of the stabilizer 4202 may be adjusted
from the first (run-in) position to a second position having a
sufficiently large diameter to engage the inner walls of the
wellbore 4102 to support the BHA 4200 while drilling. During the
drilling process, as will be described in greater detail below, the
stabilizer 4202 may be adjusted to a third position (between the
run-in position and the second position) to vary the under-gage
amount (e.g., separation between support members 4203 and the inner
walls of the wellbore 4102), in an effort to control the trajectory
of the hole.
[0231] Means for adjusting the stabilizer 4202 may vary with
different embodiments. For example, as illustrated in FIGS.
33A-33C, the support members 4203 may be implemented as movable
arms/blades that may be retracted in the first (run-in) position
(FIG. 33A), expanded in the second position, and partially
retracted/expanded to the third position (FIG. 33C) to provide a
separation between the stabilizer 4202 and the wellbore 4102. The
stabilizer 4202 may be continuously adjustable to aid in
directional control. As an alternative, one or more of the support
members 4203 may be aligned to give the stabilizer 4202 a smaller
diameter during run-in. The support, members 4203 may then be
misaligned (e.g., by rotating one of the support members 4203
relative to the other) to increase the diameter of the stabilizer
4202. As another alternative, the stabilizer 4202 may include one
or more spring-type support members 4207 (shown in FIG. 33D) that
may be adjusted between the first, second, and third positions. As
yet another alternative, the stabilizer 4202 may include an
inflatable or mechanical support member (not shown), that may be
operated similar to a packing element to adjust the stabilizer
between the first, second, and third (or more) positions.
[0232] In either case, adjustments to the stabilizer 4202 (between
the various positions) may be made by any suitable means, such as
hydraulic means (in a similar manner as described above with
reference to the expandable bit 4204), mechanical means, and
electrical or electromechanical means, etc. Regardless, the
stabilizer 4202 may be designed for use in rotary and/or slide
mode. For example, in slide mode, the stabilizer 4202 provides
drill string centralization and prevents the BHA from leaning onto
one side of the hole. For some embodiments, the stabilizer 4202 may
include sensors that monitor relative movement of the casing 104 in
order to allow the stabilizer 4202 to rotate with the casing 4104
or to slide as the casing 4104 is being rotated to aid in the
control of the direction of the hole. In either case, the
stabilizer 4202 may prevent BHA 4200 from buckling (and leaning to
one side) when weight-on-bit is applied to the BHA 4200. By
preventing deflection of the BHA 4200 within the wellbore 4102, the
stabilizer 4202 may also reduce the amount of axial and lateral
vibration.
[0233] As previously described, excessive vibration, particularly
in rotary mode, may lead to less than optimal contact between the
bit 4204 and the formation 4103, leading to reduced penetration
rate and a corresponding increased drilling time, which increases
production costs. Further, excessive vibration may also lead to
catastrophic harmonics which may damage and/or destroy the various
components of the BHA 4200. In an effort to further reduce
vibration, the BHA 4200 may also include a flexible collar 4206,
which may be designed to prevent vibration from traveling from the
bent subassembly 4114 to an upper portion of the BHA 4200 (e.g.,
any portion above the flexible collar 4206). The flexible collar
4206 may be made of any suitable flexible-type materials capable of
withstanding harsh downhole conditions.
[0234] At step 3310, the bit 4204 is rotated to drill a hole having
an outer diameter larger than the outer diameter of the casing
4104. As previously described, embodiments of the BHA 4200 may be
operated in a rotary mode or a slide mode. In rotary mode, the bit
4204 may be rotated with the casing 4104 and guided with a
rotary-steerable assembly (not shown), having adjustable pads that
may be used to "push off" the inner walls of the formation 4102 to
adjust the deviation of the bit angle from center. In slide mode,
the bit 4204 may be rotated by a steerable downhole motor 4112,
which typically provides a high speed of rotation and a high rate
of removal without the need to rotate the casing 4104. When
operating in either mode, the stabilizer 4202 provides
centralization and prevents the BHA 4200 from leaning to one side
of the hole, thus allowing better control of the trajectory of the
hole.
[0235] At step 3312, the trajectory of the hole is monitored. As
previously described, in conventional DWC systems, the hole may be
steered by geological indicators logged at certain points while
drilling (logging while drilling, or "LWD") using at least one LWD
tool. While this log may be used to reconstruct and verify the
wellbore path after drilling, this may be too late to make
corrections. However, by monitoring the trajectory of the hole
while it is being drilled (measuring while drilling, or "MWD"),
embodiments of the present invention may allow for corrections to
be made at the surface, for example by adjusting weight on bit,
adjusting angle of the bent sub, and/or steering the motor
4112.
[0236] Further, as previously described, the stabilizer 4202 may be
adjusted in response to a monitored trajectory. For example, the
support members 4203 may be adjusted to provide a separation
between the stabilizer 4202 and the inner surface of the wellbore
4102. The separation between the stabilizer 4202 and the inner
surface of the wellbore 4102 (as shown in FIG. 33C) may allow the
bent housing 4114 of the motor 4112 to lean more to one side, thus
increasing bit deflection. Accordingly, the under-gage of the
stabilizer 4202 may be varied, for example, in an effort to control
bit deflection of the bit from center, for example, to make
relatively fine adjustments to the trajectory of the wellbore 4103
as it is extended.
[0237] The trajectory of the wellbore 4102 may be monitored with a
measurement-while-drilling (MWD) tool 4107 which, as shown, may be
disposed anywhere along the BHA 4200. The MWD tools 4107 may be
generally used to evaluate the trajectory of the wellbore 102 in
three-dimensional space while extending the wellbore 4102.
Therefore, the MWD tool 4107 may generally include one or more
sensors to measure the trajectory (e.g., azimuth and inclination)
of the wellbore, such as a steering sensor, accelerometer,
magnetometer, or the like.
[0238] Of course, the MWD tool 4107 may also have sensors to
monitor one or more downhole parameters, such as conditions in the
wellbore (e.g., pressure, temperature, wellbore trajectory, etc.)
and/or geophysical parameters (e.g., resistivity, porosity, sonic
velocity, gamma ray, etc.). For some embodiments, the MWD tool 4107
may log such parameters for later retrieval at the surface. Thus,
the MWD tool 4107 may also perform the same functions as
conventional LWD tools. Regardless of whether these parameters are
logged or telemetered to the surface in real time, measuring these
parameters while drilling may save an additional trip down the
wellbore for the sole purpose of such measurements.
[0239] Any suitable telemetry techniques may be utilized to
communicate the wellbore trajectory (and possibly any other
parameters) monitored by the MWD tool 4107 to the surface of the
wellbore 4102. Examples of suitable telemetry techniques may
include electronic means (e.g., through a wireline or wired pipe)
and/or digitally encoding data and transmitting to the surface as
pressure pulses in a mud system using sensing devices including,
but not limited to, one or more of the following: mud-pulse
telemetry device; mud pulse on gyroscope device; gyroscopic
telemetry device on wireline; gyroscopic telemetry electromagnetic
device; gyroscopic telemetry acoustic device; gyroscopic telemetry
mud pulse device; magnetic dipole including single shot and
telemetry; wired casing as shown and described in relation to U.S.
Application Ser. No. 10/419,456 entitled "Wired Casing" and filed
Apr. 21, 2003, which is incorporated by reference herein in its
entirety; and fiber optic sensing devices. Any combination of
sensors and/or telemetry may be utilized in the present invention.
Regardless of the method used, based on the monitored trajectory as
received at the surface, adjustments may be made at the surface
(e.g., adjustments to the stabilizer 4202, weight on bit, speed of
rotation, steering of the motor 4112 or rotary-steerable assembly,
etc.).
[0240] Accordingly, the operations 3308-3310 may be repeated to
extend the wellbore to a desired depth along a well-controlled
trajectory. Once the desired depth is reached, the BHA 4200 may be
retrieved from the wellbore. For example, the BHA 4200 may be
retrieved by unlatching the casing latch 4106 and placing the
stabilizer 4202 and expandable bit 4204 back in the run-in
positions (as shown in FIG. 33A) and pulling the BHA 200 back to
the surface through the casing 4104. The string of casing 4104 may
then be extended into the newly drilled portion of the wellbore,
for example by adding sections of casing 4104 from the surface.
[0241] However, retrieving the BHA 4200 through the entire length
of casing 4104 may require a significant amount of time in which
the formation around the newly drilled (and uncased) portion of the
wellbore may settle, thereby making it difficult to subsequently
advance the string of casing 4104. Therefore, for some embodiments,
prior to completely retrieving the BHA 4200, the BHA 4200 may be
only partially raised through the casing 4104 (e.g., enough that
the bit 4205 is at least partially within the casing 4104). After
partially raising the BHA 4200, the casing 104 may then be advanced
into the newly drilled portion of the wellbore, for example, by
adding additional sections of casing 4104 from the surface. Because
partially raising the BHA 4200 may require significantly less time
than completely raising the BHA 4200 to the surface (as during
retrieval), the likelihood of the formation settling prior to
advancing the casing 4104 is reduced. After advancing the casing
4104, the BHA 4200 may then be completely retrieved.
[0242] While the adjustable stabilizer 4202 is shown in FIGS.
33A-33D as positioned between the bit 4205 and casing latch 4106,
for some embodiments, one or more adjustable stabilizers may be
positioned above the casing latch 4106 instead of, or in addition
to, the adjustable stabilizer 4202. As an example, an adjustable
stabilizer 4202 may be positioned above the casing latch 4106 to
provide support to the casing 4104, which, when utilized as part of
the drilling assembly (including the BHA 4200), may also be
subjected to similar strains as the BHA 4200. In other words, the
casing 4104 may also be subjected to weight on bit and,
particularly in the case of rotary operation, lateral and radial
vibrations. Further, while not shown, a drilling assembly may
include the BHA 4200 attached to a portion of casing run in through
another portion of casing (not shown) already lining the wellbore.
For example, the BHA 4200 may be attached to a portion of
expandable casing. After extending the wellbore with the BHA 4200,
the expandable casing may be advanced and expanded to line the
extended portion of the wellbore. Of course, the BHA 4200 may be
retrieved from the wellbore prior to the expanding.
[0243] In another embodiment, the expandable bit 4205 may be
replaced with a combination of a pilot bit and underreamer.
Embodiments of the present invention provide methods and assemblies
for improved drilling with casing (DwC). By providing an adjustable
stabilizer, the drilling assembly may be adequately supported, thus
avoiding excessive deflection and vibration that commonly occurs in
conventional DwC systems. Further, by, utilizing
measurement-while-drilling equipment, trajectory of the wellbore
may be measured in real time, thus allowing corrections of the
trajectory to be made at the surface increasing the likelihood a
desired trajectory will be achieved. A further additional
embodiment may include closed-loop drilling to control the diameter
of the adjustable stabilizer or motor bend angle, or a 3-D rotary
steerable system. The closed-loop control could be a
microprocessor, either uphole or downhole.
[0244] FIGS. 35-36 show alternate embodiments of a system for
directionally drilling with casing. These embodiments provide
methods and apparatus for drilling with a BHA releasably attached
to casing which allow the directional force for the system to be
placed directly on the casing rather than directly on the BHA.
[0245] FIG. 35 shows casing 2404 with a BHA 2400 releasably
attached to an inner diameter thereof by a casing latch 2406. While
a casing latch 2406 is shown in FIG. 35, any other method for
releasably attaching the BHA 2400 to the inner diameter of the
casing latch 2406 is contemplated for use in the present invention.
The casing latch 2406 performs an orientation function (described
below) as well as the function of releasably connecting the casing
2404 to the BHA 2400. To this end, one or more axial blades 2407
extend radially from the body of the casing latch 2406 portion of
the BHA 2400. Additionally, one or more torque blades 2405 located
below the axial blades 2407 extend radially from the body of the
casing latch 2406. The torque blades 2405 may be included in any
number, as with the axial blades 2407. The axial blades 2407 and
torque blades 2405 are spring-loaded.
[0246] The casing 2404 includes one or more casing sections. FIG.
35 shows three casing sections 2404A, 2404B, and 2404C threadedly
connected to one another. The lower casing section 2404C is
threadedly connected to the middle casing section 2404B by a casing
coupling 2416. The casing coupling 2416 may have female threads at
upper and lower ends for threadedly connecting the lower end of the
middle casing section 2404B to the upper end of the lower casing
section 2404C, respectively. Likewise, the upper casing section
2404A is threadedly connected to the middle casing section 2404B by
a profile collar 2411. The profile collar 2411 may have female
threads at each end for connecting to the male threads of the lower
end of the upper casing section 2404A and to the upper end of the
middle casing section 2404B. The profile collar 2411 includes
profiles 2413 therein for releasably engaging the axial blades 2407
and profiles 2415 therein for releasably engaging the torque blades
2405.
[0247] When employed to connect the BHA 2400 to the casing 2404,
the BHA 2400 with the spring-loaded axial and torque blades 2407
and 2405 are run through the casing 2404. Once the blades 2407 and
2405 reach the profiles 2413 and 2415 in the inner diameter of the
profile collar 2411, the bias force from the spring-loaded blades
2407 and 2405 causes the blades 2407 and 2405 to snap out into
their respective profiles 2413 and 2415. The torque blades 2405
rotate a few degrees before snapping out into the profile collar
2411. The axial blades 2407 prevent the BHA 2400 from translating
axially relative to the casing 2404, and the torque blades 2405
prevent the BHA 2400 from rotating relative to the casing 2404.
While the profiles 2415 and 2413 are shown existing in the profile
collar 2411 in FIG. 35, it is also contemplated for use in the
present invention that profiles may exist in the casing 2404 itself
to releasably engage the axial and torque blades 2407 and 2405.
[0248] An upper portion of the BHA 2400, shown here as the upper
position of the casing latch 2406, possesses one or more packing
elements 2417 on its outer diameter for sealingly engaging an
annulus between the BHA 2400 and the casing 2404. The packing
elements 2417 are preferably elastomeric for providing a seal
between the casing 2404 and the BHA 2400. Additionally, cups 2418
located above and below the packing elements 2417 aid in sealing
the annulus between the casings 2404 and the BHA 2400. The packing
elements 2417 and the cups 2418 extend radially from the BHA 2400
circumferentially around the body of the casing latch 2406.
[0249] The upper end of the casing latch 2406 has threads 2419,
preferably female threads, and/or a fishing profile to allow
collets to latch into or around (see U.S. Pat. No. 3,951,219, which
is herein incorporated by reference in its entirety) for connecting
the BHA 2400 to the surface with a tubular body (not shown) so that
the BHA 2400 can be retrieved at the desired time. Additionally,
the upper end may have a GS profile. Possible tubular bodies which
may retrieve the BHA 2400 include but are not limited to drill
pipe, coiled tubing, coiled rod, or wireline. Below the casing
latch 2406 in the BHA 2400 is a resistivity sub 2420 for housing
one or more resistivity sensors (not shown) therein for use in
taking real-time or periodic resistivity measurements. Around the
resistivity sub 2420 is a stabilizer 2422 which extends radially
from and preferably circumferentially around the BHA 2400. The
stabilizer 2422 bridges the annulus between the BHA 2400 and the
casing 2404 and maintains the position of the BHA 2400 within the
casing 2404 at a preferred axial location to stabilize the BHA 2400
relative to the casing 2404.
[0250] The resistivity sub 2420 may contain one or more geophysical
sensing devices capable of measuring parameters such as formation
resistivity, formation radiation, formation density, and formation
porosity. The sensing devices may be latched therein by embodiments
of mechanisms shown in FIGS. 4247 (see below). The section of
casing (here, the middle casing section 2404B) disposed around the
portion of the BHA 2400 having the resistivity device therein
preferably has one or more resistivity antennas for use with the
resistivity device. The resistivity sub 2420 is not required for
use in the present invention, but only when resistivity
measurements are desired during or after drilling.
[0251] Below the resistivity sub 2420 in the BHA 2400 is an MWD/LWD
sub 2424, which may house one or more MWD or LWD sensing devices
including, but not limited to, one or more of the following:
mud-pulse telemetry device; mud pulse on gyroscope device;
gyroscopic telemetry device on wireline; gyroscopic telemetry
electromagnetic device; gyroscopic telemetry acoustic device;
gyroscopic telemetry mud pulse device; magnetic dipole including
single shot and telemetry; wired casing as shown and described in
relation to U.S. Application Ser. No. 10/419,456 entitled "Wired
Casing" and filed Apr. 21, 2003, which is incorporated by reference
herein in its entirety; and fiber optic sensing devices. Any
combination of sensors and/or telemetry may be utilized in the
present invention. As with the resistivity sub 2420 sensing
devices, the MWD/LWD sub 2424 sensing devices may be latched
therein by the mechanism shown in FIGS. 4-472. The sensing
device(s) within the MWD/LWD sub 2424 are utilized to measure the
angle with respect to the vertical axis of the casing 2404 at the
surface of the earth to which the casing 2404 is deflected. The
angle may be measured in real time while drilling the casing 2404
into the earth while the surveying tool remains within the MWD/LWD
sub 2424, or alternatively, the angle may be measured periodically
by halting drilling temporarily to lower the surveying tool into
the MWD sub 2424 and measure the orientation of the casing 2404.
Measuring the angle at which the casing 2404 is being or has been
drilled allows the operator to adjust conditions, such as amount of
drilling fluid flowed through the casing 2404 or the force placed
on the casing 2404 from the surface to lower the casing 2404 into
the earth formation, to alter the angle of deflection of the casing
2404 within the formation.
[0252] Because same directional MWD and LWD sensors are magnetic,
the casing 2404 surrounding the MWD/LWD sub 2424 must usually be
non-magnetic. However, because the casing 2404 is left downhole
when drilling with casing, and because non-magnetic casing is more
expensive than the magnetic casing usually drilled with when
drilling with casing, it is desirable in some situations to drill
with magnetic casing. To this end, a gyroscope may be utilized as
the directional MWD/LWD sensor to eliminate the necessity to use
non-magnetic casing around the MWD/LWD sub 2424. Magnetic casing
may then be disposed around the MWD/LWD sub 2424. A preferred
gyroscopic sensor for use in the present invention is a Gyrodata
Gyro-Guide GWD gyro-while-drilling tool, as shown and described in
Gyrodata Services Catalog, 2003, at page 31. Gyro-Guide is a fully
integrated guidance system housed in the MWD tool string (here, the
BHA 2400) which includes wireless telemetry for surveying while
drilling. Use of the Gyro-Guide allows gyro-while-drilling rather
than the operator having to repeatedly stop the drilling process,
place the surveying tool (e.g., gyroscope) into the casing 2404
with wireline, take measurements, then remove the surveying tool
prior to drilling further.
[0253] Below the MWD/LWD sub 2424 in the BHA 2400 is a mud motor
2425. Connected below the mud motor 2425 is an underreamer 2426 and
a pilot bit 2428. The pilot bit 2428 and the underreamer 2426 may
be replaced by a bi-center bit in one embodiment. The mud motor
2425 provides rotational force to the underreamer2426 and pilot bit
2428 relative to the mud motor 2425 through a motor bearing pack
2429 when it is desired-to rotate the pilot bit 2428 relative to
the BHA 2400 and the casing 2404 and rotationally drill into the
formation. The mud motor 2425 utilized may be similar to he mud
motor shown and described in relation to FIGS. 1-12. The pilot bit
2428 and underreamer 2426 drill the casing 2404 into the formation.
The pilot bit 2428 preferably has side cutting capability to allow
the casing 2404 to veer at an angle with respect to the centerline
of the wellbore after drilling to the side of the wellbore.
[0254] An optional stabilizer 2430 similar to the stabilizer 2422
may be located around the outer diameter of the BHA 2400 at a
location near the connection between the MWD/LWD sub 2424 and the
mud motor 2425. The stabilizer 2430 is preferably located adjacent
to an eccentric casing bias pad 2435 (described below). Like the
stabilizer 2422, the stabilizer 2430 also maintains the axial
location of the BHA 2400 relative to the casing 2404 by bridging
the annulus between the BHA 2400 and the casing 2404. An additional
concentric stabilizer 2432 is disposed concentrically around the
outer diameter of the mud motor 2425 near the lower end of the
casing 2404 to stabilize the lower end of the BHA 2400 relative to
the casing 2404.
[0255] The primary impetus for the directional bias of the casing
string 2404 (with respect to the vertical axis of the casing string
2404 entering the formation from the surface) exists due to an
eccentric casing bias pad 2435. The casing bias pad 2435 is
disposed on only one side of the casing 2404 on the outer diameter
of the casing 2404 to push the centerline of the casing 2404 at an
angle with respect to the wellbore centerline, thus eccentering the
casing 2404 relative to the wellbore. The casing bias pad 2435 is
mounted near the lower end of the casing 2404. The directional bias
angle of the casing 2404 is in the opposite side of the casing 2404
from the side of the casing 2404 to which the casing bias pad 2435
is attached. For example, as shown in FIG. 35, the eccentric bias
pad 2435 is located on the right side of the casing 2404;
therefore, the deviation angle of the casing 2404 will be to the
left of the centerline of the wellbore. In one embodiment, the
casing bias pad 2435 may cover approximately 90-100 degrees of
circumference, but any angle is possible with the present
invention. The height of the casing bias pad 2435, or the distance
from the inner side of the casing bias pad 2435 mounted on the
outer diameter of the casing 2404 to the outer side of the casing
bias pad 2435 farthest from the casing 404 outer diameter, is
predetermined prior to insertion of the assembly into the wellbore.
The height of the casing bias pad 2435 at least partially
determines the angle at which the casing 2404 deviates from the
centerline of the wellbore. In an additional embodiment of the
present invention, the bias pad 2435 may instead be an eccentric
stabilizer
[0256] With the eccentric casing bias pad 2435, the directional
force for directionally drilling the wellbore at an angle is
provided essentially perpendicular to the portion of the casing
bias pad 2435 perpendicular to the axis of the casing 2404. The
force is translated from the outer portion of the casing bias pad
2435 to the casing 2404 so that the directional force is primarily
born by the casing 2404 rather than the BHA 2400, primarily because
the BHA 2400, is housed almost completely within the casing 2404
rather than a large portion of the BHA 2400 extending below the
casing 2404. In the embodiment shown in FIG. 35, the pilot bit
2428, the underreamer 2426 and a portion of the mod motor 2425 are
the only portions of the BHA 2400 which extend below the casing
2404. Preferably, the length of the exposed BHA 2400 is
approximately 5-10 feet in length. Ultimately, the directional bias
force transmits from the wellbore, to the casing bias pad 2435, to
the stabilizer 2432, through the motor bearing pack 2429, and then
to the underreamer 2426 and pilot bit 2428.
[0257] The casing latch 2406, in addition to performing the
function of latching the BHA 2400 to the casing 2404, orients the
face of the MWD or LWD tool (not shown) located within the BHA 2400
to the casing bias pad 2435 so that the location of the casing bias
pad 2435 on the casing 2404, and consequently the angle at which
the casing 2404 is drilling, is readily ascertainable with respect
to some reference point. The torque blades 2405 of the casing latch
2406 maintain the rotational position of the BHA 2400 relative to
the casing 2404, therefore orienting the sensor with respect to
where the eccentric pad 2435 is located by preventing rotation of
the BHA 2400 within the casing 2404. Similarly, the MWD/LWD tool
may be latched into the MWD/LWD sub 2424 by the apparatus and
method shown and described in relation to FIGS. 42-47 so that the
MWD/LWD tool does not rotate with respect to the casing latch 2406
body, thus maintaining the rotational position of the MWD/LWD tool
with respect to the casing latch 2406 body so that the position of
the eccentric bias pad 2435 is readily ascertainable. Thus, the
operator can keep track of which in direction the casing 2404 is
being drilled so that the wellbore can continue to be drilled in
the same direction if desired.
[0258] FIG. 36 shows casing 2504 with a BHA 2500 releasably
attached to an inner diameter thereof by a casing latch 2506. As
stated above in relation to FIG. 35, the casing latch 2506 may be
substituted with any other means for attaching the casing 2504 to
the BHA 2500. The casing components including the casing sections
2504A, 2504B, 2504C; profile collar 2511 including profiles 2513,
2515; and casing coupling 2516 are substantially similar to the
casing sections 2404A, 2404B, 2404C, profile collar 2411, profiles
2413, 2415, and casing coupling 2416 shown and described in
relation to FIG. 35. Also, most of the BHA components including the
threads 2519; packing element 2517 and cups 2518; axial and torque
blades 2507 and 2505; resistivity sub 2520; MWD/LWD sub 2524;
underreamer 2526; pilot bit 2528; and stabilizers 2522, 2530, and
2532 are substantially similar to the threads 2419, packing element
2417, cups 2418, axial and torque blades 2407 and 2405, resistivity
sub 2420, MWD/LWD sub 2424, underreamer 2426, pilot bit 2428, and
stabilizers 2422, 2430, and 2432, as shown and described in
relation to FIG. 35. Therefore, the above description of these
components applies equally to the embodiment shown in FIG. 36.
[0259] The casing latch 2506 of FIG. 36 is substantially similar to
the casing latch 2406 of FIG. 35, so the majority of the above
description of the casing latch 2406 applies equally to the
embodiment shown in FIG. 36. The primary difference between the
casing latch 2506 and the casing latch 2406 is that the casing
latch 2506 of FIG. 36 does not have to be an orienting latch to
keep track of the location of the casing bias pad 2535, as the
casing bias pad 2535 of FIG. 36 acts as a concentric stabilizer
(see description below).
[0260] Instead of the mud motor 2425 of FIG. 35, a bent housing mud
motor 2550 is connected to the lower end of the MWD/LWD sub 2524.
The bent housing mud motor 2550 includes a bent motor connecting
rod housing 2555 that is bent at an angle to cause the casing 2504
to deviate while drilling at an angle with respect to the
centerline of the wellbore. The bent motor connecting rod housing
2550 is angled with respect to the rest of the BHA 2500 at the
angle and direction in which it is desired to bias the casing
2504.
[0261] An additional difference between the system of FIG. 35 and
the system of FIG. 36 is that rather than the eccentric casing bias
pad 2435 of FIG. 35, the casing bias pad 2535 of FIG. 36 is
circumferential and can be termed a stabilizer. Rather than an
eccentric bias pad providing the orientation angle of the casing
2504, the bent motor connecting rod housing 2555 provides the
orientation angle.
[0262] Just as in the embodiment of FIG. 35, the embodiment
illustrated in FIG. 36 shows a majority of the BHA 2500 located
within the casing 2504. The only portions of the BHA 2500 which are
located below the casing 2504 are a portion of the bent motor
connecting rod housing 2555, the motor bearing pack 2529,
underreamer 2526, and pilot bit 2528. Again, the length of the BHA
2500 below the casing 2504 is preferably only approximately 5-10
feet.
[0263] In the operation of the embodiment of FIG. 36, the
directional bias force is provided by the motor bend, which pushes
against the side of the wellbore, causing a resultant force on the
opposite side of the pilot bit 2528 and underreamer 2526. However,
the directional force is transmitted by the casing 2504 instead of
the BHA 2500, as in the embodiment of FIG. 35, so that the
directional bias force transmits from the wellbore, to the casing
bias pad 2535, then to the stabilizer 2532, through the motor
bearing pack 2529, and then to the underreamer 526 and pilot bit
2528.
[0264] As in the embodiment shown in FIG. 35, the height of the
casing bias pad 2535 is predetermined before lowering the assembly
downhole. However, in the embodiment of FIG. 36, the mud motor bend
angle is adjustable from the surface and/or downhole to adjust the
angle at which the casing 2504 is drilled. In the embodiments of
both FIGS. 35 and 36, the height and/or diameter of the casing bias
pad 2435, 2535 (or eccentric stabilizer) is also adjustable from
the surface of the wellbore and/or downhole.
[0265] In the embodiments of FIGS. 35-36, the non-magnetic casing
section 2404C or 2504C may be constructed of any non-magnetic
material consistent with MWD sensors. Also, other non-magnetic
casing alternatives are contemplated for use with the present
invention. The non-magnetic casing may be composite or metallic.
Resistivity measurements from the resistivity sub 2420, 2520 may
require repackaging of the sensor antennas and/or a special
resistivity casing joint.
[0266] In the above embodiments shown and described in relation to
FIGS. 35-36, in lieu of the underreamer 2426, 2526 and pilot bit
2428, 2528, an expandable bit (not shown) which is expandable to
drill the wellbore, then retractable to a smaller outer diameter
when retrieving the BHA 2400, 2500 from the casing 2404, 2504 may
be utilized. An example of an expandable bit which may be used in
the present invention is described in U.S. Patent Application
Publication No. US2003/111267 or U.S. Patent Application
Publication No. 2003/183424, each of which is incorporated by
reference herein in its entirety.
[0267] The BHA 2400, 2500 components, including the latch 2406,
2506; MWD/LWD sub 2424, 2524; and resistivity sub 2520, may be
arranged in a different order than is shown in FIGS. 35-36.
Additionally, the stabilizers 2422; 2522; 2430, 2530; and 2432,
2532 may be placed in different longitudinal locations on the o.d.
of the BHA 2400, 2500.
[0268] The operation of embodiments depicted in FIGS. 35-36
includes assembling the BHA 2400, 2500 and casing 2404, 2504. The
BHA 2400, 2500 and casing 2404, 2504 assembly is then lowered into
the formation and the assembly is caused to drill at an angle with
respect to a vertical wellbore drilled into the formation. If
desired, the mud motor may rotate the pilot bit 2428, 2528 while
drilling at the angle. Once the assembly has drilled to the desired
depth at which to leave the casing 2404, 2504 within the wellbore,
the BHA 2400, 2500 is detached from the casing 2404, 2504. The
casing 2404, 2504 is lowered over the BHA 2400, 2500, and the BHA
2400, 2500 is then retrieved from the wellbore using a tubular body
such as drill pipe or wireline. The casing 2404, 2504 may then be
cemented into the wellbore. Additional casing (not shown) may then
be drilled through the casing 2404, 2504 into the formation and may
be expanded into the casing 2404, 2504. This process may be
repeated as desired.
[0269] FIG. 37 shows another embodiment of a directional drilling
assembly. Particularly, the BHA 2700 is equipped with an
articulating housing 2760 to provide the directional bias for
drilling. As shown, the BHA 2700 is releasably attached to an inner
diameter of the casing 2704 using a casing latch 2706. As stated
above in relation to FIGS. 35 and 36, the casing latch 2706 may be
substituted with any other means for attaching the casing 2704 to
the BHA 2700. The casing components including the casing sections
2704A, 2704B, 2704C; profile collar 2711 including profiles 2713,
2717; and casing coupling 2716 are substantially similar to the
casing sections 2404A, 2404B, 2404C, profile collar 2411, profiles
2413, 2415, and casing coupling 2416 shown and described in
relation to FIG. 35. Also, most of the BHA components including the
threads 2719; packing elements 2717 and cups 2718; axial and torque
blades 2707 and 2705; resistivity sub 2720; MWD/LWD sub 2724;
underreamer 2726; pilot bit 2728; and stabilizers 2722, 2730, and
2732 are substantially similar to the threads 2419, packing
elements 2417, cups 2418, axial and torque blades 2407 and 2405,
resistivity sub 2420, MWD/LWD sub 2424, underreamer 2426, pilot bit
2428, and stabilizers 2422, 2430, and 2432, as shown and described
in relation to FIG. 35. Therefore, the above description of these
components applies equally to the embodiment shown in FIG. 37.
[0270] Instead of a bent motor 2550 as shown in FIG. 36, a drilling
motor 2750 equipped with an articulating housing 2760 is used to
provide torque to rotate the pilot bit 2728 and the underreamer
2726 as illustrated in FIG. 37. The articulating housing 2760 can
be pivoted to create an angle between the drilling motor 2750 and
the motor bearing pack 2729, thereby causing the pilot bit 2728 to
drill at an angle with respect to the centerline of the wellbore.
In comparison to the bent motor 2550, the articulating housing 2760
allows the drilling motor 2750 to pass through the casing 2404 in a
substantially concentric manner. In this respect, a larger drilling
motor may be installed on the bottom hole assembly, thereby
providing more power to the pilot bit 2728.
[0271] FIGS. 38A-B depict an exemplary articulating housing 2760
according to aspects of the present invention. The articulating
housing 2760 includes a first articulating member 2761 engageable
with a second articulating member 2762 as shown in FIG. 38A. In one
embodiment, the first articulating member 2761 is connected to the
drilling motor 2750, and the second articulating member 2762 is
connected to the motor bearing pack 2729. As shown, the first and
second articulating members 2761, 2762 are coupled using two male
and female connections 2765. Specifically, each of the male
connection members 2763 of the first articulating member 2761 is
coupled to a respective female connection member 2764 of the second
articulating member 2762. A pin 2766 may be inserted through each
male and female connection 2765 to ensure engagement of the
articulating members 2761, 2762. Additionally, a sleeve 2767 may be
disposed around the pins 2766 to prevent the separation of the pin
2766 from the connections 2765. In turn, the sleeve may be attached
to the articulating housing 2760 using another pin or screw 2769.
Optionally, the first articulating member 2761 may include one or
more stabilizers 2768 formed thereon.
[0272] FIG. 38B is another cross sectional view of the articulating
housing 2760, which is rotated 90 degrees when compared to FIG.
38A. As shown, the second articulating member 2762 is deviated from
the centerline of the first articulating member 2761. This is
because the pin connection 2765 acts like a hinge to allow relative
rotation between the first and second articulating members 2761,
2762. In this respect, the motor bearing pack 2729 and the pilot
bit 2728 may be deviated from a centerline of the drilling motor
2750. Preferably, the articulating housing 2760 is adapted to allow
the motor bearing pack 2729 deviate up to about 7 degrees from the
centerline; more preferably, up to about 5 degrees; and most
preferably, up to about 3 degrees.
[0273] FIGS. 39-41 show another embodiment of a directional
drilling assembly. In FIG. 39, a BHA 2900 is being conveyed through
a casing 2904. The BHA 2900 includes a casing latch 2906, a MWD/LWD
tool 2924, an expandable stabilizer 2902, and a flexible collar
2910. The drilling motor 2950 is equipped with an articulating
housing 2960 and a motor bearing pack 2929. An expandable bit 2928
is employed to extend the wellbore. It must be noted that the
description of the components provided herein applies equally to
the embodiment shown in FIGS. 39-41. For example, the MWD/LWD tool
2924 may include sensors to monitor conditions in the wellbore such
as pressure and temperature as previously described. During run-in,
the expandable stabilizer 2902 and the expandable bit 2928 are
collapsed. Additionally, the articulating housing 2960 is
substantially vertical. When compared to a BHA having a bent motor,
the articulating housing 2960 provides more clearance between the
drilling motor 2950 and the casing 2904. In this respect, a larger
drilling motor may be used to generate more torque downhole.
[0274] In FIG. 40, the BHA 2900 has reached the bottom of the
wellbore, but the drilling process has not started. As shown, the
casing latch 2906 has been actuated to engage the BHA 2900 with the
casing 2904. It can also be seen that the articulating housing 2960
and the BHA 2900 are still substantially vertical.
[0275] In FIG. 41, the drilling process has begun. The articulating
housing 2960 is actuated by applying weight to the housing 2960.
Because the expandable bit 2928 is in contact with the bottom of
the wellbore, the housing 2960 experiences a force from above and
below, thereby causing the housing 2960 to bend. In this manner,
the expandable bit 2928 may be deviated from the centerline.
Furthermore, the expandable stabilizer 2902 may be utilized to
assist with direction control as discussed above. For example, the
expandable stabilizer 2902 may be partially expanded and partially
retracted as shown. Also, it can be seen that the expandable bit
2928 has been expanded to created larger diameter hole to
accommodate the casing 2904.
[0276] Referring initially to FIG. 42, there is shown, in
cross-section, a wellbore 10A in which drilling operations are
being performed. Wellbore 10A is a directionally drilled borehole,
having an entry portion 12A extending from the earth's surface 14A
to a deviated portion 16A extending into a formation 18A from which
hydrocarbons are likely to be found. The borehole 10A, although
shown as having a generally dogleg profile, may have other
profiles, such as deviating from vertical immediately upon entry to
the earth.
[0277] To drill into the earth and thereby form borehole 10A, a
drill string 20A, comprising a plurality of individual lengths of
pipe or tubing 22A (one such shown in FIG. 43) and downhole
equipment, such as a bent sub 30A, drill bit 32A and/or float tools
34A needed for drilling the well, are suspended from a drilling
platform 24A of a rig 26A. On rig 26A are provided equipment (not
shown) for setting the rotational alignment of the drill string
20A, to control the depth position of the drill string 20A, and to
provided fluids such as drilling mud, water, cement, or other
fluids used in the drilling of wells into the borehole 10A or down
the hollow central portion 28A (shown in FIG. 43) of the drill
string 20A to power the drill motor to turn the drill bit 32A.
[0278] Referring now to FIG. 43, there is shown a float sub 34A of
the present invention, in this embodiment being integrally formed
within a section of tubing 20A within the bent sub portion and thus
placed into the drill string 20A at the time the drill string 20A
was inserted into the earth. Float sub 34A generally includes an
annular body portion 36A, having a configured central aperture 38A
therethrough in which downhole peripherals such as mule shoe 52A
and valve 42A may be positioned. The body portion 36A is preferably
configured of a drillable material such as the cement used to
secure the annulus between the borehole and the drill string 20A
where the drill string 20A is used as casing, or of plastic, cast
iron, aluminum, or such other easily drillable material such that
the body portion, and the attendant mule shoe 52A and valve 42A can
be easily removed from the casing by drilling them out in position
in the drill string 20A. Central aperture 38A includes an upper
guide portion 44A, in this embodiment configured as an integral
frustoconical surface narrowing from an anti-rotation profile 31A
formed at the upper surface of the float sub body 34A leading to
landing bore 46A, and terminating in enlarged valve receipt bore
48A. Landing bore 46A is a generally right cylindrical bore, having
an alignment sleeve 50A disposed therein within which is provided
shoe 52A for the receipt of a survey tool 60A (shown positioned
above the float sub 34A in FIG. 43) in an aligned position within
the float sub 34A. As shown in FIG. 43, shoe 52A is generally a
tubular member, the upper end of which is received in secured
engagement with the inner diameter of sleeve 50A at the lowermost
end thereof in the landing bore 40A. The upper surface of shoe 52A
is provided with a mule shoe profile 54A, i.e., the uppermost
annular surface 56A of shoe 52A facing in an up-bore direction is
configured as a plane cut across the tubular profile of the shoe
52A at an angle to the centerline of the shoe 52A, such that the
perimeter of the upper terminus of the shoe 52A at mule shoe
profile 54A is an ellipse. Shoe 52A additionally includes a slot
58A, extending in a downhole direction from mule shoe profile 54A,
in the wall of the shoe 52A. It is understood that the mule shoe
profile 54A may include other geometries in addition to an
ellipse.
[0279] Referring still to FIG. 43, valve body 62A is received
downhole from shoe 52A, in valve receipt bore 48A. Valve body 62A
generally includes a housing 64 having a through-bore 66A
therethrough which extends from the lowermost extension of shoe 52A
to a valve assembly 68A. Housing 64A is preferably cast in,
threaded into, or otherwise permanently secured within body 34A
before loading the float sub 34A into the drill string 20A. Valve
assembly 68A is shown in this embodiment as a "flapper"-type valve,
i.e., a valve wherein a cover plate 70A is connected by a
spring-loaded hinge 72A to the housing 64A, such that cover plate
70A is positioned when in a closed position over the opening of
bore 66A at the underside of the housing 64A to thereby seal the
bore from entry of fluids from a location downhole therefrom into
the bore 66A, and thus into the hollow interior region 28A of the
drill string 20A. However, when fluid is directed down the hollow
interior region 28A of the drill string 20A, such fluid may pass
through the hollow interiors of the sleeve 50A and mule shoe 52A,
and thus throughthe through-bore 66A to provide a sufficient force
bearing upon the valve to cause the cover plate 70A to swing open
about the hinge 72A, thereby allowing such fluids to pass
therethrough and thence onwardly down the portion of the drill
string 20A therebelow. The fluid may exit into the wellbore through
the mud passages in the bit. In another embodiment, the fluid may
pass through the powering passages in the mud-driven drill motor
(not shown) before reaching the bit. The configuration of the float
sub 34A shown in FIG. 43 locates the sleeve 50A generally
co-linearly with the center of drill string 20A, and thus the
receipt of a survey tool therein, as will be described further
herein, will position the survey tool in the center of the drill
string 20A. However, there exist survey tools where it would be
useful to have the survey tool to one side of the drill string 20A,
therefore, the bore 46A of the float sub 34A may be offset to one
side or the other (i.e., not co-linear with the drill string 20A
centerline) such that the sleeve 50 will likewise be offset from
the centerline of the drill string 20A.
[0280] Referring still to FIG. 43, a survey tool 60A is shown
within drill string 20A suspended on a wireline 102A above (or
adjacent to) float sub 34A. Survey tool 60A generally includes a
hollow, generally cylindrical body 104A having an outer cylindrical
portion 106A having an inner diameter substantially equal to that
of shoe 52A, and an outer diameter slightly smaller than the inner
diameter of the sleeve 50A within which shoe 52A is received; an
upper cover portion 108A from which wireline extends from the tool
60A; and an open lower end 110A. The lower end 110A is likewise
configured with a mating mule shoe profile 100A (shown in FIG.
43A), cut at the same angle as that of shoe 52A, to provide a
mating elliptical surface to that of the mule shoe profile 54A on
shoe 52A. FIG. 43A shows a side view of the survey tool 60A having
a mating profile 100A for mating with the mule shoe profile 54A on
the shoe 52A.
[0281] To retrieve the survey tool 60A from the well where the tool
60A becomes separated from the wireline 102A, cover portion 108A
may include a fishing neck 112A thereon for retrieving of the
survey tool 60A with a fishing tool (not shown). In another
embodiment, the tool 60A may be intentionally separated from the
wireline 102A and left in place. In another embodiment still, the
tool 60A may be pre-assembled with shoe 52A only to be retrieved
later by wireline or pipe. The body 104A further includes a
plurality of flow passages 116A extending therethrough which enable
fluids to flow between the hollow portion 28A of the drill string
20A and the interior volume 118A of the body 104A. A plurality of
stabilizers 120A are located on the outer surface of body 104A help
center the survey tool 100A in the drill string 20A as it is
lowered from the surface through hollow portion 28A.
[0282] Within survey tool 60A and connected to wireline 102A
passing through upper cover portion 108A is a diagnostic apparatus
114A. In the embodiment shown, this diagnostic apparatus 114A is a
geosensor and sender combination which, in conjunction with. a
computer and computer program therein, is able to determine
orientation of the borehole 10A in the earth, and thus is needed to
ensure that the borehole 10A is progressing in the desired
direction once the rotational position of the survey tool 60A is
known.
[0283] Referring now to FIG. 44, the receipt of survey tool 60A in
shoe 52A is shown. Survey tool 60A is lowered down the hollow
portion 28A of drill string 20A on wireline 102A such that lower
end 110A thereof is received within landing bore 46A of float tool
34A. Where survey tool 60A is axially misaligned with landing bore
46A, i.e., is offset to one side of the drill string 20A, the lower
end thereof will engage the tapered surface 44A on alignment bore
46A and be guided to the opening of sleeve 50A. Thence survey tool
60A is further lowered, such that the lower end thereof enters
sleeve 50A and the mating mule shoe profile 100A on the lower end
110A of survey tool 60A will contact the mule shoe profile 54A on
shoe 52A. Where the rotational alignment of the two profiles is not
such that the plane of their elliptical faces is not parallel,
further lowering of the survey tool 60A will cause the end 110A of
survey tool 60A to slide upon the mule shoe profile. 54A of shoe
52A, simultaneously causing the survey tool 60A to rotate until the
survey tool 60A is fully received against profile 54A such that the
planar elliptical faces of each of profiles 54A, 100A are in
parallel contact.
[0284] In the preferred embodiment hereof, the drill shoe includes
a cutting apparatus which may be a traditional rock bit, a drill
motor, or the like, preferably configured to be drilled through by
a subsequent, smaller drill shoe passed down the casing.
Alternatively, the drill shoe may include a jet section having a
plurality of fluid jets extending from a central bore thereof (not
shown) to the exterior thereof in a known circumferential position.
Preferably, as is known in the art, the fluid jets may be
selectively controlled to enable jetting into the formation for
removal of formation materials and thereby create a deviation in
the direction of the borehole direction. Thus, the drill string (or
drill motor) may be rotated to drill ahead or the jets may be
oriented by rotational positioning and selection thereof to drill
directionally. The drill shoe also preferably includes a plurality
of mud passages therethrough, through which drilling fluids may
pass to lubricate or cool the cutting surface and enable the
removal of cuttings from the borehole as the drilling fluid is
recirculated to the earth's surface.
[0285] The orientation or rotational alignment of the mule shoe
profile 54A, being known prior to the placement of the survey tool
60A therein, enables multiple functions to be accomplished downhole
with a high degree of reliability. In one aspect, the survey tool
60A may be a gyroscope, which is adapted to acquire information
relating to wellbore position. The position information is
communicated to the surface via the wireline 1 20A. Particularly,
surface components or controllers may receive information relating
to the orientation of the gyro and the rotational position of the
casing, including the bent sub. In turn, the position of the casing
or the bent sub may be changed by rotating the casing at the
surface to provide the desired orientation or position. Thereafter,
the gyro may be removed via the wireline 120A, or if necessary via
a fishing tool. After orientation, drilling or jetting through
selective ports of the jet portion of the drill shoe may be
undertaken to establish a new or desired direction of the borehole.
The new direction of the borehole may be determined and verified by
landing the gyro on the muleshoe profile 54A. Any additional
directional modification may be performed, as needed, according to
the method described above.
[0286] Alternatively, a measure-while-drilling tool ("MWD tool") or
LWD tool 600A having a survey tool 660A may be used to determine
and steer the drill shoe (located below 620A) as drilling
progresses, as illustrated in FIG. 47. Many types of sensors may be
utilized, including magnetic, gravity, gyro sensors and any
combination thereof. Additionally, many types of telemetry
including mud-pulse, electromagnetic, acoustic, wireline,
fiberoptic, wired casing, and any combination thereof. Any
combination of sensors and telemetry may be utilized. The advantage
of using the fluid-driven or continuous MWD/LWD tool 600A is that
the drilling may continue with the survey tool 660A landed on the
bore 646A. The drilling may continue using a drill motor 625A,
wherein the casing 605A need not be rotated as the drill shoe 620A
is then mud flow powered, or a traditional rock bit is used and the
casing 605A. may be turned to supply the formation-bit motion and
cutting power. The MWD/LWD tool 600A may be equipped with a mud
pulse telemetry component 610A to send information such as
inclination and azimuth of the wellbore back to the surface. In one
aspect, mud pulse telemetry 610A includes manipulating fluid flow
through holes 616A by varying the total flow area of the holes 616A
such that pressure pulses are perceivable at the surface. In this
respect, mud pulse telemetry 610A is a way to communicate
information from downhole to surface. In this manner, the direction
of the borehole may be checked with or without ongoing drilling
operation in the borehole. It must be noted that information may
also be sent back to the surface using other methods known to a
person of ordinary skill in the art, for example electromagnetic
communication.
[0287] Referring to FIGS. 42-44, the float sub 34A and survey tool
60A, in combination, enable simultaneous survey and drilling
operations, as well as other simultaneous operations. which may be
useful in the downhole location. Specifically, survey tool 60A may
be securely located in float sub 34A, while drilling mud, water,
cement, or other liquids are flowed therethrough. Specifically,
where fluids are flowed from the surface location and down hollow
portion 28A of drill string 20A, such fluid, upon reaching survey
tool, bears upon survey tool and tends to maintain it against shoe
52A, and such fluid likewise flows through flow passages 116A to
the hollow interior 118A of the survey tool. Thence, such fluids
flow through the hollow bore of shoe 52A and bore 66A in the valve
body 64A, such that they bear upon and open or maintain open the
valve cover plate 70A, and thus continue flowing down the remainder
of the drill string 20A to locations such as the drill or mud motor
and mud passages in the drill bit (not shown) and thence up the
annulus between the drill string 20A and the borehole 10A. If the
flow of fluid down the drill string 20A is interrupted or stopped
or the pressure below the valve 68A exceeds the pressure of the mud
at the valve 68A, the fluid in annulus will reflow back up the
drill string 20A unless blocked. Such reflow would dislodge the
survey tool from the shoe 52A, and may damage survey tool 60A.
However, as cover plate 70A on valve body 42A is spring-loaded by
hinge 72A to be biased in a closed direction, where the pressure
above the valve approaches the back pressure exerted against the
valve, the cover plate 70A will close over bore 66A. Further
increases in back pressure caused by the fluid in the annulus 10A
will only increase this closing force, thereby sealing off bore 66A
and preventing further backflow or reflow of the fluids up the
drill string 20A. Although the valve 68A has been described as a
flapper-type valve, other valves such as check valves, poppet
valves, auto-fill valves, or differential valves, the operation and
construction of which are well known to those skilled in the art,
may be substituted for the flapper valve without deviating from the
scope of the invention.
[0288] Referring now to FIGS. 45 and 46, an alternative survey tool
configuration is shown. In this embodiment, survey tool 200A is in
all cases structured similar to survey tool 60A, except mule shoe
profile of the survey tool 60A is replaced such that open lower end
202A of survey tool 200A is generally a right circular cylinder,
and an alignment lug 204A is provided on the outer surface of tool
200A. As this tool is lowered into the float sub 34A from the
position of FIG. 45 to the fully-landed position of the survey tool
200A of FIG. 46, lug 204A will engage the mule shoe profile 54A of
shoe 52A and slide therealong, thereby rotating the survey tool
200A, as shown by the 90-degree turn of the tool 200A between FIG.
45 and FIG. 46, as tool 200A is further loaded into shoe 52A, until
lug 204A is aligned with slot 58A, whence further lowering of tool
200A causes lug 204A to travel down to the base of slot 58A at
which time tool 200A is fully engaged and aligned in shoe 52A. The
survey tool 204A is smaller in diameter than survey tool 60A, as it
must slide into shoe 52A whereas survey tool 60 rests upon the
upper surface of the shoe 52A. Survey tool 200A is in all other
respects identical to survey tool 60A, and the operation of the
tool 200A in conjunction with mudflow therethrough is identical to
that of survey tool 60A.
[0289] As with survey tool 60A, the orientation or rotational
alignment of the survey tool 200A is known with respect to the
position of the bent sub, the drill shoe, or the jet section, as
the orientation of the slot 58A is known with respect to these
portions of the drill string when they are assembled together
before entering the borehole. Thus, survey tool 200A may comprise a
gyro, and signals therefrom indicative of the direction in which
the borehole is progressing and the alignment or orientation of the
drill shoe components may be sent on wireline 120A to the surface
to enable repositioning of the drill shoe components if needed, as
was accomplished with respect to the survey tool 60A. Likewise, an
MWD/LWD tool could be landed in the float sub 34A and utilize the
alignment provided by the slot 58A to continue drilling and
steering using the MWD/LWD. While the MWD/LWD tool is landed on the
float sub 34A, the MWD/LWD tool can commurnicate the survey
information to the surface via mud pulse telemetry, thereby
eliminating the need to remove the survey tool to further drill the
borehole.
[0290] The float sub 34A of the present invention provides multiple
useful downhole features when provided in a drill string 20A.
First, the position of the shoe 52A relative to the drill bit is
noted prior to placement of the float sub 34A down the borehole,
thereby enabling the use of data retrieved from or calculated by
the survey tool to have a meaningful relation to the face being
drilled. Additionally, the shoe 52A enables a known rotational
alignment of the well survey tool 60A, 200A, when seated in the
float sub 34A, which likewise enables meaningful data retrieval and
generation for bit heading. Further, the use of an aligning element
in combination with flow through the survey tool 60A, 200A housing,
allows the drilling mud or other fluid flowing down the drill
string 20A to be used to ensure that the survey tool 60A, 200A
remains fully seated and thus properly oriented, as surveying is
occurring, and likewise allows survey to occur when fluids are
flowing through the system and thus as drilling is ongoing.
[0291] In each instance, after surveying is completed and well
production need be initiated, the float sub 34A components must be
removed or otherwise rendered non-impeding to the production of
fluid from the well. Because the survey tool 60A 200A is merely
sitting in the float sub 34A, it may be easily removed from the
float sub 34A such as by extending a fishing tool (not shown) and
engaging fishing neck 112A to pull the survey tool from the drill
string 20A, or if the wireline 102A is sufficiently strong, the
survey tool may be pulled up with the wire 102A. In another aspect,
the survey tool 60A, 200A may be latched in the float sub 34A with
a collet assembly, secured in place with shear screws or other
methods known to a person of ordinary skill whereby the survey tool
may be retrieved with relative ease.
[0292] Once the survey tool is removed, the float sub 34A is used
to enable cementing of the casing 22A comprising the drill string
30A in place in the borehole, to case the borehole. Specifically,
cement is flowed down the interior 28A of the casing 20A, and
through the float sub 34A (as flowed drilling fluids), and thence
out the mud passages in the drill shoe or other cementing passages
provided therefore and into the annular space between the drill
string 20A and the borehole 10A and 16A. This cement may need to
cure in place without backing up through the interior of the drill
string before hardening. Therefore, when the cementing fluid is no
longer flowed down the drill string and a secondary, lighter liquid
is poured into the drill string immediately behind the cement
whereby the pressure in the drill string will be less than that in
the annulus between the drill string 20A and the borehole 10A and
16A, the valve assembly 68A will close over the opening of bore 66A
at the underside of the housing 64A to seal the bore from entry of
cement back into the hollow interior region 28A of the drill string
20A. In another aspect, one or more isolation subs (not shown) may
be positioned above or below the float shoe 34A to prevent leakage
of cement back up the hollow region 28A if cement leaks past valve
assembly 68A.
[0293] After the cement is cured, the float sub 34A is then
removed, typically by directing a drill, mill, or cutter down the
drill string 20A hollow portion 28A from the surface, and
physically cutting or drilling through the shoe, housing, and valve
assembly. The drill, mill, or cutter will readily drill through the
cement or plasticbased components of the float sub, as well as any
metal portion, into small pieces which may be recovered, in part,
by being carried to the surface in drilling mud. Additionally,
there is a benefit to having as much of the componentry as
practicable, such as valve body 48A, etc. constructed of a material
which is easily ground up or drilled through yet has sufficient
strength to retain its shape under pressure. Once the float sub is
removed, production tubing or other production elements can easily
be passed through the drill string 20A past the former location of
the float sub 34A. In instances where the borehole has not yet
reached its ultimate depth, an additional casing to be cemented in
place having a drilling bit and a drill motor operatively attached
thereto may be used to drill through the float sub 34A and the
drill motor at the bottom of the drill shoe to continue drilling
further into the earth.
[0294] Although the invention has been described with respect to
its use in a situation where the drill string 20A is to be used, in
situ, as casing, the invention is as applicable to situations where
a well is separately cased with tubing. In such an embodiment, a
section of the casing may be provided with float sub 34A therein in
a fixed longitudinal and angular alignment, and the distance from
the float sub 34A to other locations of interest such as the end of
the lowestmost casing in the stack noted. Thus, the float sub 34A
may be used to enable survey tool alignment and positioning in
casing, although drilling may not be simultaneously occurring.
[0295] Although the float sub 34A has been described in terms of a
landing platform for receiving and orienting a survey tool, float
sub 34A may be modified to include additional features, for example
a latching collar or other receptacle formed therein to which a
latching system such as a float collar or a cementing tool may be
secured. Likewise, the float sub may be configured to include a
stage tool, whereby a blocking member such as a ball (not shown)
may be positioned to block the bore 66A, such that cement may be
directed through the stage tool portion thereof (not shown).
[0296] In another aspect shown in FIGS. 48-52, the present
invention provides a survey tool assembly 900 for use while
directionally drilling with casing. FIG. 48 shows a casing 910
having a drill bit 915 and a cementing valve 920 disposed at a
lower portion thereof. In one embodiment, a portion of the casing
910 may be manufactured from a non-magnetic casing. The drill bit
915 may include one or more fluid deflectors (bit nozzles) 925
angled in the direction of desired trajectory. The casing 910 may
also include a receiving socket 930 for engagement with the survey
tool assembly 900. Preferably, the receiving socket 930 is aligned
or indexed with the fluid deflectors (bit nozzles) 925 to
facilitate orientation of the survey tool assembly 900.
[0297] The survey tool assembly 900 may include survey tools such
as a MWD tool 935 and a gyro 936. In one embodiment, the survey
tools 935, 936 are disposed in the body 940 of the survey tool
assembly 900 using one or more centralizers 942. A mud pulser 945
may be used to transmit information from the survey tools 935, 936
to the surface. The body 940 has a retrieving latch 950 disposed at
one end, and an alignment key 955 disposed at another end. The
alignment key 955 is adapted to engage the receiving socket 930 in
a manner that orients the survey tool assembly 900 with the fluid
deflectors (bit nozzles) 925. One or more seals 908 may be used to
prevent fluid leakage between the survey tool assembly 900 and the
casing 910. Additionally, spring bow centralizers 960 may be
disposed on the outer portion of the body 940 to centralize the
survey tool assembly 900 in the casing 910.
[0298] Many survey tools are actuated by fluid flow. To this end,
the survey tool assembly 900 includes a fluid inlet channel 965 to
allow fluid to flow into the body 940 to actuate the MWD tool 935
and the gyro 936. However, many survey tools operate in a fluid
flow range that is often below what is necessary for other
operations, for example, drilling operation. Consequently, the
survey tool must be retrieved prior to the subsequent, higher flow
rate operation. The process of repeatedly retrieving and deploying
the survey tools is time consuming and expensive. To this end, the
survey tool assembly 900 according to aspects of the present
invention also includes a bypass valve 970 to allow the subsequent,
higher flow rate operation to be performed without retrieving the
survey tool assembly 900.
[0299] In one embodiment, the bypass valve 970 is disposed at a
portion of the body 940 that is below the survey tools 935, 936.
The bypass valve 970 is initially biased in the closed position by
a biasing member 975, as illustrated in FIG. 48. An exemplary
biasing member 975 includes a spring. When the bypass valve 970 is
closed, fluid in the casing 910 can only flow,into the body 940 of
the survey tool assembly 900 through the inlet channel 965, as
illustrated in FIG. 51. It must be noted that other types of bypass
devices known to a person of ordinary skill in the art are
contemplated within aspects of the present invention, for example,
a fix orifice bypass.
[0300] The bypass valve 970 may be opened by providing a higher
flow rate. Specifically, the bypass valve 970 opens when the flow
rate in the casing 910 overcomes the directional force of the
biasing member 975. Once opened, some of the fluid in the casing
910 may be directed through the bypass valve 970 instead of the
inlet channel 965, as illustrated in FIG. 52. In this manner, a
higher flow rate may be supplied to perform the subsequent, higher
flow rate operation.
[0301] In operation, the survey tool assembly 900 is assembled
inside the casing 910 and is lowered into the wellbore together
with the casing 910. Particularly, the alignment key 955 is
situated in the receiving socket 930 to orient the survey tool
assembly 900 with the fluid deflectors 925, as illustrated in FIG.
49. A lower fluid flow rate is supplied to operate the survey tools
935, 936. The lower flow rate is insufficient to overcome the
spring 975 of valve 970, but is sufficient to open the cementing
valve 920, as shown in FIGS. 49 and 51. It must be noted that the
lower flow rate may also be sufficient to operate the drill bit 915
at a slower rate. Information collected by the survey tools 935,
936 may be transmitted back to the surface by the mud pulser
945.
[0302] The bypass valve 970 is opened when the directional force of
the spring is overcome by a higher flow rate. After the bypass
valve 970 is opened, fluid flow through the survey tool assembly
900 may occur through the inlet channel 965 and the bypass valve
970, as illustrated in FIGS. 50 and 52. The higher flow rate may
operate the drill bit 915 at a faster rate and provide more fluid
flow through the fluid deflectors (bit nozzles) 925, thereby
generating a more effective directional control. To collect survey
information, the fluid flow may be decreased to close the bypass
valve 970 and allow the operation of the survey tools 935, 936.
Information collected by the survey tools 935, 936 may be
transmitted back to the surface via mud-pulse telemetry using the
mud pulser 945. This process of surveying and drilling may be
repeated as desired. In this respect, the survey tools 935, 936 do
not need to be retrieved and reconveyed downhole as drilling
progresses, thereby saving time and cost of the operation. After
drilling is complete, the survey tool assembly 900 may be retrieved
by any manner known to a person of ordinary skill in the art.
Preferably, the survey tool assembly 900 is retrieved by latching a
wireline to the retrieving latch 950. In this manner, the survey
tool assembly 900 may be reused in the next drilling operation.
[0303] Any of the above-mentioned downhole electromechanical
devices such as drilling tools, directional tools, sensor package,
cementing gear, and the like may be controlled or actuated by
string rotation; mud pump cycling, wireline electric signal, wired
casing signal, or combinations thereof. Controlling and/or
actuating by string rotation may involve using a number of
start/stop cycles and/or varying rpm. Controlling and/or actuating
by mud pump cycling may involve using a number of start/stops of
the flow rate and/or varying the flow rate.
[0304] In one embodiment, the present invention provides a method
for directing a trajectory of a lined wellbore comprising providing
a drilling assembly comprising a wellbore lining conduit and an
earth removal member; directionally biasing the drilling assembly
while operating the earth removal member and lowering the wellbore
lining conduit into the earth; and leaving the wellbore lining
conduit in a wellbore created by the biasing, operating and
lowering. In one aspect, directionally biasing the drilling
assembly comprises urging fluid through a non-axis-symmetric
orifice arrangement of the drilling assembly. In one embodiment,
the non-axis-symmetric orifice arrangement is disposed on the earth
removal member. In another aspect, directionally biasing comprises
urging the drilling assembly against a non-axis-symmetric pad
arrangement included thereon. In one embodiment, the
non-axisymmetric pad arrangement is disposed on the wellbore lining
conduit.
[0305] In an additional embodiment, the present invention provides
a method for directing a trajectory of a lined wellbore comprising
providing a drilling assembly comprising a wellbore lining conduit
and an earth removal member; directionally biasing the drilling
assembly while operating the earth removal member and lowering the
wellbore lining conduit into the earth; and leaving the wellbore
lining conduit in a wellbore created by the biasing, operating and
lowering. In one embodiment, the method further comprises a second
wellbore lining conduit having a portion disposed substantially
co-axially within the wellbore lining conduit.
[0306] In an additional embodiment, the present invention provides
a method for directing a trajectory of a lined wellbore comprising
providing a drilling assembly comprising a wellbore lining conduit
and an earth removal member; directionally biasing the drilling
assembly while operating the earth removal member and lowering the
wellbore lining conduit into the earth; and leaving the wellbore
lining conduit in a wellbore created by the biasing, operating and
lowering, the drilling assembly further comprising a motor having a
rotating shaft, the rotating shaft having a fluid passage
therethrough. In an additional embodiment, the present invention
provides a method for directing a trajectory of a lined wellbore
comprising providing a drilling assembly comprising a wellbore
lining conduit and an earth removal member; directionally biasing
the drilling assembly while operating the earth removal member and
lowering the wellbore lining conduit into the earth; and leaving
the wellbore lining conduit in a wellbore created by the biasing,
operating and lowering, wherein a latch member operatively connects
the earth removal member to the wellbore lining conduit.
[0307] In one embodiment, the present invention provides an
apparatus for drilling a well, comprising a motor operating system
disposed in a motor system housing; a shaft operatively connected
to the motor operating system, the shaft having a passageway; and a
divert assembly disposed to direct fluid flow selectively to the
motor operating system and the passageway in the shaft. In one
aspect, the divert assembly comprises a closing sleeve having one
or more ports, the closing sleeve disposed in the shaft. In another
aspect, the divert assembly comprises a rupture disk disposed to
block fluid flow to the passageway in the shaft.
[0308] Another embodiment of the present invention provides an
apparatus for drilling a well, comprising a motor operating system
disposed in a motor system housing; a shaft operatively connected
to the motor operating system, the shaft having a passageway; and a
divert assembly disposed to direct fluid flow selectively to the
motor operating system and the passageway in the shaft. In one
aspect, the motor operating system comprises a hydraulic system,
while in another aspect, the motor operating system comprises a
system selected from a turbine system and a stator system.
[0309] An additional embodiment of the present invention provides
an apparatus for drilling a well, comprising a motor operating
system disposed in a motor system housing; a shaft operatively
connected to the motor operating system, the shaft having a
passageway; and a divert assembly disposed to direct fluid flow
selectively to the motor operating system and the passageway in the
shaft; and a drill shoe rotatably connectable to a casing, the
drill shoe comprising a rotatable drill face and a spindle
connected to the shaft. In one aspect, the drill shoe includes a
fluid connection to the passageway in the shaft. In another aspect,
the drill shoe includes a shut-off mechanism for stopping fluid
flow through the fluid connection.
[0310] In one embodiment, the present invention provides an
apparatus for drilling a well, comprising a motor operating system
disposed in a motor system housing; a shaft operatively connected
to the motor operating system, the shaft having a passageway; and a
divert assembly disposed to direct fluid flow selectively to the
motor operating system and the passageway in the shaft; and a
casing latch attached to the motor system housing, the casing latch
connected to releasably secure the apparatus to an internal surface
of a casing. In one aspect, the casing comprises a nozzle biased in
a direction for directionally drilling the casing. In another
aspect, the casing comprises a stabilizer proximate to a midpoint
of the casing for directionally drilling the casing. In yet another
aspect, the casing latch includes a fluid passage connected to the
passageway in the shaft. In yet another aspect, the apparatus
further comprises a guide assembly connected to the casing latch,
the guide assembly having a cone portion and a tubular portion. In
one aspect, the guide assembly includes one or more seats for
receiving a device selected from an inter string and an orientation
device.
[0311] Another embodiment of the present invention provides an
apparatus for drilling a well, comprising a motor operating system
disposed in a motor system housing; a shaft operatively connected
to the motor operating system, the shaft having a passageway; and a
divert assembly disposed to direct fluid flow selectively to the
motor operating system and the passageway in the shaft, wherein the
motor system housing includes an enlargement portion for expanding
a casing size.
[0312] An additional embodiment of the present invention provides
an apparatus for drilling with casing, comprising a casing; a motor
system retrievably disposed in the casing, the motor system
comprising a motor operating system disposed in a motor system
housing; a shaft operatively connected to the motor operating
system, the shaft having a passageway; a divert assembly disposed
to direct fluid flow selectively to the motor operating system and
the passageway in the shaft; and a drill face operably connected to
shaft of the motor system. In one aspect, the apparatus further
comprises a latch for releasably latching onto the casing, the
latch fixedly connected to the motor system.
[0313] An additional embodiment of the present invention provides
an apparatus for drilling with casing, comprising a casing; a motor
system retrievably disposed in the casing, the motor system
comprising a motor operating system disposed in a motor system
housing; a shaft operatively connected to the motor operating
system, the shaft having a passageway; a divert assembly disposed
to direct fluid flow selectively to the motor operating system and
the passageway in the shaft; and a drill face operably connected to
shaft of the motor system, wherein the divert assembly comprises a
closing sleeve having one or more ports, the closing sleeve
disposed in the shaft. A further additional embodiment of the
present invention provides an apparatus for drilling with casing,
comprising a casing; a motor system retrievably disposed in the
casing, the motor system comprising a motor operating system
disposed in a motor system housing; a shaft operatively connected
to the motor operating system, the shaft having a passageway; a
divert assembly disposed to direct fluid flow selectively to the
motor operating system and the passageway in the shaft; and a drill
face operably connected to shaft of the motor system, wherein the
divert assembly comprises a rupture disk disposed to block fluid
flow to the passageway in the shaft.
[0314] An additional embodiment of the present invention provides
an apparatus for drilling with casing, comprising a casing; a motor
system retrievably disposed in the casing, the motor system
comprising a motor operating system disposed in a motor system
housing; a shaft operatively connected to the motor operating
system, the shaft having a passageway; a divert assembly disposed
to direct fluid flow selectively to the motor operating system and
the passageway in the shaft; and a drill face operably connected to
shaft of the motor system, wherein the motor operating system
comprises a hydraulic system. A further additional embodiment
provides an apparatus for drilling with casing, comprising a
casing; a motor system retrievably disposed in the casing, the
motor system comprising a motor operating system disposed in a
motor system housing; a shaft operatively connected to the motor
operating system, the shaft having a passageway; a divert assembly
disposed to direct fluid flow selectively to the motor operating
system and the passageway in the shaft; and a drill face operably
connected to shaft of the motor system, wherein the motor operating
system comprises a system selected from a turbine system and a
stator system.
[0315] In one embodiment, the present invention provides an
apparatus for drilling with casing, comprising a casing; a motor
system retrievably disposed in the casing, the motor system
comprising a motor operating system disposed in a motor system
housing; a shaft operatively connected to the motor operating
system, the shaft having a passageway; a divert assembly disposed
to direct fluid flow selectively to the motor operating system and
the passageway in the shaft; a drill face operably connected to
shaft of the motor system; and a drill shoe rotatably connectable
to the casing, the drill shoe having the drill face and a spindle
connected to the shaft. In one aspect, the drill shoe includes a
fluid connection to the passageway in the shaft. In a further
aspect, the drill shoe includes a shut off mechanism for stopping
fluid flow through the fluid connection.
[0316] In one embodiment, the present invention provides an
apparatus for drilling with casing, comprising a casing; a motor
system retrievably disposed in the casing, the motor system
comprising a motor operating system disposed in a motor system
housing; a shaft operatively connected to the motor operating
system, the shaft having a passageway; a divert assembly disposed
to direct fluid flow selectively to the motor operating system and
the passageway in the shaft; a drill face operably connected to
shaft of the motor system; and a casing latch attached to the motor
system housing, the casing latch connected to releasably secure the
apparatus to an internal surface of the casing. In one aspect, the
casing latch includes a fluid passage connected to the passageway
in the shaft.
[0317] In another embodiment, the present invention provides an
apparatus for drilling with casing, comprising a casing; a motor
system retrievably disposed in the casing, the motor system
comprising a motor operating system disposed in a motor system
housing; a shaft operatively connected to the motor operating
system, the shaft having a passageway; a divert assembly disposed
to direct fluid flow selectively to the motor operating system and
the passageway in the shaft; a drill face operably connected to
shaft of the motor system; a casing latch attached to the motor
system housing, the casing latch connected to releasably secure the
apparatus to an internal surface of the casing; and a guide
assembly connected to the casing latch, the guide assembly having a
cone portion and a tubular portion. In one aspect, the guide
assembly. includes one or more seats for receiving a device
selected from an inter string and an orientation device.
[0318] The present invention provides in yet another embodiment an
apparatus for drilling with casing, comprising a casing; a motor
system retrievably disposed in the casing, the motor system
comprising a motor operating system disposed in a motor system
housing; a shaft operatively connected to the motor operating
system, the shaft having a passageway; a divert assembly disposed
to direct fluid flow selectively to the motor operating system and
the passageway in the shaft; a drill face operably connected to
shaft of the, motor system, wherein the motor system housing
includes an enlargement portion for expanding a casing size.
[0319] Another embodiment of the present invention includes a
method for drilling and completing a well, comprising pumping drill
mud to a motor system disposed in a casing; rotating a drill face
connected to the motor system; diverting fluid flow to a passageway
through the motor system; and pumping cement through the passageway
to the drill face. In one aspect, the method further comprises
releasably latching the motor system to the casing utilizing a
casing latch.
[0320] A further embodiment of the present invention includes a
method for drilling and completing a well, comprising pumping drill
mud to a motor system disposed in a casing; rotating a drill face
connected to the motor system; diverting fluid flow to a passageway
through the motor system; and pumping cement through the passageway
to the drill face, wherein the drill mud and the cement are pumped
utilizing an inter string. In another embodiment, the present
invention includes Another embodiment of the present invention
includes a method for drilling and completing a well, comprising
pumping drill mud to a motor system disposed in a casing; rotating
a drill face connected to the motor system; diverting fluid flow to
a passageway through the motor system; pumping cement through the
passageway to the drill face; and retrieving the motor system from
the casing.
[0321] Another embodiment of the present invention includes a
method for drilling and completing a well, comprising pumping drill
mud to a motor system disposed in a casing; rotating a drill face
connected to the motor system; diverting fluid flow to a passageway
through the motor system; pumping cement through the passageway to
the drill face; and expanding the casing utilizing an enlarged
portion of a housing for the motor system.
[0322] In a further embodiment, the present invention includes a
method of initiating and continuing a path of a wellbore,
comprising providing a first casing having a first earth removal
member operatively disposed at a lower end thereof; penetrating a
formation with the first casing to form the wellbore; selectively
altering a trajectory of the wellbore while penetrating the
formation of the first casing; flowing drilling fluid to a motor
system disposed in a second casing, the second casing being
releasably attached to an inner diameter of the first casing and
having a second earth removal member; rotating the second earth
removal member with the motor system; and selectively altering the
trajectory of the second casing as it continues into the formation.
In one aspect, the trajectory of the second casing is altered more
than the trajectory of the first casing.
[0323] The present invention further includes in one embodiment a
method of altering a path of a casing into a formation, comprising
providing an outer casing with a deflector releasably attached to
its lower end; penetrating the formation with the deflector;
releasing the releasable attachment; deflecting the path of the
outer casing in the formation by moving the casing string along the
deflector; releasing an inner casing from a releasable attachment
to the outer casing; and flowing drilling fluid to a motor system
disposed within the inner casing to rotate an earth removal member
operatively attached to the motor system while altering a
trajectory of the inner casing drilling into the formation. In
another embodiment, the present invention further includes an
apparatus for deflecting a wellbore, comprising an outer casing
with a member for deflecting the casing string preferentially in a
direction; a first earth removal member operatively connected to a
lower end of the outer casing; and an inner casing having a motor
operating system disposed therein disposed within the outer casing
and operatively attached thereto.
[0324] In a yet further embodiment, the present invention includes
a method for preferentially directing a path of a casing to form a
wellbore, comprising providing a second casing concentrically
disposed within a first casing having a biasing member, the second
casing having a motor system releasably attached therein; jetting
the first casing having an earth removal member operatively
connected thereto into a formation to a first depth while
selectively altering the trajectory of the wellbore using the
biasing member; releasing a releasable attachment between the first
and second casing; providing drilling fluid to the motor system;
and selectively altering a trajectory of the second casing while
rotating an earth removal member operatively connected to a lower
end of the motor system as the second casing continues into the
formation. In one aspect, the biasing member includes a
preferential jet for directing fluid flow asymmetrically through
the first casing while jetting. In another aspect, the biasing
member includes a stabilizing member disposed proximate to a
midpoint of the first casing.
[0325] In an embodiment, the present invention includes a method
for preferentially directing a path of a casing to form a wellbore,
comprising providing a second casing concentrically disposed within
a first casing having a biasing member, the second casing having a
motor system releasably attached therein; jetting the first casing
having an earth removal member operatively connected thereto into a
formation to a first depth while selectively altering the
trajectory of the wellbore using the biasing member; releasing a
releasable attachment between the first and second casing;
providing drilling fluid to the motor system; selectively altering
a trajectory of the second casing while rotating an earth removal
member operatively connected to a lower end of the motor system as
the second casing continues into the formation; and diverting fluid
flow to a passageway through the motor system. In one aspect, the
method further comprises flowing a physically alterable bonding
material through the passageway to the earth removal member.
[0326] An additional embodiment of the present invention includes a
method for preferentially directing a path of a casing to form a
wellbore, comprising providing a second casing concentrically
disposed within a first casing having a biasing member, the second
casing having a motor system releasably attached therein; jetting
the first casing having an earth removal member operatively
connected thereto into a formation to a first depth while
selectively altering the trajectory of the wellbore using the
biasing member; releasing a releasable attachment between the first
and second casing; providing drilling fluid to the motor system;
selectively altering a trajectory of the second casing while
rotating an earth removal member operatively connected to a lower
end of the motor system as the second casing continues into the
formation; drilling the second casing to a second depth; and
expanding the second casing. In one aspect, expanding the second
casing is accomplished by retrieving the motor system from the
second casing.
[0327] In another embodiment, the present invention includes a
method for preferentially directing a path of a casing to form a
wellbore, comprising providing a second casing concentrically
disposed within a first casing having a biasing member, the second
casing having a motor system releasably attached therein; jetting
the first casing having an earth removal member operatively
connected thereto into a formation to a first depth while
selectively altering the trajectory of the wellbore using the
biasing member; releasing a releasable attachment between the first
and second casing; providing drilling fluid to the motor system;
selectively altering a trajectory of the second casing while
rotating an earth removal member operatively connected to a lower
end of the motor system as the second casing continues into the
formation; and retrieving the motor system from the second
casing.
[0328] The present invention further includes, in one embodiment, a
method for preferentially directing a path of a casing to form a
wellbore, comprising providing a second casing concentrically
disposed within a first casing having a biasing member, the second
casing having a motor system releasably attached therein; jetting
the first casing having an earth removal member operatively
connected thereto into a formation to a first depth while
selectively altering the trajectory of the wellbore using the
biasing member; releasing a releasable attachment between the first
and second casing; providing drilling fluid to the motor system;
selectively altering a trajectory of the second casing while
rotating an earth removal member operatively connected to a lower
end of the motor system as the second casing continues into the
formation; and selectively introducing a surveying tool into the
motor operating system to selectively measure the trajectory of the
wellbore. In one aspect, the surveying tool selectively measures
the trajectory of the wellbore while drilling with the first or
second casing.
[0329] In an embodiment, the present invention includes a method
for preferentially directing a path of a casing to form a wellbore,
comprising providing a second casing concentrically disposed within
a first casing having a biasing member, the second casing having a
motor system releasably attached therein; jetting the first casing
having an earth removal member operatively connected thereto into a
formation to a first depth while selectively altering the
trajectory of the wellbore using the biasing member; releasing a
releasable attachment between the first and second casing;
providing drilling fluid to the motor system; and selectively
altering a trajectory of the second casing while rotating an earth
removal member operatively connected to a lower end of the motor
system as the second casing continues into the formation; and
measuring a trajectory of the wellbore while drilling with the
first or second casing.
[0330] An embodiment of the present invention includes an apparatus
for deflecting a wellbore, comprising a casing having upper and
lower portions and an earth removal member operatively attached to
its lower end; and at least one hole-opening blade disposed on the
upper portion of the casing string for gravitationally bending the
casing to alter a trajectory of the wellbore. The hole-opening
blade comprises a concentric stabilizer in one aspect. In another
aspect, the hole-opening blade is an eccentric stabilizer. An
additional embodiment of the present invention includes an
apparatus for deflecting a wellbore, comprising a casing having
upper and lower portions and an earth removal member operatively
attached to its lower end; at least one hole-opening blade disposed
on the upper portion of the casing string for gravitationally
bending the casing to alter a trajectory of the wellbore; and at
least one angled perforation in the earth removal member for
further altering the trajectory of the wellbore through asymmetric
fluid flow through the perforation.
[0331] An embodiment of the present invention includes a method for
deflecting a wellbore while drilling with casing, comprising
providing a casing with a drilling member at a lower end thereof;
penetrating a formation with the casing while selectively altering
a trajectory of the casing; pumping drilling fluid to a motor
system disposed in an additional casing disposed within the casing;
rotating the additional casing with the motor system, the motor
system having an earth removal member operatively attached to its
lower end; and selectively altering a direction of additional
casing to deflect the wellbore at a further trajectory. An
additional embodiment includes a method of deflecting a wellbore
while drilling with casing, comprising providing a casing with a
drilling member at a lower end thereof; providing a deflecting
member releasably attached to the drilling member; anchoring the
deflecting member in the wellbore at a predetermined depth; and
urging the drilling member along the deflector, thereby altering
the direction of the wellbore.
[0332] A further embodiment of the present invention includes a
method of deflecting a wellbore while drilling with casing,
comprising providing a casing with a drilling member at a lower end
thereof, the drilling member having at least one fluid path
extending therefrom, the fluid path directed away from a
longitudinal centerline of the string; and pumping fluid through
the fluid path, thereby altering the direction of the wellbore. A
further embodiment includes a method of deflecting a wellbore while
drilling with casing, comprising forming a first, larger diameter
wellbore; providing a second, lower, smaller diameter wellbore; and
slanting a casing string to direct the lower end thereof away from
the centerline of the wellbore, thereby altering the direction of
the wellbore.
[0333] In another embodiment, the present invention includes a
method of initiating and continuing a path of a wellbore,
comprising providing a casing string and a cutting apparatus
disposed at a lower portion of the casing string; penetrating a
formation with the casing string to form the wellbore; and
selectively altering the trajectory of the casing string as it
continues into the formation. In one aspect, selectively altering
the trajectory of the casing string comprises selectively jetting
fluid to create an asymmetric flow pattern through a lower portion
of the cutting apparatus. In another aspect, selectively altering
the trajectory of the casing string comprises selectively diverting
fluid flow out of a portion of the casing string. In one
embodiment, selectively diverting fluid flow forms a profile in a
portion of the formation through which the casing string
continues.
[0334] An embodiment of the present invention includes a method of
initiating and continuing a path of a wellbore, comprising
providing a casing string and a cutting apparatus disposed at a
lower portion of the casing string; penetrating a formation with
the casing string to form the wellbore; and selectively altering
the trajectory of the casing string as it continues into the
formation, wherein selectively altering the trajectory of the
casing string comprises laterally moving the casing string through
an enlarged inner diameter of an upper portion of the wellbore.
Another embodiment includes the present invention includes a method
of initiating and continuing a path of a wellbore, comprising
providing a casing string and a cutting apparatus disposed at a
lower portion of the casing string; penetrating a formation with
the casing string to form the wellbore; selectively altering the
trajectory of the casing string as it continues into the formation;
and surveying the path of the wellbore while selectively altering
the trajectory of the casing string.
[0335] A further embodiment provides the present invention includes
a method of initiating and continuing a path of a wellbore,
comprising providing a casing string and a cutting apparatus
disposed at a lower portion of the casing string; penetrating a
formation with the casing string to form the wellbore; selectively
altering the trajectory of the casing string as it continues into
the formation; and introducing at least one additional casing
string into the casing string. In an embodiment, the present
invention includes a method of initiating and continuing a path of
a wellbore, comprising providing a casing string and a cutting
apparatus disposed at a lower portion of the casing string;
penetrating a formation with the casing string to form the
wellbore; and selectively altering the trajectory of the casing
string as it continues into the formation, wherein penetrating the
formation with the casing includes jetting fluid through at least
one nozzle disposed in the cutting apparatus, the at least one
nozzle having an extended bore which is adjustable to vary the
penetration rate of the casing into the formation.
[0336] An embodiment of the present invention includes a method of
altering a path of a casing string in a formation, comprising
providing a casing string with a deflector releasably attached to
its lower end; penetrating the formation with the deflector;
releasing the releasable attachment; and deflecting the path of the
casing string in the formation by moving the casing string along
the deflector. In one aspect, the deflector comprises an inclined
wedge.
[0337] An additional embodiment of the present invention includes
an apparatus for deflecting a wellbore, comprising a casing string
with means for deflecting the casing string preferentially in a
direction; and a first cutting apparatus disposed at a lower
portion of the casing string. In one embodiment, means for
deflecting the casing string preferentially in the direction
comprises an inclined wedge releasably attached to a lower portion
of the cutting apparatus. In another embodiment, means for
deflecting the casing string preferentially in the direction
comprises an angled perforation through the lower portion of the
casing string for receiving a fluid. In yet another embodiment,
means for deflecting the casing string preferentially in the
direction further comprises a bent portion in the casing string for
deflecting the casing string preferentially in a direction. In
another embodiment, means for deflecting the casing string
preferentially in the direction comprises a second cutting
apparatus larger in diameter than the first cutting apparatus
disposed on a portion of the casing string above the first cutting
apparatus.
[0338] An embodiment of the present invention includes an apparatus
for deflecting a wellbore, comprising a casing string with means
for deflecting the casing string preferentially in a direction; a
first cutting apparatus disposed at a lower portion of the casing
string; and a landing seat for securing a survey tool therein. In
another embodiment, the present invention includes an apparatus for
deflecting a wellbore, comprising a casing string with means for
deflecting the casing string preferentially in a direction; and a
first cutting apparatus disposed at a lower portion of the casing
string, wherein the casing string comprises a lower casing string
and an upper casing string, and wherein means for deflecting the
casing string preferentially in the direction comprises a second
cutting apparatus which connects the lower casing string to the
upper casing string and is larger in diameter than the second
cutting apparatus.
[0339] Another embodiment of the present invention includes an
apparatus for deflecting a wellbore, comprising a casing string
with means for deflecting the casing string preferentially in a
direction; a first cutting apparatus disposed at a lower portion of
the casing string; and a drilling apparatus releasably connected to
an inner diameter of the casing string with a second cutting
apparatus disposed on the drilling apparatus below the releasable
connection. In one aspect, the second cutting apparatus comprises a
cutting structure disposed on a portion facing the releasable
connection.
[0340] An embodiment of the present invention includes an apparatus
for deflecting a wellbore, comprising a casing string with means
for deflecting the casing string preferentially in a direction; and
a first cutting apparatus disposed at a lower portion of the casing
string, wherein the first cutting apparatus includes at least one
nozzle extending therethrough, the at least one nozzle having an
extended straight bore extending longitudinally therethrough.
[0341] An embodiment of the present invention includes an apparatus
for deflecting a wellbore, comprising a casing string with means
for deflecting the casing string preferentially in a direction; and
a first cutting apparatus disposed at a lower portion of the casing
string, wherein the first cutting apparatus includes at least one
nozzle extending therethrough, the at least one nozzle having an
extended straight bore extending longitudinally therethrough. In
one embodiment, the at least one nozzle is drillable or made of a
soft material such as copper. In another embodiment, the at least
one nozzle comprises a thin coating of a hard material, the hard
material having a hardness greater than a hardness of a soft
material. The hard material may be ceramic or tungsten carbide. The
remainder of the at least one nozzle may comprise a soft material
such as copper.
[0342] In another embodiment, the first cutting apparatus includes
at least one nozzle extending therethrough, the at least one nozzle
being drillable and having a profiled sleeve coating of a hard
material. In another embodiment, the first cutting apparatus
includes at least one drillable nozzle extending therethrough, the
at least one nozzle comprising a hard material having stressed
portions therein for increasing breakability of the at least one
nozzle when drilled therethrough.
[0343] In another embodiment, the stressed portions include a
plurality of stressed, longitudinal notches in the at least one
nozzle. In another embodiment still, a sealing material is disposed
in the plurality of stressed notches.
[0344] In another aspect, the present invention provides a nozzle
assembly usable within a tool body while jetting a casing into a
formation. The nozzle assembly includes soft, drillable material
forming a nozzle retainer and a thin sleeve of a hard material
disposed within the nozzle retainer, the hard material forming an
longitudinal bore extending past the exit and entry points of a
fluid flow path through a hole through the tool body, the hard
material having a hardness greater than a hardness of the soft
material. In one embodiment, the soft material is copper. In
another embodiment, the hard material is ceramic. In another
embodiment still, the thin sleeve position is adjustable relative
to the nozzle retainer.
[0345] In another aspect, the present invention provides a method
for preferentially directing a path of a casing string to form a
wellbore. The method includes jetting the casing string with a
cutting structure connected thereto into a formation; and
selectively directing the casing string in a direction as the
casing string continues into the formation. In one embodiment,
selectively directing the casing string in the direction comprises
using the casing string to create an annular space in an upper
portion of the wellbore and laterally directing an upper portion of
the casing string through the annular space. In another embodiment,
selectively directing the casing string comprises integrating arcs
in the casing string to urge the casing string to form the path in
the wellbore while directing fluid asymmetrically out of the
cutting structure. In another embodiment, the casing string
comprises a tubular body with an inclined wedge attached to its
lower portion, and wherein selectively directing the casing string
comprises directing the path of the wellbore by obstructing an
axial path of the tubular body by the inclined wedge.
[0346] In another aspect, the present invention provides an
apparatus for deflecting a wellbore. The apparatus includes a
casing string having upper and lower portions and at least one
hole-opening blade disposed on the upper portion of the casing
string. In one embodiment, the apparatus also includes a cutting
structure disposed on the lower portion of the casing string. In
another embodiment, the apparatus further includes a tubular body
releasably connected to an inner diameter of the casing string,
wherein the tubular body has a cutting apparatus disposed at its
lower end comprising a cutting structure located on upper and lower
portions thereof.
[0347] In another aspect, the present invention provides a method
for deflecting a wellbore while drilling with casing. The method
includes providing a casing string with a drilling member at a
lower end thereof; penetrating a formation with the casing string;
and selectively altering a direction of the lower end to deflect
the wellbore.
[0348] In another aspect, the present invention provides an
assembly for drilling with casing. The assembly includes a casing
latch for securing the assembly to a portion of casing; a bit
attached to a bottom portion of the assembly; a biasing member for
providing the bit with a desired deviation from a center line of
the wellbore; and at least one adjustable stabilizer. In one
embodiment, the bit is an expandable bit. In another embodiment,
the stabilizer has one or more support members adapted to be placed
in a first position for running through the portion of casing and a
second position for engaging an inner wall of the wellbore. In
another embodiment still, the stabilizer is adjustable to at least
a third position, wherein an outer diameter of the stabilizer in
the third position is less than the outer diameter of the
stabilizer in the second position. In yet another embodiment,
assembly includes a flexible collar disposed between the bit and
the casing latch. In another embodiment still, the biasing member
is a bent housing of a downhole motor adapted to drive the bit. In
a further embodiment, the assembly includes a measurement tool that
is adapted to measure a trajectory of the wellbore and communicate
the measured trajectory to the wellbore surface. In another
embodiment, the assembly includes at least one additional
adjustable stabilizer. The bit may be a pilot bit. The bit may also
include an underreamer.
[0349] In another aspect, the present invention provides a drilling
assembly for creating a wellbore, the drilling assembly having a
casing portion; a bit assembly disposed on a bottom portion of the
drilling assembly, the bit assembly adapted to be expanded from a
first diameter to a second diameter; and at least one stabilizer
adapted to be adjusted from a first position to at least a second
position. In one embodiment, the casing portion is expandable. In
another embodiment, the bit assembly comprises an expandable bit.
In another embodiment still, the drilling assembly further
comprises a biasing member for providing the bit with a desired
deviation from a center line of the wellbore. In yet another
embodiment, the assembly includes a biasing member for providing
the bit assembly with a desired deviation from a center line of the
wellbore. In a further embodiment, the assembly includes a downhole
drilling motor adapted to rotate the bit. In another embodiment,
the assembly includes a flexible collar disposed between the bit
assembly and a bottom end of the casing portion. In another
embodiment still, the assembly also includes a measurement tool
adapted to measure a trajectory of the wellbore and communicate the
measured trajectory to the wellbore surface.
[0350] In one aspect, the present invention provides a method for
drilling with casing. The method includes lowering a drilling
assembly down a wellbore through casing, wherein the drilling
assembly comprises an adjustable stabilizer and one or more
drilling elements. The method also includes adjusting one or more
support members of the stabilizer to increase a diameter of the
stabilizer and operating the drilling assembly to extend a portion
of the wellbore below the casing, wherein the extended portion
having a diameter greater than an outer diameter of the casing. In
one embodiment, the drilling elements may include an expandable bit
for expanding the expandable bit to have a larger outer diameter
than the casing.
[0351] In another embodiment, the method may include measuring a
trajectory of the wellbore, and in response to the measured
trajectory, making one or more adjustments from a surface of the
wellbore. The adjustments may involve adjusting the support members
of the stabilizer or adjusting a weight applied to the bit. The
method may also include sensing a geophysical parameter.
[0352] In another embodiment, the method may include partially
raising the drilling assembly through the casing; advancing the
casing into the extended portion of the wellbore; and raising the
drilling assembly through the casing to a surface of the
wellbore.
[0353] In another aspect, the present invention provides an
apparatus for drilling a wellbore in an earth formation. The
apparatus includes a drill string having a longitudinal bore
therethrough and a drilling assembly connected at the lower end of
the drill string. Preferably, the drilling assembly is selected to
be operable to form a borehole and at least in part to be
retrievable through the longitudinal bore of the drill string. The
apparatus may also include a directional borehole drilling assembly
connected to the drill string and including biasing means for
applying a force to the drilling assembly to drive it laterally
relative to the wellbore and at least one adjustable stabilizer,
the adjustable stabilizer retrievable through the longitudinal bore
of the drill string. In one embodiment, the adjustable stabilizer
is positioned above the biasing means of the directional borehole
drilling assembly. In another embodiment, the drilling assembly
comprises an expandable bit selected to be operable to form a
borehole having a diameter greater than an outer diameter of the
drill string and to be retrievable through the longitudinal bore of
the drill string.
[0354] In another aspect, the present invention provides a method
for directionally drilling a well with a casing as an elongated
tubular drill string and a drilling assembly retrievable from the
lower distal end of the drill string without withdrawing the drill
string from a wellbore being formed by the drilling assembly. The
method includes providing the casing as the drill string; a
directional borehole drilling assembly connected to the drill
string and including biasing means for applying a force to the
drilling assembly to drive it laterally relative to the wellbore;
and providing an adjustable stabilizer to support the directional
borehole drilling assembly. The method also includes connecting the
drilling assembly to the distal end of the drill string and
inserting the drill string, the directional borehole drilling
assembly, and the drilling assembly into the wellbore. The method
further includes adjusting the adjustable stabilizer; forming a
wellbore having a diameter greater than the diameter of the drill
string; and operating the biasing means to drive the drilling
assembly laterally relative to the wellbore. The method further
includes removing at least a portion of the drilling assembly from
the distal end of the drill string; removing the at least a portion
of the drilling assembly out of the wellbore through the drill
string without removing the drill string from the wellbore; and
leaving the drill string in the wellbore. In one embodiment, the
one or more support members is adjusted to change, a diameter of
the stabilizer. In another embodiment, prior to removing at least a
portion of the drilling assembly from the distal end of the drill
string, the method further includes partially raising at least a
portion of the drilling assembly through the drill string and
advancing the drill string within the wellbore.
[0355] In another aspect, the present invention provides an
assembly for drilling with casing. The assembly includes a casing
latch for securing the assembly to a portion of casing and a
cutting structure attached to a bottom portion of the assembly. The
assembly also includes a biasing member for providing the cutting
structure with a desired deviation from a centerline of the
wellbore, wherein biasing force for providing the cutting structure
with the desired deviation is provided substantially by the casing.
In one embodiment, the biasing member is an eccentric bias pad
disposed on an outer diameter of the casing. The eccentric bias pad
may alter the centerline of the casing relative to the borehole
centerline in an opposite direction from the side of the casing on
which the eccentric bias pad is disposed. In another embodiment,
the biasing member comprises a bent motor housing within the
casing. The assembly may also include a concentric stabilizer
disposed around a lower end of the casing absorbs a majority of the
biasing force. In another embodiment still, the casing latch is an
orienting latch. In yet another embodiment, the assembly includes
at least one of a measuring while drilling tool and a resistivity
tool. In yet another embodiment, the cutting structure is
expandable. In yet another embodiment, the assembly is retrievable
from the casing.
[0356] In another aspect, the present invention provides a method
of drilling with casing. The method includes providing a casing
having an assembly releasably connected therein, the assembly
comprising an earth removal member at its lower end and a biasing
member. The biasing member deflects the earth removal member to a
desired angle with respect to the centerline of the wellbore and to
place a biasing force on the casing. In one embodiment, the method
also includes sensing a geophysical parameter.
[0357] In another aspect, the present invention provides a method
of forming a wellbore using a casing equipped with a cutting
apparatus. The method includes positioning an orienting member in
the casing, the orienting member having a predetermined orientation
relative to the cutting apparatus; and positioning a survey tool
with respect to the orienting member, such that an orientation of
the survey tool in the casing is known. In one embodiment, the
orienting member includes at least one flow aperture therethrough,
and the survey tool includes at least one flow aperture
therethrough. The orienting member provides an additional downhole
functionality such as receiving a cementing tool therein or
providing a stage tool integral therewith. In one embodiment, the
orienting member may include a slot. In another embodiment, the
orienting member may include a mule shoe profile and the survey
tool includes a mating mule shoe profile receivable against the
mule shoe profile of the landing shoe. The mule shoe profiles of
the survey tool and the orienting member provide, upon mating of
the mule shoe profiles, alignment between the landing shoe and the
survey tool. In another embodiment, the orienting member includes a
tubular element having a slot therein.
[0358] In another embodiment still, the casing comprises a float
shoe and the orienting member is disposed in the float shoe. In
another embodiment, the survey tool is positioned by landing the
survey tool in the orienting member. In another embodiment still,
the method further includes acquiring information relating a
direction of the cutting apparatus. The method may also include
sending the information to a receiving apparatus and steering the
cutting apparatus in response to the information acquired. In
another embodiment, the cutting apparatus includes a jetting
assembly and/or a drilling bit. In yet another embodiment, the
method also includes removing the survey tool before drilling is
continued.
[0359] In another aspect, the present invention provides an
apparatus for surveying a well wherein a drill string formed of a
casing having a cutting apparatus. The apparatus includes an
alignment member located in the drill string and a survey tool
receivable in said alignment member and alignable thereby to a
desired orientation in the drill string. In one embodiment, the
alignment member includes a shoe having a profile thereon, the
profile indexed rotationally with respect to the circumference of
the drill string. The survey tool includes an alignment element
interactive with the shoe upon locating of the survey tool in the
shoe to provide a known alignment of the survey tool with the drill
string. In another embodiment, the survey tool alignment element
includes a profile matable with the profile of the alignment
member. In yet another embodiment, the alignment member further
includes a slot; the survey tool includes a generally cylindrical
body having an alignment lug projecting therefrom; and the lug is
positionable in the slot when the survey tool is disposed in the
alignment member to provide a known orientation of the survey tool
with the drill string.
[0360] In another embodiment still, the survey tool includes a
generally hollow interior and an open end positionable in said
alignment member, and at least one aperture extending through the
body of said survey tool to communicate fluids from the casing to
the hollow interior. The alignment member includes an aperture
extending therethrough to communicate fluids from a region above
the alignment member to a region below the alignment member, the
alignment member otherwise blocking off the communication of fluids
through the drill string therepast; and whereby upon placement of
the survey tool in the alignment member for the alignment thereof,
fluids may pass through the aperture, and thus through the hollow
interior of the survey tool and through the alignment member. In
another embodiment, the the survey tool contains a survey apparatus
located therein in a position so as not to interfere with fluid
flow therethrough; and the survey apparatus may be operated to
obtain borehole or formation information as fluid is flowing
therethrough. In another embodiment, a drill shoe having a drill
motor and a jetting apparatus is positioned on the end of the drill
string, and the survey apparatus steers the drill shoe as the drill
shoe penetrates an earth formation.
[0361] In yet another embodiment, the alignment member includes a
stage tool and may further include a float tool to receive a cement
shoe thereon.
[0362] In another aspect, the present invention provides an
apparatus for drilling with casing. The apparatus includes casing
having a drilling member disposed at a lower portion thereof and a
pivoting member coupling the drilling member to the casing, wherein
the drilling member may be pivoted away from a centerline of the
casing for directional drilling. In one embodiment, apparatus
further includes a drilling motor, wherein the pivoting member is
coupled to the drilling motor.
[0363] In another aspect, the present invention provides a survey
tool for use while drilling with casing. The survey tool includes a
body having a bore therethrough and one or more measurement
devices. The survey tool also includes an inlet for fluid
communication between the casing and the bore of the body and a
bypass valve for diverting fluid in the casing from the inlet. In
one embodiment, the bypass valve is in a closed position when the
fluid is at a lower fluid flow rate, while a higher flow rate
places the bypass valve in an open position.
[0364] In another aspect, the present invention provides a method
of collecting information while drilling with casing. The method
includes providing a measurement tool in a casing, the measurement
tool having a first inlet and a second inlet. The method also
includes flowing fluid through a first channel to actuate the
measurement tool and collecting information on a condition in the
wellbore. The method also includes increasing fluid flow in the
casing and flowing fluid through the second channel to continue
drilling.
[0365] While the foregoing is directed to embodiments of the
present invention, other and further embodiments of the invention
may be devised without departing from the basic scope thereof, and
the scope thereof is determined by the claims that follow.
* * * * *