Note: Descriptions are shown in the official language in which they were submitted.
CA 02725717 2013-07-24
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APPARATUS AND METHODS FOR DRILLING A WELLBORE USING CASING
BACKGROUND OF THE INVENTION
Field of the Invention
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.
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Description of the Related Art
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
plafform 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.
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.
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
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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.
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.
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.
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
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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.
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."
In subsea drilling operations, a drilling platform is supported by the
subterranean
formation at the bottom of a body of water. The drilling plafform 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 plafforms of a given dimension are allowed over a
given surface
area and because of the possibly prohibitive economic cost of multiple
plafforms, 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.
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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
plafform is reduced, causing a decrease in the production of hydrocarbons from
the
subsea formation.
To avoid the intersection of wellbores, the wellbores are often drilled at an
angle
from the slots in the plafform. The wellbores drilled from the outermost slots
on the
platform are typically drilled at an angle outward from the plafform, 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.
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.
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
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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.
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.
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.
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.
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Figure 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.
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.
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
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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.
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.
While the system illustrated in Figure 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.
A further disadvantage of the system of Figure 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
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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.
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.
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SUMMARY OF THE INVENTION
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.
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.
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.
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.
CA 02725717 2010-12-22
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.
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.
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.
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.
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.
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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.
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.
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.
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
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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.
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.
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
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
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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.
Figure 1 is a schematic view of one embodiment of a system for drilling and
completing a well in a formation under water.
Figures 2A and 2B show a cross-sectional view of one embodiment of a hollow
shaft motor drilling system disposed in a casing.
Figure 3 is a cross-sectional view of one embodiment of a hollow shaft motor
drilling
system illustrating a fluid divert operation.
Figure 4 is a partial cross-sectional view of one embodiment of the divert
system of
Figure 3.
Figure 5 is a cross-sectional view of one embodiment of a hollow shaft motor
drilling
system illustrating a cementing operation.
Figure 6 is a cross-sectional view of one embodiment of a hollow shaft motor
drilling
system illustrating a system retrieval operation.
Figure 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.
Figure 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.
Figure 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.
Figure 10 is a cross-sectional view of one embodiment of a hollow shaft motor
drilling system illustrating a surveying operation.
Figure 11 is a cross-sectional view of one embodiment of a hollow shaft motor
drilling system disposed in an expandable casing.
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Figure 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.
Figure 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.
Figure 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.
Figure 15 is a cross-sectional view of an alternate embodiment of the
diverting
apparatus of Figure 14 disposed within a subterranean wellbore. Stabilizer
pads are
disposed on the outer diameter of the casing.
Figure 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 Figure 16 is cut away to show
a threadable
connection.
Figure 17 shows an alternate embodiment of the diverting apparatus of the
present
invention having an eccentric stabilizer disposed thereon.
Figure 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.
Figure 19 is a cross-sectional view of the drilling apparatus of Figure 18
drilling
through the diverting apparatus upon removal from the wellbore.
Figure 20 is a cross-sectional view of the drilling apparatus of Figure 18
upon
removal of the drilling apparatus after drilling through the diverting
apparatus.
CA 02725717 2010-12-22
Figures 21 and 22 illustrate a process for drilling through casing.
Figures 23A and 23B are perspective views of first and second ends of an
embodiment of a drillable nozzle.
Figures 24A and 24B are perspective view of first and second ends of an
alternative
embodiment of a drillable nozzle.
Figure 25 is a section view of a first embodiment of a nozzle assembly
disposed in
a tool body.
Figure 26 is a section view of a second embodiment of a nozzle assembly
disposed
in a tool body.
Figures 27 is a section view of a third embodiment of a nozzle assembly
disposed
in a tool body.
Figures 28 is a section view of a fourth embodiment of a nozzle assembly
disposed
in a tool body.
Figure 29 is a section view of a tool body having nozzle assemblies disposed
therein for drilling with casing.
Figure 30 is a cross-sectional view of a lower end of an earth removal member
having fluid passages therethrough.
Figure 31 is a section view of a casing string capable of use in the present
invention.
Figure 32 illustrates an exemplary system for directional drilling according
to the
prior art.
Figures 33A-D illustrate a system for directional drilling according to an
embodiment
of the present invention.
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Figure 34 is a flow diagram illustrating exemplary operations for directional
drilling
with casing according to an embodiment of the present invention.
Figure 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.
Figure 36 shows a sectional view of a further alternate embodiment of a system
for
directional drilling with casing.
Figure 37 is a crosssectional view of another embodiment of a directional
drilling
assembly equipped with an articulating housing.
Figures 38A-B show an exemplary articulating housing according to aspects of
the
present invention.
Figure 39 shows another embodiment of a directional drilling assembly.
Figure 40 shows the directional drilling assembly of Figure 45 after the BHA
has
reached the bottom of the wellbore.
Figure 41 shows the directional drilling assembly of Figure 45 in operation.
Figure 42 is a schematic view, in section, of a directional borehole being
drilled.
Figure 43 is a sectional view of a float sub in a downhole location indicated
in
Figure 42 and a sectional view of a survey tool receivable therein.
Figure 43A shows a side view of the survey tool of Figure 43.
Figure 44 is a sectional view of the float sub of Figure 43, showing a survey
tool in
section, received and landed therein.
Figure 45 is a sectional view of a float sub as in Figure 44, showing an
alternative
embodiment of a survey tool shown partially in section to be received therein.
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CA 02725717 2010-12-22
Figure 46 is a partial sectional view of the float sub of Figure 45, showing
the survey
tool in and landed on the float sub.
Figure 47 shows a partial view of a float sub having a wellbore survey tool or
sensor
disposed therein.
Figure 48 shows an embodiment of a survey tool assembly according to aspects
of
the present invention.
Figure 49 shows the survey tool assembly of Figure 48 in the survey mode.
Figure 50 shows the survey tool assembly of Figure 48 in the drilling mode.
Figure 51 shows the bypass valve of the survey tool assembly of Figure 48 in
the
closed position.
Figure 52 shows the bypass valve of the survey tool assembly of Figure 48 in
the
open position.
Figure 53A is a sectional elevation of an earth boring bit nozzle.
Figure 53B is a sectional view through the section y¨y of Figure 53A.
Figure 54 shows an alternate embodiment of a bit nozzle made substantially of
a
non-metallic metal.
Figure 55 shows a cross-sectional view of an alternate embodiment of a
diverting
apparatus disposed within a subterranean wellbore for use in directional
drilling.
Figure 56A is a cross-sectional view of a diverting apparatus used for
expanding a
casing.
Figure 56B is a cross-sectional view of the diverting apparatus of Figure 56A
in the
process of expanding the casing.
Figure 57 is an upward sectional view of an earth removal member for use in
the
present invention.
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DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT
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.
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.
Figure 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 Figure 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 plafform 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.
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.
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CA 02725717 2010-12-22
Figures 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 Figures 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.
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.
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
CA 02725717 2010-12-22
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.
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.
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.
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 Figure 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.
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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 Figure 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.
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
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CA 02725717 2010-12-22
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.
Figures 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 Figure 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.
To begin the drilling operation, referring again to Figures 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 Figure
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 Figures 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.
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 Figures 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 Figure 3, a ball 261 is dropped from the surface through the casing 195,
219 and into
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CA 02725717 2010-12-22
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
Figure 3.
Figure 3 is a cross-sectional view of one embodiment of a hollow shaft motor
drilling
system 200 illustrating a fluid divert operation. Figure 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 Figure 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.
Figure 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
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CA 02725717 2010-12-22
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.
Figure 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.
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.
Figure 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
CA 02725717 2010-12-22
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 Figures 3-6, except
fluids are
pumped down from the surface through the interior diameter of the casing 219
instead of
the inter string 207.
Embodiments of the invention may also be utilized to perform directional
drilling.
Figure 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
Figure 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 angle a. Figure 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 Figures 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.
Embodiments of the invention may be utilized to perform a survey operation to
determine the direction of drilling. Figure 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
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CA 02725717 2010-12-22
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.
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. Figure 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.
Figure 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,
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CA 02725717 2010-12-22
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.
With the embodiments of Figures 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 Figures 1-12. Additionally, the additional casing may be cemented
into the
formation and expanded by the motor drilling system.
In an additional aspect of the present invention, the motor drilling system
200 or
1100 described in relation to Figures 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 Figures 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.
Figure 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.
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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 diverter60 while the casing string 40 is penetrating
the formation
20, preventing rotational movement of the diverter 60.
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.
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
29
CA 02725717 2010-12-22
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.
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.
CA 02725717 2010-12-22
Figure 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. Figure 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 Figure 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.
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.
31
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CA 02725717 2010-12-22
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
Figure 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 Figure 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.
Figure 15 is an alternate embodiment of the diverting apparatus 110 of Figure
14.
The diverting apparatus 210 of Figure 15, which forms a wellbore 230,
comprises the
same parts as those in Figure 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.
The diverting apparatus 210 of Figure 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.
32
CA 02725717 2010-12-22
The operation of the diverting apparatus 110 and 210 of Figures 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.
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,
33
CA 02725717 2010-12-22
235. In the embodiment of Figure 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.
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.
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
34
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CA 02725717 2010-12-22
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.
Figures 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.
Figure 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 Figures 14 and 15, and no eccentric pads 285 are located on the outer
diameter of the
casing as shown in Figure 15. Rather, in the embodiment of Figure 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
Figures 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
Figures 14 and 15, respectively. As in the embodiments shown in Figures 14 and
15, any
number of fluid deflectors 475 may be utilized in the present invention.
As in the embodiments shown in Figures 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 Figures 14 and 15, the above description of the
float subs 115,
215 of Figures 14 and 15 and their operation applies equally to the float sub
415 of Figure
55. Similarly, because the landing seats 45, 145, and 245 of Figures 13, 14,
and 15,
CA 02725717 2010-12-22
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 Figure 55.
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.
Figure 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.
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 Figures 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.
36
CA 02725717 2010-12-22
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 Figures 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.
In a preferred operation of the embodiment shown in Figure 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 Figure
31 (see below).
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
37
CA 02725717 2010-12-22
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.
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
Figures 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. Figures 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 Figure 57), and the
landing seat
445 of Figure 55.
Additional components of the embodiment of Figures 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.
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 Figure 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
38
CA 02725717 2010-12-22
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.
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.
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.
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.
As mentioned in relation to the embodiment of Figure 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
39
CA 02725717 2010-12-22
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.
Figure 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.
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.
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
CA 02725717 2010-12-22
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.
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.
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.
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
41
CA 02725717 2010-12-22
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 Figure 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.
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.
Figure 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 Figure 16; as such, like parts will not
be described
again herein. The embodiment shown in Figure 17 is different from the
embodiment
shown in Figure 16 because instead of the concentric stabilizer acting as the
second
cutting apparatus, an eccentric stabilizer 1395 disposed asymmetrically on one
side of the
42
CA 02725717 2010-12-22
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
Figure 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.
In the operation of the embodiments of Figures 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.
Finally, Figures 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
Figures 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 Figure
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
43
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CA 02725717 2010-12-22
connections, are used to fix the diverting apparatus 510 relative to the
drilling apparatus
522 torsionally and axially.
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.
The operation of the diverting apparatus 510 and the drilling apparatus 522 is
shown in Figures 18-20. Figure 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
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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.
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 Figure 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.
Figure 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.
As seen in Figure 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.
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,
CA 02725717 2013-07-24
= .
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.
In the embodiments shown in Figures 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.
Furthermore, in any of the embodiments shown in Figures 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.
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.
The diverting apparatus of Figures 13-20 used for nudging may be utilized as
the
outer casing 185 shown in Figure 1, while the inner casing 195 may be any of
the
embodiments depicted in Figures 1-12. In this manner, referring to Figure 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
46
CA 02725717 2010-12-22
direction and angle of the wellbore. The drilling system may include any of
the
embodiments shown in Figures 1-12.
In the most preferable embodiment of Figures 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.
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).
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 Figures 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.
47
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CA 02725717 2010-12-22
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.
In the embodiments of the present invention shown in Figures 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. Figure 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).
As shown in Figure 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.
Figure 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. Figure 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.
48
CA 02725717 2010-12-22
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.
Figures 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 Figures
1-22. The nozzles shown in Figures 23A-23B, 24A-B, and 25-29 are insertable
into the
cutting structures of Figures 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
Figures 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.
In the embodiment shown in Figures 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). Figure 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.
49
CA 02725717 2010-12-22
The drillable nozzle 1700 has one or more stressed portions therein,
specifically
shown as one or more stressed notches 1710 in Figures 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.
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.
Figures 24A and 24B illustrate another embodiment of a drillable nozzle 1800.
A
first end 1851 of the nozzle 1800 is shown in Figure 24B, while a second end
1841 of the
nozzle 1800 is depicted in Figure 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.
The embodiment shown in Figures 24A and 24B is substantially the same as the
embodiment shown in Figures 23A and 23B, except for the following aspects. The
CA 02725717 2010-12-22
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 Figures 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.
In the embodiments of Figures 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.
Figures 25-28 show nozzle assemblies which may be utilized in a drillable
cutting
structure operatively attached to casing. Figures 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. Figures 27 and 28 show relatively thin profiled
flow tubes
2180, 2280, each of which represent a portion of the nozzle assemblies 2100,
2200.
In the embodiment of the present invention illustrated in Figure 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.
51
CA 02725717 2010-12-22
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.
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 Figure 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.
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 Figure 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 Figure 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
52
CA 02725717 2010-12-22
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.
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.
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.
Advantageously, the embodiment of Figure 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.
53
CA 02725717 2010-12-22
An alternate embodiment of a nozzle assembly 2000 of the present invention is
shown in Figure 26. The nozzle assembly 2000 is substantially similar to the
nozzle
assembly 1900 shown and described in relation to Figure 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 Figure 26 because the nozzle assembly 2000 is
one piece.
The embodiment shown in Figure 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.
The nozzle assemblies 1900, 2000 shown in Figures 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.
Figures 27 and 28 show further alternate embodiments of a nozzle assembly
2100,
2200. The embodiment shown in Figure 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 Figure 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.
54
CA 02725717 2010-12-22
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.
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
Figures 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 Figures 25-
26.
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 resislant 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.
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
CA 02725717 2010-12-22
between the tool body 2125 and the retainer 2120 for connecting the nozzle
assembly
2100 to the tool body 2125.
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.
Figure 28 shows an additional embodiment of the present invention. The
embodiment shown in Figure 28 is substantially the same as the embodiment
shown in
Figure 27; therefore, substantially similar elements to Figure 27 which are in
the "21"
series are labeled in Figure 28 with the "22" series. The difference between
the
embodiment of Figure 27 and the embodiment of Figure 28 is that the embodiment
shown
in Figure 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 Figures 27 and
28 may all be utilized in non-drillable applications such as in expandable
cutting structures
when drilling with casing.
Shown in Figure 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 Figure 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
Figures 14-15 and 17. Figure 29 also demonstrates by the lower nozzle assembly
1900
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CA 02725717 2010-12-22
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.
In addition to their use in drillable applications, the above embodiments
shown in
Figures 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
Figures 1-22,
such as an expandable bit. The embodiment of Figure 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.
Figure 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 Figures
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.
The alternate embodiments of Figures 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 Figures 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.
Figures 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
57
CA 02725717 2010-12-22
through bore has an enlarged concave portion at an inlet side of the nozzle,
communicating with a smaller diameter cylindrical portion.
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.
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.
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.
Referring firstly to Figures 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.
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
58
CA 02725717 2010-12-22
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
5 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 Figures 53A-B, is a hard chrome material.
In another
example, tungsten carbide may be used as the surface material.
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 Figure 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 electro-plating means. Additionally, copper is sufficiently soft to allow a
subsequent drill
bit to drill through the body of the nozzle.
In Figure 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.
An advantage of the present invention will be apparent from the method of use
of
the drill bit nozzle as shown in Figures 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
59
CA 02725717 2010-12-22
characteristics of jetted drilling fluid, while nevertheless enabling
subsequent conventional
or standard wellbore drilling equipment to drill through them.
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.
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
Figure 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.
CA 02725717 2010-12-22
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.
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.
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.
Figures 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
61
CA 02725717 2013-07-24
. .
,
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.
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 to approximately 3 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.
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. 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).
Operation of the BHA 4200 may be best described with reference to Figure 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
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CA 02725717 2010-12-22
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.
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 Figure 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.).
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.
Means for adjusting the stabilizer 4202 may vary with different embodiments.
For
example, as illustrated in Figures 33A-33C, the support members 4203 may be
implemented as movable arms/blades that may be retracted in the first (run-in)
position
(Figure 33A), expanded in the second position, and partially
retracted/expanded to the
third position (Figure 33C) to provide a separation between the stabilizer
4202 and the
63
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CA 02725717 2010-12-22
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 Figure
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.
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 electro-mechanical 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.
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
64
CA 02725717 2010-12-22
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.
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.
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.
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 Figure 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
CA 02725717 2013-07-24
from center, for example, to make relatively fine adjustments to the
trajectory of the
wellbore 4103 as it is extended.
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.
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.
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 Serial Number
10/419,456
entitled "Wired Casing" and filed April 21, 2003; and fiber optic sensing
devices. Any
combination of sensors and/or
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CA 02725717 2010-12-22
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.).
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 Figure 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.
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.
While the adjustable stabilizer 4202 is shown in Figures 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
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CA 02725717 2010-12-22
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.
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.
Figures 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.
Figure 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
Figure 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.
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CA 02725717 2010-12-22
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.
The casing 2404 includes one or more casing sections. Figure 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.
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 Figure 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.
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
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CA 02725717 2013-07-24
=
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
casing2404
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.
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. Patent No.
3,951,219) 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.
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 Figures 42-47 (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.
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;
CA 02725717 2013-07-24
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 Serial Number 10/419,456 entitled "Wired Casing" and filed
April 21,
2003; 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
Figures 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.
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
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CA 02725717 2010-12-22
the surveying tool (e.g., gyroscope) into the casing 2404 with wireline, take
measurements, then remove the surveying tool prior to drilling further.
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 Figures 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.
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.
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
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CA 02725717 2010-12-22
the casing bias pad 2435 is attached. For example, as shown in Figure 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
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
Figure
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.
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
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CA 02725717 2010-12-22
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 Figures 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.
Figure 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 Figure
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 Figure
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 Figure 35. Therefore, the above description of these components
applies
equally to the embodiment shown in Figure 36.
The casing latch 2506 of Figure 36 is substantially similar to the casing
latch 2406
of Figure 35, so the majority of the above description of the casing latch
2406 applies
equally to the embodiment shown in Figure 36. The primary difference between
the
casing latch 2506 and the casing latch 2406 is that the casing latch 2506 of
Figure 36
does not have to be an orienting latch to keep track of the location of the
casing bias pad
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CA 02725717 2010-12-22
2535, as the casing bias pad 2535 of Figure 36 acts as a concentric stabilizer
(see
description below).
Instead of the mud motor 2425 of Figure 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.
An additional difference between the system of Figure 35 and the system of
Figure
36 is that rather than the eccentric casing bias pad 2435 of Figure 35, the
casing bias pad
2535 of Figure 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.
Just as in the embodiment of Figure 35, the embodiment illustrated in Figure
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.
In the operation of the embodiment of Figure 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 Figure 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.
As in the embodiment shown in Figure 35, the height of the casing bias pad
2535 is
predetermined before lowering the assembly downhole. However, in the
embodiment of
CA 02725717 2013-07-24
. .
Figure 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 Figures 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.
In the embodiments of Figures 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.
In the above embodiments shown and described in relation to Figures 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.
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.
The operation of embodiments depicted in Figures 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
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CA 02725717 2010-12-22
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.
Figure 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
Figures 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 Figure 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 Figure 35. Therefore, the above
description of
these components applies equally to the embodiment shown in Figure 37.
Instead of a bent motor 2550 as shown in Figure 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 Figure 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.
77
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CA 02725717 2010-12-22
Figures 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 Figure 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.
Figure 38B is another cross sectional view of the articulating housing 2760,
which is
rotated 90 degrees when compared to Figure 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.
Figures 39-41 show another embodiment of a directional drilling assembly. In
Figure 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
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CA 02725717 2010-12-22
the embodiment shown in Figures 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.
In Figure 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.
In Figure 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.
Referring initially to Figure 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.
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
Figure 43) and
downhole equipment, such as a bent sub 30A, drill bit 32A and/or float tools
34A needed
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CA 02725717 2010-12-22
for drilling the well, are suspended from a drilling plafform 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 Figure 43) of the drill string
20A to power
the drill motor to turn the drill bit 32A.
Referring now to Figure 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 Figure 43) in an aligned
position within
the float sub 34A. As shown in Figure 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
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CA 02725717 2010-12-22
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.
Referring still to Figure 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 Figure 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.
Referring still to Figure 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
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CA 02725717 2010-12-22
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 Figure 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. Figure 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.
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.
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.
Referring now to Figure 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
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CA 02725717 2010-12-22
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.
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.
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 120A.
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
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CA 02725717 2010-12-22
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.
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 Figure 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.
Referring to Figures 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
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CA 02725717 2010-12-22
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.
Referring now to Figures 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 Figure 45 to the fully-landed position of the
survey tool 200A
of Figure 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
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CA 02725717 2010-12-22
tool 200A between Figure 45 and Figure 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.
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 communicate
the
survey information to the surface via mud pulse telemetry, thereby eliminating
the need to
remove the survey tool to further drill the borehole.
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
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CA 02725717 2010-12-22
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.
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.
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.
87
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CA 02725717 2010-12-22
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.
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.
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).
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CA 02725717 2010-12-22
In another aspect shown in Figures 48-52, the present invention provides a
survey
tool assembly 900 for use while directionally drilling with casing. Figure 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.
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.
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.
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CA 02725717 2010-12-22
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 Figure 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 Figure 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.
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 Figure 52. In this manner, a higher flow rate may be supplied
to perform the
subsequent, higher flow rate operation.
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 Figure 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
Figures 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.
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 Figures 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
CA 02725717 2010-12-22
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.
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.
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.
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
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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.
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.
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.
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
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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.
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.
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.
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
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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.
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.
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.
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
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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.
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.
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
CA 02725717 2010-12-22
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.
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.
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.
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.
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;
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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.
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.
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.
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
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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.
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.
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
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motor system. In one aspect, the method further comprises flowing a physically
alterable
bonding material through the passageway to the earth removal member.
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.
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.
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
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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.
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.
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
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for further altering the trajectory of the wellbore through asymmetric fluid
flow through the
perforation.
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.
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.
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
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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.
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.
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.
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
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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.
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.
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.
Another embodiment of the present invention includes an apparatus for
deflecting a
wellbore, comprising a casing string with means for deflecting the casing
string
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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.
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.
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.
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.
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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.
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.
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.
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
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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.
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.
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.
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
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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.
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.
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.
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.
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.
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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.
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
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the drilling assembly through the drill string and advancing the drill string
within the
wellbore.
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.
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.
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
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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.
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.
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
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tool is disposed in the alignment member to provide a known orientation of the
survey tool
with the drill string.
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.
In yet another embodiment, the alignment member includes a stage tool and may
further include a float tool to receive a cement shoe thereon.
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.
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
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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.
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.
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.
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