Note: Descriptions are shown in the official language in which they were submitted.
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Method and Apparatus for Shaping a Well Hole
BACKGROUND OF THE INVENTION
Cross-Reference to Related Applications
[0001] Not Applicable.
Statement Regarding Federally Sponsored Research or Development
[0002] Not Applicable.
Background of the Invention
[0003] Directional drilling is the practice of drilling non-vertical wells.
This was originally an
accidental occurrence caused by rock formations or imprecise operations which
caused the
drilling head to diverge from the intended vertical course. The value of
drilling in a direction
other than straight down was realized as beneficial to the industry.
[0004] Several methods for drilling were developed which created inclinations,
deviations from
the vertical, of the wellbore. Down hole drilling motors, also known as mud
motors, driven by
the hydraulic power of drilling mud circulated down the drill string allow the
drill string to
remain stationary while only the bit rotates. By introducing a bent pipe (a
"bent housing")
between the mud motor and the drill string, the direction of the wellbore can
be selected and
controlled. There are also steerable motors which incorporate devices for
changing the
inclination on the fly. Other techniques and equipment also exist for
directional drilling control.
[0005] Three components are measured to determine the position of a wellbore:
the depth of the
point (measured depth), the inclination at the point, and the magnetic azimuth
at the point. These
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three components are collectively called a survey. Developments in measuring
the three
components allow wells to be directed to precise locations and orientations.
[0006] A series of consecutive surveys are used to track the progress and
location of a wellbore
as it progresses along a desired path. For various reasons periodic surveys
are only taken at
intervals of 30 ¨ 500 feet, with 90 feet (the length of a typical "stand")
being common during
active changes in angle or direction. These periodic surveys result in a
series course corrections,
and thus a wellbore is a collection of dog leg turns rather than a smooth
curving arc. Since
drilling often is stopped to produce a more accurate survey, increasing the
number of surveys
slows the drilling progress. Therefore, the tendency in rig operation is to
minimize the frequency
of surveys resulting in the need for coarser course corrections.
[0007] Aggressive bits used in progressive drilling results in a rough bore
wall. Rough bore
walls combined with the dog leg turns described above create a difficult
environment for
inserting and removing download drilling equipment ("Bottom Hole Assemblies"
or "BHA").
The rough geometry of the bore walls also makes it difficult for casing /
liners to be inserted into
a borehole. A dog leg that is too sharp may exceed the bending radius of the
liner. Rough walls
and dog legs can catch and snag the liner's leading edge preventing it from
reaching the end of
the lateral. Increased friction along the sides of the casing may call for
more force to be
necessary to push the casing into place. This increased force can cause the
casing to flex,
expand, buckle, or keyhole.
[0008] Use of aggressive bits to widen a bore hole or ease the curves can
cause a divergence in
the well path. Sidetracks or ledges can be created further resulting in an
unshapely hole.
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Further, aggressive bits can over enlarge a wellbore resulting in added
expenses, as extra
material is necessary to cement the casing in the wider bore hole. Constantly
stopping to
measure or check bore hole conditions is time consuming and costly.
BRIEF DESCRIPTION OF THE DRAWINGS
[0009] Figure 1 illustrates dog leg curves which obstruct inserting drill
strings down a rough
wellbore.
[0010] Figure 2 illustrates a front view of a drilling apparatus in accordance
with an exemplary
embodiment of the invention.
[0011] Figure 3 shows an exploded cut away view of the three possible sub-
assemblies of a
drilling apparatus in accordance with an exemplary embodiment of the
invention.
[0012] Figure 4 illustrates the use of a fluid circulating sub-assembly to
clear cuttings from a
side cutting sub-assembly and bullnose in accordance with an exemplary
embodiment of the
invention.
[0013] Figure 5A ¨ 5C shows the progression of a drilling apparatus through a
dog leg curve to
reshape a wellbore in accordance with an exemplary embodiment of the
invention.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0014] Disclosed herein is a design for an apparatus referred to in general
terms as a bottom hole
assembly (BHA). The apparatus is used during well drilling operations to shape
and clean a
wellbore after the initial pass by an aggressive drill head. In particular,
the apparatus' primary
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function is to clean the curves and lateral portions of a horizontal well. The
preferred
embodiment of the apparatus is a series of sub-assemblies which are connected
through pin
threads and box threads which secure the sub-assemblies end to end along a
common central axis
in to a single apparatus. The apparatus is then secured to the bottom end of a
drill string and ran
down an existing rough cut bore hole.
[0015] The sub-assemblies of particular interest to this disclosure are a side
cutting sub-
assembly, a fluid circulating sub-assembly, and a bullnose sub-assembly. One
skilled in the art
would appreciate that the features of the individual sub-assemblies could be
incorporated into
fewer sub-assemblies, or into a complete single assembly without means for
separating into sub-
assemblies. Further, one skilled in the art would appreciate that additional
features may be
incorporated in the BHA without compromising the functionality of the assembly
as described
herein. For simplicity and clarity in this disclosure, each sub-assembly is
described as a
separable unit. Further, the relative placement of each sub-assembly with
respect to the others is
described below when doing so makes their function and relative interactions
relevant. Nothing
in this disclosure is meant, or should be interpreted as limiting the
placement of the sub-
assemblies, or requiring the strict use of each assembly as a separate
assembly, or the
incorporation of other functionality or features not described herein.
[0016] The apparatus is fitted to the end of a drill string by use of a pin or
box thread connector
at the top of the BHA and is used to clean rough bore walls created by
aggressive cutting heads
during initial and subsequent well borings. Proper use of the device will ease
the abrupt angle
changes of dog legged turns as well as finish rough bore walls and remove
ledges, thus
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producing smooth flowing curves and clean bores which are more conducive to
insertion of liner
/ casing and the insertion and removal of other BHAs.
[0017] The side cutting sub-assembly is a tubular drill structure which
utilizes rows of cutting
surfaces oriented longitudinally on the outer surface. The cutting surfaces in
the preferred
embodiment are Polycrystalline Diamond Compact (PDC) cutters. The plurality of
these rows
are interspersed around the circumference along with longitudinally oriented
flow channels
which allow mud to flow past the rows of cutting surfaces thus removing the
cuttings produced
by drilling operations and carrying them back up the wellbore past the drill
string to the surface.
[0018] One skilled in the art would appreciate that the cutting surfaces could
be of other
materials. One skilled in the art would appreciate that the actual cutting
surfaces or structures,
the quantity, orientation and rotational speed of such cutting surfaces can be
tailored for the
environment in which the tool is to be used. Further, a variety of cutting
surfaces or structures
may be intermixed for specific environments.
[0019] To prevent the cutting surfaces from aggressively re-shaping the
wellbore by causing
ledges, pockets, or tangents, the cutting surfaces are alternately
interspersed with gauging
surfaces. Gauging surfaces are hard surfaces which do not substantially wear
or cut when in
contact with the bore wall. Gauging surfaces prevent the cutting surfaces from
penetrating too
deeply into the bore walls. In the preferred embodiment, the gauging surfaces
are diamond
domes (DD) which are hemispheres of approximately the same height as the PDC
cutting
surfaces. They are oriented around the cutting surfaces such that the gauging
surfaces contact
the bore wall and prevent cutting surfaces from penetrating too deeply into
the bore wall while
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still allowing the cutting surfaces to contact and remove any formation which
intrudes into the
wellbore.
[0020] To improve the efficiency of the assembly, fluid flow is used to remove
cuttings and to
lubricate and cool the BHA. As is traditional in BHA's fluid is circulated
down the drill string's
hollow center. This fluid reaches the bottom of the drill string and exits the
center through voids
in the BHA to then return to the surface along the outside of the drill
string. The fluid circulating
sub-assembly disclosed here uses a plurality of nozzles to further pressurize
drilling fluids.
These pressurized drilling fluids are then directed back up the wellbore past
the cutting surfaces
of the side cutting sub-assembly to remove the built up cuttings which slow
drilling processes.
[0021] The bullnose assembly has a rounded edge at the lower end so it will
not catch on ledges
or rough outcropping of the wellbore as it progresses down the well. While the
majority of the
bullnose has a hollow core, the bottom of the bullnose assembly is closed off
with optional
nozzles pointing in front or down the bore hole. The nozzles help clear the
wellbore before the
drilling apparatus by washing the cuttings to the side and back up the
wellbore.
[0022] In operating the drilling apparatus, the nozzles can be adjusted to
configure the Total
Flow Area (TFA) out the bottom of the bullnose sub-assembly, or out the fluid
circulating sub-
assembly to adjust the clearing of cuttings. There are several factors which
afford the choice of
nozzle configurations including mud weight, hole depth, drill pipe used,
maximum standpipe
pressure, desired gallons per minute (gpm) to clean hole, etc. The nozzle
configuration can also
be adjusted to provide uneven flow in order to create turbulent flow and thus
evacuate existing
and new cuttings out of the hole. The bullnose nozzles can be configured to
ensure the capability
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to wash through bridges and reduced hole sizes. The fluid circulating sub can
be configured to
maximize circulation cuttings up and out of the hole.
[0023] When the apparatus or BHA is being lowered down the vertical of a
wellbore the side
cutting sub-assembly may contact the bore wall with enough force to perform
significant cutting
actions in areas where the structures penetrate causing a restricted hole
size, or irregular shapes
of the wellbore. Whenever, when the BHA reaches a dog leg turn, the bullnose
will contact the
outside of the turn and the weight of the drill string will cause the side
cutter assembly to contact
the inside of the dog leg with enough force to cut and round the angled
corner. When the BHA
is lowered past the dog leg turn and into the straight part of the curve, the
flex of the drill string
will force the side cutter assembly against the outer wall with a force that
will allow it to cut into
the outside wall, thus widening the curve.
[0024] As the BHA is cutting the wellbore, the gauging surfaces rub against
the bore wall and
prevent the cutting surfaces from cutting too deeply. The bullnose's curved
edges keep the BHA
from catching on a ledge or from going off course to diverge from the original
wellbore.
[0025] Turning now to the drawings, Figure 1 illustrates dog leg curves which
obstruct inserting
drill strings down a rough wellbore. The drilling rig (100) pushes a casing or
liner (110) down a
wellbore (150). In traditional drilling, intermitting course correction cause
curves (153) in the
wellbore (150) to actually be a series of dog leg turns (155) which gradually
redirect the wellbore
to a lateral (157). However aggressive drilling and formation properties may
leave a rough
wellbore (illustrated in the enlarged section) where the bottom of the casing
or liner (120) can get
caught on edges of the wellbore (150).
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[0026] Figure 2 illustrates a front view of a drilling apparatus in accordance
with an exemplary
embodiment of the invention. The drilling apparatus (200) is an assembly of
three sub-
assemblies (220, 250, and 270). The sub-assembly illustrated on top of the
stack is a side cutting
sub-assembly (220), which has a pin thread (201) at the top end and a box
thread (202, not
visible) at the lower end. The tubular body (221, not designated) contains a
plurality of cutter
arrays (222) interspersed with flow channels (223) around the circumference of
the tubular body
(221). A cutter array (222) has alternating cutting surfaces (226) and gauging
surfaces (225).
Cutting channels run between the surfaces (225, 226) from one flow channel
(223) to another.
[0027] One skilled in the art would appreciate that the pin thread and box
thread described above
could be replace with other joining apparatus for linking the sub assembly to
other sub
assemblies or for linking the sub assembly to the components of the drill
string. Further, one
skilled in the art would appreciate that the pin threads and box threads could
be eliminated such
that one or more sub assemblies are joined into a single new assembly
comprising all aspects of
the described sub assemblies.
[0028] The sub-assembly illustrated in the middle of the stack is a fluid
circulating sub-assembly
(250). A plurality of up pointing or backward facing nozzles (255) direct
fluid back up the
annulus past the cutter arrays (222). The fluid circulating sub-assembly (250)
has a pin thread at
the top end which is illustrated as a thread joint (203) where it mates with
the box thread located
at the bottom of the side cutting sub-assembly (220).
[0029] The sub-assembly illustrated on the bottom of the stack is a bullnose
sub-assembly (270).
The closed bottom (288) of the bullnose sub-assembly (270) is rounded on the
edges (285). The
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bullnose sub-assembly (270) has a pin thread at the top end which is
illustrated as a thread joint
(203) where it mates with the box thread located at the bottom of the fluid
circulating sub-
assembly (250).
[0030] Figure 3 shows an exploded cut away view of the three possible sub-
assemblies of a
drilling apparatus in accordance with an exemplary embodiment of the
invention. The drilling
apparatus (200) is an assembly of three sub-assemblies (220, 250, and 270). It
is made up of a
hollow tubular body (221) which has a central channel (210) The first sub-
assembly, illustrated
on top of the stack, is a side cutting sub-assembly (220), which has a pin
thread (201) at the top
end and a box thread (202) at the lower end. The tubular body (221) contains a
plurality of cutter
arrays (222) interspersed with flow channels (223, not illustrated) around the
circumference of
the tubular body (221). A cutter array (222) has alternating cutting surfaces
(226) and gauging
surfaces (225). Cutting channels run between the surfaces (225, 226) from one
flow channel
(223) to another.
[0031] The second sub-assembly, illustrated in the middle of the stack, is a
fluid circulating sub-
assembly (250). A plurality of up-pointing or backward-facing nozzles (255)
direct fluid from
the central channel (210), back up the annulus past the cutter arrays (222).
The fluid circulating
sub-assembly (250) has a pin thread at the top end (201) and a box thread
(202) at the lower end.
[0032] The third sub-assembly, illustrated on the bottom of the stack, is a
bullnose sub-assembly
(270). The closed bottom (288) of the bullnose sub-assembly (270) is rounded
on the edges
(285) to create the bullnose (280) at the lower end of the assembly. The upper
end of the
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assembly has a pin thread (201). The bullnose assembly (270) has nozzles (275)
in the bottom
(288) of the assembly which direct fluid from the central channel (210) out
into the wellbore.
[0033] Figure 4 illustrates the use of a fluid circulating sub-assembly to
clear cuttings from a
side cutting sub-assembly in accordance with an exemplary embodiment of the
invention. In this
view, the drill string (110) is shown pushing the drilling apparatus (200, not
designated) down
through the wellbore (150). The up nozzles (255) in the fluid circulating sub-
assembly (250)
direct fluid (410) up the wellbore to remove cuttings (450) from the wellbore
(150). Further,
down facing nozzles (275) located in the bullnose (280) direct fluid (420)
ahead of the BHA to
loosen and remove cuttings (450) from the wellbore (150).
[0034] Figure 5A ¨ 5C shows the progression of a drilling apparatus through a
dog leg curve to
reshape a wellbore in accordance with an exemplary embodiment of the
invention. Figure 5A
show what happens as the drill string (110) pushes the drilling apparatus
(200, not designated)
down through a curve (153) in the wellbore (150) the bullnose (270) comes in
contact with the
side of the curve (153).
[0035] Figure 5B show that as the drill string (110) continues to push the
drilling apparatus (200)
through the dog leg turn (155) of a curve (153) in the wellbore (150), the
side cutting sub-
assembly (220) is forced against the inside of the dog leg turn (155) allowing
the side cutting
sub-assembly (220) to cut into the bore wall easing the curve (155' in Figure
5C)
[0036] Figure 5C shows that as the drill string (110) continues past the eased
dog leg turn (155')
the drill string (110) will continue to flex (exaggerated for clarity) to
force the side cutting
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assembly (220) against the outside wall of the curve (153). The bullnose (270)
will continue to
steer the drilling apparatus (200) through the existing wellbore (150)
preventing divergent paths
from being cut.
[0037] The diagrams in accordance with exemplary embodiments of the present
invention are
provided as examples and should not be construed to limit other embodiments
within the scope
of the invention. For instance, heights, widths, and thicknesses may not be to
scale and should
not be construed to limit the invention to the particular proportions
illustrated. Additionally
some elements illustrated in the singularity may actually be implemented in a
plurality. Further,
some element illustrated in the plurality could actually vary in count.
Further, some elements
illustrated in one form could actually vary in detail. Further yet, specific
numerical data values
(such as specific quantities, numbers, categories, etc.) or other specific
information should be
interpreted as illustrative for discussing exemplary embodiments. Such
specific information is
not provided to limit the invention.
[0038] The above discussion is meant to be illustrative of the principles and
various
embodiments of the present invention. Numerous variations and modifications
will become
apparent to those skilled in the art once the above disclosure is fully
appreciated. It is intended
that the following claims be interpreted to embrace all such variations and
modifications.
