Note: Descriptions are shown in the official language in which they were submitted.
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MECHANIZED SLOT DRILLING
Field of the Invention
The inventions relates to systems and methods for providing plane opening in
formations.
Background to the Invention
Considerable amounts of natural gas have been found to be producible from
formations such as source rocks, shale, and other low porosity and
permeability formations
by drilling long horizontal wells and stimulating the wells with multiple
propped fractures
so that a large volume of formation within a short distance of the well is
connected to the
wellbore. Hydrocarbons trapped in such formations then migrate toward the
volume
connected to the wellbore at rates that can result in economic production of
the
hydrocarbons from formations that were previously considered to be uneconomic
to
produce. Although fracturing of the formations can result in profitable
production, it
would be desirable to have an alternative to fracturing, to provide volumes
connected to
wellbores within these formations.
US patent 7,647,967 to Coleman et al. suggests a method to remove mass from a
formation between two connected wellbores by using a flexible cutting cable
such as a
segmented diamond cutting saw that is pulled reciprocally between two
wellbores. The
wellbores are drilled and connected so that the cutting cable may be inserted
into one of the
two, and then fished from connecting wellbore, and then repeatedly pulled back
and forth,
removing formation between the wellbores to form an opening in the shape of a
plane.
US patents 4,232,904 and 5,033,795 suggest methods to remove minerals such as
coal from seams using a chain cutter that is pulled through the seam initially
from a tunnel
drilled either in a U-shape or from two sides from which access to the seam is
provided by
excavation or from the seam outcropping.
Patent application publications W02010/074980, W02012/052496 and US
2011/0247810 suggest variations of using a chain cutter pulled back and forth
between
wellbores for the purpose of hydrocarbon production.
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Each of the references suggesting using flexible cutting cables rely on energy
transferred from rigs on the surface by lifting or reciprocating the cutters
to provide energy,
by lateral side force, for cutting the slot in the formation. The net energy
that can be
transmitted to cutting formation is limited by the strengths of the cutting
cables and the
speed with which surface rigs are able to reciprocate the cutting cables. The
result is that
formation is removed at a relatively slow rate.
SPE paper 68441by Philip Head et al. describes an electric coiled tubing
drilling
system that utilizes a fit for purpose electric motor to drive a steerable
drill bit. Typically,
steerable motors are driven by hydraulic positive displacement motors that
utilize energy
from pressure of the drilling fluid. With the electric drilling motor,
drilling fluid properties
and flow rates are not constrained by the requirements of both the formation
and drilling.
Summary of the invention
A system is provided for providing access to surfaces within a formation
comprising: a cylindrical cutting assembly having a first end and a second
end: a cutting
element positioned radially around a circumference of the cylindrical cutting
assembly; a
means for rotating the cutting element around the cutting assembly; and a
means for
moving the cutting assembly through a wellbore wherein the cutting assembly is
biased
against one side of the wellbore.
A method is also provide for providing a slotted opening in a formation, the
method
comprising: providing a wellbore from a first surface location to a second
surface location;
inserting into the wellbore a cylindrical cutting assembly connected to at
least two wellbore
tubular, one of the wellbore tubulars extending to each of the first surface
location and the
second surface location; and rotating the radial cylindrical cutting element.
A system that may be used to accomplish this method is also provided, the
apparatus comprising: a cylindrical cutting assembly having a first end and a
second end: a
cutting element positioned radially around a circumference of the cylindrical
cutting
assembly; a means for to rotating the cutting element around the cutting
assembly; and a
means for moving the cutting assembly through a wellbore wherein the cutting
assembly is
biased against one side of the wellbore.
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The method and apparatus of the present invention may provide more energy to
be
converted to mechanical motion within the wellbore to enable more rapid
creation of slot
volume than a system that requires mechanical motion be provided from the
surface
facilities by reciprocating a cutting element.
This rotating cutting action may be provided from the electric motors within
the
wellbores, or could be enhanced or replaced by rotating the entire drilling
assembly up to
the max torque allowed by the pipe having strength similar to wellbore tubular
used in
conventional directional drilling. Pipe rotation is induced to the entire
drill string from the
rotary table of the rig and drilling trajectory is planned to maximize the
rotation (therefore
resulting cutting action) while minimizing bend curvature and concentration of
torque and
bending moment in the drill pipe assembly.
Brief Description of the Figures
Figure 1 is a schematic figure of a wellbore connecting wellheads at two
surface
locations with a horizontal U-shaped section.
Figure 2 is a schematic figure of a wellbore connecting wellheads at two
surface
locations with a horizontal U-shaped section where a portion of the formation
between the
parallel legs of the U-shaped section has been removed according to the
present invention.
Figure 3 is a schematic of the apparatus of the present invention connected at
each
end to a wellbore tubular.
Figure 4 is a schematic of a wellbore from which a slot could be provided from
a
single wellbore in a formation.
Figure 5 is a schematic of alternative embodiment of the present invention.
Detailed Description
Referring now to Figure 1, a wellbore 101 with a horizontal U-shaped section
102
is shown. The wellbore has substantially vertical sections 103 extending from
surface
locations 104 where drilling rigs 105 are placed. The vertical sections extend
through
overburden 106 and into a target formation 107 that could contain hydrocarbons
such as,
for example, natural gas. The sections of the wellbores that extend through
the overburden
may be cased with casings 108 that are cemented into place. The U-shaped
section 102
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preferably has two essentially parallel legs 109, connected by an essentially
horizontal run
110. In some embodiments, the legs 109 could be tilted up, so that any
hydrocarbon
liquids produced from the wellbore after the well is completed would flow down
to a point
close to the vertical sections where they could be produced, by for example,
an electrical
submersible pump. Tilting up of the legs 109 may also facilitate the removal
of cuttings as
the slot is formed since the circulating drilling fluid would tend to follow
the shortest path
between legs 109 which would be at the lowest point as the slot is formed and
the cuttings
would also tend to aggregate at that lowest point. In other embodiments, the
legs 109 could
be angled up or down so that the completed slotted wellbore could be sheared
by horizontal
formation stresses to help maintain the slot open.
Wellbores 101 are shown with sections 103 being essentially vertical, but they
could enter the overburden angled, for example, at 45 degrees from vertical.
Having the
wellbores start out at an angle would reduce the friction between the
formation and
tubulars moving within the wellbore caused by the greater change in the
direction of the
wellbore to transition to a more horizontal orientation. The optimum angle of
the wellbore
entering from the surface could be estimated as a trade-off between the change
in frictional
forces and the increased length of vertical section 103 needed to reach the
target formation
107.
Most formations contain a direction in which most naturally occurring
fractures
occur. The U-shaped wellbore could be placed so that this plane, 111, is
essentially
perpendicular to the longest dimension of the finished slot between the legs
of the U-
shaped wellbore. This would maximize the number of natural fractures
intersected, and
increase production of hydrocarbons from the finished wellbore.
The U-shaped wellbore could be, for example, constructed by starting two
separate
wells, and connecting the two wells by intersecting the two wellbores in the
middle, at
mid-point 112. It would be very difficult to have the two wellbores lined up
so that they
intersect directly, but, for example, a magnetic device could be placed in the
end of the first
of the two wellbores to be provided, and the second could be directionally
drilled toward
the magnet, and the wellbores could be connected by intersecting the wellbores
at a
relatively small angle. The changes in direction shown in the figures are
greatly
exaggerated in order to show the entire well, but could be provided with
changes in
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direction in the range of 10 to 15 degrees for each one hundred feet of the
wellbore. This
is well within the range of directional drilling systems used in the oil and
gas industry.
Parallel legs 109, and essentially horizontal run 110 could be left as open
holes, or
could be cased with a soft millable casing.
In another embodiment, parallel legs 109 could be placed in an essentially
vertical
plane and a vertical rather than a horizontal slot may be formed.
The initial borehole is referred to as U-shaped, but the shape could be
significantly
different. It is not intended that this description be literally applied. For
example, two
wellbores could approach each other at an angle rather than straight, and
result in an initial
borehole that is the shape of a V instead of U, so long as the cutting element
could pass
through the intersection of the wellbores.
The U-shaped well is drilled with conventional directional drilling
techniques. The
dimensions of the U-shaped well may be, in general, with the essentially
parallel legs from
100 feet to two miles apart (31 meters to 3250 meters), or, for example, 500
to 2000 feet
apart (154 meters to 615 meters). The total length of the U-shaped well is
only limited by
the distance the legs could be directionally drilled and intersected. With the
total length of
the U-shaped well limited, the ratio of the distance between the essentially
parallel legs and
the length of the essentially parallel legs may be between 1:1 and 5:1. T area
of the final
slot between the legs of the U-shaped section is maximized when the ratio of
the distance
between the parallel legs and the distance between the essentially parallel
legs is 1:2. In
other embodiments, a longer length of the parallel legs may also be useful
because the
resulting longer slotted well, if placed perpendicular to the direction of
naturally occurring
fractures, would intersect more naturally occurring fractures and therefore
may more
efficiently connect the wellbores to a larger volume of the formation.
The two drilling rigs 105, when both are attached to the cutting element,
would
need to be operated in a coordinated manner. A distributed control system
("DCS") might
be utilized to coordinate this operation and optionally allow operation of
both drilling rigs
by one operator. Non-rotating casing protectors ("NRDPP") may also be utilized
to
control wear of the casings and reduce torque and drag in sections of the
wellbore not to be
part of the slot to be created. NRDPPs are described in, for example, SPE
Paper 76759 by
Fuller and Jardaneh, the disclosure of which is incorporated herein by
reference.
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The motors could be hydraulic motors, and could be positive displacement
hydraulic motors driven by a flow of drilling fluids. The motors could also be
electrical
motors such as the motor described in SPE paper 68441 by Head et al., or
electrical motors
similar to motors used in electrical submersible pumps. The motors may drive
collars
connected to cutting elements such as shearers similar to E-CTD type shearers,
described
in SPE paper 68441, SPE paper 52791 by Turner and et al, SPE paper 46013 by
Head and
et al. The number of shearing elements driven by each motor may be, for
example,
between one and one hundred, or between ten and fifty. More than one motor
could be
incorporated in the system. Electrical power could be provided by cables such
as those
used to power electrical submersible pumps. The cables could be placed inside
the
conduits for protection, and here may be multiple cables or multiple cables
extending to
each surface rig. The total power that could be provided to electrical motors
for the present
application could be sufficient to provide, for example, 1000 horse power to
drive cutting
elements. The motors described in SPE paper 68441 are claimed to be capable of
producing up to 28 horsepower. Thirty or more of such motors could be provided
along a
string of motor and cutting elements.
Typically, in a drilling operation, drilling fluids are circulated to a drill
bit through
a drilling string, and the drilling fluids cool and transport rock cuttings
back up the
wellbore through an annular around the drilling string. A system like this
conventional
drilling system could be used. Alternatively, drilling fluid could be pumped
down one
vertical wellbore, through the U-shaped portion and back up the other
wellbore. After the
slot is at least partially created, the velocities of the drilling fluid may
not be sufficient to
remove all of the cuttings created. Cuttings remaining in the slot will not
hinder subsequent
hydrocarbon production because the slots will still have permeability orders
of magnitude
higher than the formation.
Referring now to Figure 2, the U-shaped wellbore 201 is shown with slots 202
shown partially connecting two parallel legs, 203 and 204, of the U-shaped
wellbore. The
slot may be formed by placing in the well cutting assemblies having motors
driving cutting
elements around the circumference of the motors, and pulling the cutting
element back and
forth through the wellbore while tension is maintained on the cutting element
by, for
example, connecting each end of the cutting element to drill strings, coiled
tubing, bars
such as the bars used for sucker rod pumps, or combinations thereof Multiple
slots are
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shown in Figure 2 although in some embodiments, a single slot may be provided
connecting essentially the full length of the parallel legs 203 and 204.
Providing multiple
slots may reduce the cost by eliminating some slot cutting, and may provide
support and
reduce the tendency of the slot to collapse. Instead of, or in addition to
motors rotating the
cutting assemblies, the cutting assemblies could be rotated from the surface.
In general,
coiled tubing could be advantageous because the operation could be more
continuous and
therefore proceed more rapidly.
Referring now to Figure 3, a schematic drawing of a cutting assembly 301 is
shown. Cutting elements 302 are shown positioned radially around a
circumference of the
cutting assembly. A motor 303 within the cutting assembly drives the cutting
elements.
End connections 304 connect the ends of the cutting assembly to, for example,
coiled
tubing or drill string elements 305, the coiled tubing or drill string may
also provide a
protective conduit for electrical supply cables, and a path for drilling
fluids into the cutting
assembly, so that the drilling fluids may be directed at the cutting elements
to transport
cuttings from the cutting elements. The cutting assembly could also include
logging
instruments, or accelerometers to track the location of the cutting assembly.
Output from
the logging tools and/or accelerometers could be multiplexed and sent as a
high frequency
signal over the power supply cables to enable tracking of the progress of the
operation.
The cutting assembly 301 could be assembled with high torque non-upset
connections such as the TKC 4040 connection from Hunting Energy Services, 1018
Rankin Road, Houston, Texas, 77049. The cutting elements 302 could include
wear
resistant materials such as tungsten carbide, diamond impregnated elements or
polycrystalline diamond cutters, and the cutting elements could be positioned
along the
length of the cutting assembly. The cutting elements could be spiraled along
the
cylindrical outer surface of the cutting assembly. When hydraulic motors are
used, fluids
such as drilling mud could be provided from each of the drilling rigs, and,
for example, an
internal plug between motors being driven from fluids coming from each
direction could
be provided. The cutting assembly 301 could be provided with nozzles to
distribute
drilling fluids provide from one or both of the drilling rigs along the length
of the cutting
assembly as necessary to remove cuttings and to cool the cutting surfaces.
Joint 306 connects two separate motors 303, each of the two motors driving a
separate set of cutting elements associated with that motor. The motors rotate
the cutting
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elements in opposite directions, 307 and 308, so that torque against the wall
of the wellbore
is counteracted by the two oppositely turning sets of elements. Motor torque
may also be
counterbalanced, in some embodiments, by providing motors that turn in
opposite
directions.
Power supply is provided from surface facilities through cable 309.
Commercially
available power supplies useful, for example, for electrical submersible
pumps, may be
utilized.
The cutting elements may be biased against one portion of the wellbore by
being
held in tension by, for example, drill strings, rods, or coiled tubing
attached to each end of
the cutting assembly.
Torque from the cutting elements against the wall of the borehole may counter
each
other, by providing the cutting elements, or alternating sets of cutting
elements, that turn in
alternating directions. This would result in a more levelled and controllable
slot being
formed. The cutting elements could be provided to turn in opposite directions
by having,
for example, alternating motors turning in opposite directions, or alternating
motors could
be geared to turn the cutting elements in different directions, or individual
or sets of cutting
elements could be geared to rotate in opposite directions.
In some embodiments of the present invention, the carrier pipe could enhance
or
replace the cutting action from the electric motors by rotating the entire
assembly up to the
maximum torque capacity of the pipe, as currently done in directional
drilling. In this
embodiment, some or all of the cutting surfaces can be without a connection to
a motor.
In some embodiments of the present invention, multiple horizontal U-shaped
sections of wellbore could be provided from the same set of vertical
wellbores. The U-
shaped sections of wellbore could be provided in opposite directions at
similar levels, or
multiple levels of U-shaped sections of wellbore could be provided at
different elevations
in the same direction, or both. The U-shaped wellbores, and subsequent slotted
wellbores,
could be vertically displaced, for example, between 50 feet (15 meters) and
500 feet (154
meters), or between 70 feet (22 meters) and 200 feet (62 meters).
Now referring to Figure 4, a vertical wellbore 401 with two horizontal legs,
402
and 403, are shown. The horizontal legs could be created by side-tracking from
the
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vertical section in essentially the same direction as a lower horizontal
section, and drilling
the side-tracked leg of the well to essentially horizontal, and then toward
the lower section
to intersect the lower section. The lower section could have been drilled into
an upward
direction so that the intersection comes at a relatively small angle. This
angle may be less
than forty five degrees, or in another embodiment, between three and twenty
degrees. A
cutting element could then be placed in the wellbore according to the present
invention and
rotated or rotated and reciprocated to form a slot between the two horizontal
legs. The
horizontal legs may be legs that have a horizontal component but extend
outward from the
wellbore 401 and then connect to form a loop around a section of the formation
404 that
may be removed by the present invention to form a slot. The slot may be
essentially
vertical. Multiple essentially vertical slots may be formed from a single
wellbore by
forming pairs of essentially horizontal legs in different directions. In one
embodiment,
there may be two pairs of essentially horizontal legs provided in opposite
directions, so that
two slots may be formed where both slots are essentially perpendicular to the
orientation of
many naturally occurring fractures. In another embodiment, there may be, for
example,
four, six or eight pairs of essentially horizontal legs extending from the
wellbore to provide
four, six, or eight slots in the formation extending from the essentially
vertical wellbore.
Referring now to Figure 5, an embodiment of the present invention is shown
where
two essentially parallel wellbores, 502 and 503, have been connected to form a
section
connecting the two parallel legs 504. The essentially parallel wellbores could
be vertical,
horizontal, or between vertical and horizontal. Rotational power from the
surface, or from
motors within the wellbores, is utilized to wind a cutting element 501 around
a pair of
rotatable tubulars 504 and 506 and there by reciprocating the cutting element
501 between
the two essentially parallel wellbores by rotating the tubular so that the
cutting element is
wrapping around one tubular 506 as it is unwrapping from the other rotatable
tubular 505.
After the cutting element is essentially unwound from one rotatable tubular,
the rotations
are reversed and the cutting element is passed through the connecting section
of the
wellbore in the opposite direction. The rotatable tubular also maintains the
cutting element
in tension, and biased against the wall of the connecting section of the
wellbore so that the
cutting element forms a slot in the formation between the two essentially
parallel
wellbores. Using rotational power may reduce wear and abrasion experienced by
tubulars
505 and 506, and may reduce the tension on the cutting element. This
embodiment may
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also eliminate a need to remove slack on the drill pipe which would reduce non-
productive
rig time.
