Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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METHOD AND APPARATUS FOR LATERAL DRILLING
THROUGH A SUBTERRANEAN FORMATION
TECHNICAL FIELD
[0001] The present invention relates generally to a
method and system for facilitating horizontal (also referred
to as "lateral") drilling into a subterranean formation
surrounding a well casing. More particularly, the invention
relates to an internally, rotating nozzle that may be used to
facilitate substantially horizontal drilling into a
subterranean formation surrounding a well casing.
BACKGROUND
[0002] The rate at which hydrocarbons are produced
from wellbores in subterranean formations is often limited
by wellbore damage caused . by drilling, cementing,
stimulating, and producing. As a result, the hydrocarbon
drainage-area of wellbores is often limited, and hydrocarbon
reserves become uneconomical- to produce sooner than they
would have otherwise, and are therefore not fully recovered.
Similarly, increased power is required to inject fluids,
such as water and C02, and to dispose of waste water, into
wellbores when a wellbore is damaged.
[0003] Formations may be fractured to stimulate
hydrocarbon production and drainage from wells, but
fracturing is often difficult to control. and results in
further formation damage and/or breakthrough to other
formations.
[0004] Tight formations are particularly susceptible
to formation damage. To better control damage to tight
formations, lateral (namely, horizontal) completion
technology has been developed. For example, guided rotary
drilling with a flexible drill string and a decoupled
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downhole guide mechanism has been used to drill laterally
into a formation, to thereby stimulate hydrocarbon
production and drainage. However, a significant limitation
of this approach has been severe drag and wear on drill pipe
since an entire drill string must be rotated as it moves
through a curve going from vertical to horizontal drilling.
[0005] Coiled tubing drilling (CTD) has been used to
drill lateral drainage holes, but is expensive and typically
requires about a 60 to 70 foot radius to maneuver into a
lateral orientation.
[0006] High pressure jet systems, utilizing non-
rotating nozzles and externally rotating nozzles with fluid
bearings have been developed to drill laterally to bore
tunnels (also referred to as holes or boreholes) through
subterranean formations. Such jet systems, however, have
failed due to the turbulent dissipation of jets in a deep,
fluid-filled borehole, due to the high pressure required to
erode deep formations, and, with respect to externally
rotating nozzles, due to impairment of the rotation of the
nozzle from friction encountered in the formation.
[0007] Accordingly, there is a need for methods and
systems by which wellbore damage may be minimized and/or
bypassed, so that hydrocarbon drainage areas and drainage
rates may be increased, and the power required to inject
fluids and dispose of waste water into wellbores may be
reduced.
BRIEF SUMMARY OF THE INVENTION
[0008] According to the present invention, lateral
(i.e., horizontal) wellbores are utilized to facilitate a
more efficient sweep in secondary and tertiary hydrocarbon
recovery fields, and to reduce the power required to inject
fluids and dispose of waste water into wells. The
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horizontal drilling of such lateral wellbores through a well
casing is facilitated by positioning in the well casing a
shoe defining a passageway extending from an upper opening
in the shoe through the shoe to a side opening in the shoe.
A rod and casing mill assembly is then inserted into the
well casing and through the passageway in the shoe until a
casing mill end of the casing mill assembly abuts the well
casing. The rod and casing mill assembly are then rotated
until the casing mill end forms a perforation in the well
casing.
[0009] An internally rotating nozzle is rotatably
mounted in a housing connectable to a hose for receiving
high pressure fluid. The rotor includes at least two
tangential jets oriented off of center and configured for
ejecting fluid to generate torque and rotate the rotor.
[0020] The rotating nozzle is then attached to the end
of a flexible hose which is extended through the passageway
to the perforation. High pressure fluid is ejected from the
rotating nozzle through the perforation to cut a tunnel in
subterranean earth formation.
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BRIEF DESCRIPTION OF THE DRAWINGS
[0011] For a more complete understanding of the
present invention, and the advantages thereof, reference is
now made to the following descriptions taken in conjunction
with the accompanying drawings, in which:
[0012] FIGURE 1 is a cross-sectional elevation view of
a well having a drilling shoe positioned therein;
[0013] FIGURE 2 is a cross-sectional elevation view of
the well of FIG. 1 having a perforation mechanism embodying
features of the present invention positioned within the
drilling shoe;
[0014] FIGURE 3 is a cross-sectional elevation view of
the well of FIG. 2 showing the well casing perforated by the
perforation mechanism;
[0015] FIGURE 4 is a cross-sectional elevation view of
the well of FIG. 3 with the perforation mechanism removed;
[0016] FIGURE 5 is a cross-sectional elevation view of
the well of FIG. 4 showing a hydraulic drilling device
extended through the casing of the well;
[0017] FIGURE 6 is a cross-sectional elevation view of
the nozzle of FIG. 5;
[0018] FIGURE 7 is a elevation view taken along the
line 7-7 of FIG. 6;
[0019] FIGURE 8 is a cross-sectional elevation view of
an alternative embodiment of the nozzle of FIG. 6 with
brakes;
[0020] FIGURE 9 is a cross-sectional elevation view
taken along the line 9-9 of FIG. 8;
[0021] FIGURE 10 is a cross-sectional elevation view
of an alternative embodiment of the nozzle of FIG. 8 that
further includes a center nozzle; and
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[0022] FIGURE 11 is a elevation view taken along the
line 11-11 of FIG. 10.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT
[0023] In the discussion of the FIGURES the same
reference numerals will be used throughout to refer to the
same or similar components. In the interest of conciseness,
various other components known to the art, such as
wellheads, drilling components, motors, and the like
necessary for the operation of the wells, have not been
shown or discussed except insofar as necessary to describe
the present invention.
[0024] Referring to FIGURE 1 of the drawings, the
reference numeral 10 generally designates an existing well
encased by a well casing 12 and cement 14. The well 10
passes through a subterranean formation 16 from which
petroleum is drawn. A drilling shoe 18 is securely attached
to a tubing 20 via a tapered threaded fitting 22 formed
between the tubing 20 and the shoe 18. The shoe 18 and
tubing 20 are defined by an outside diameter approximately
equal to the inside diameter of the well casing 12 less
sufficient margin to preclude jamming of the shoe 18 and
tubing 20 as they are lowered through the casing 12. The
shoe 18 further defines a passageway 24 which extends
longitudinally through the shoe, and which includes an upper
opening 26 and a lower opening 28. The passageway 24
defines a curved portion having a radius of preferably at
least three inches. The upper opening 26 preferably
includes a limit chamfer 27 and an angle guide chamfer 29,
for receiving a casing mill, described below.
[0025] As shown in FIG. 1, the shoe 18 is lowered in
the well 10 to a depth suitable for tapping into a
hydrocarbon deposit (not shown), and is angularly oriented
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in the well 10 using well-known techniques so that the
opening 28 of the shoe 18 is directed toward the hydrocarbon
deposit. The shoe 18 is fixed in place by an anchoring
device 25, such as a conventional packer positioned
proximate to a lower end 18a of the shoe 18. While the
anchoring device 25 is shown in FIG. 1 as positioned
proximate to the lower end 18a of the show 18, the anchoring
device is preferably positioned above, or alternatively,
below the shoe.
[0026] FIGURE 2 depicts the insertion of a rod 30 and
casing mill assembly 32 as a single unit through the tubing
and into the passageway 24 of the shoe 18 for perforation
of the well casing 12. The rod 30 preferably includes an
annular collar 34 sized and positioned for seating in the
15 chamfer 27 upon entry of the casing mill 32 in the cement
14, as described below with respect to FIG. 3. The rod 30
further preferably includes, threadingly connected at the
lower end of the rod 30, a yoke adapter 37 connected to a
substantially barrel-shaped (e.g., semi-spherical or semi-
20 elliptical) yoke 36 via a substantially straight yoke 38 and
two conventional block and pin assemblies 39 operative as
universal joints. The barrel-shaped yoke 36 is connected to
a similar substantially barrel-shaped yoke 40 via a
substantially straight yoke 42 and two conventional block
and pin assemblies 43 operative as universal joints.
Similarly, the barrel-shaped yoke 40 is connected to a
substantially barrel-shaped yoke 44 via a substantially
straight yoke 46 and two conventional block and pin
assemblies 47 operative as universal joints. Similarly, the
barrel-shaped yoke 44 is connected to a substantially
barrel-shaped "half" yoke 48 via a conventional block and
pin assembly 49 operative as a universal joint. The
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surfaces of the yokes 36, 40, 44, and 48 are preferably
barrel-shaped so that they may be axially rotated as they
are passed through the passageway 24 of the shoe 18. The
yoke 48 includes a casing mill end 48a preferably having,
for example, a single large triangular-shaped cutting tooth
(shown), a plurality of cutting teeth, or the like,
effective upon axial rotation for milling through the well
casing 12 and into the cement 14. The milling end 48a is
preferably fabricated from a hardened, high strength,
stainless steel, such as 17-4 stainless steel with tungsten
carbides inserts, tungsten carbide, or the like, having a
relatively high tensile strength of, for example, at least
100,000 pounds per square inch, and, preferably, at least
150,000 pounds per square inch. While four substantially
barrel-shaped yokes 36, 40, 44, and 48, and three
substantially straight yokes 38, 42, 46, are shown and
described with respect to FIG. 2, more or fewer yokes may be
used to constitute the casing mill assembly 32.
[0027] The rod 30 is preferably connected at the well-
head of the well 10 to a rotating device, such as a motor
51, effective for generating and transmitting torque to the
rod 30 to thereby impart rotation to the rod. The torque
transmitted to the rod 30 is, by way of example, from about
to about 1000 foot-pounds of torque and, typically, from
25 about 100 to about 500 foot-pounds of torque and,
preferably, is about 200 to about 400 foot-pounds of torque.
The casing mill assembly 32 is preferably effective for
transmitting the torque and rotation from the rod 30 through
the passageway 24 to the casing mill end 48.
[0028] In operation, the tubing 20 and shoe 18 are
lowered into the well casing 12 and secured in position by
an anchoring device 25, as described above. The rod 30 and
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casing mill assembly 32 are then preferably lowered as a
single unit through the tubing 20 and guided via the angle
guide chamfer 29 into the shoe 18. The motor 51 is then
coupled at the well-head to the rod 30 for generating and
transmitting preferably from about 100 to about 400 foot-
pounds of torque to the rod 30, causing the rod 30 to
rotate. As the rod 30 rotates, it imparts torque and
rotation to and through the casing mill assembly 32 to
rotate the casing mill end 48.
[0029] The weight of the rod 30 also exerts downward
axial force in the direction of the arrow 50, and the axial
force is transmitted through the casing mill assembly 32 to
the casing mill end 48. The amount of weight transmitted
through the casing mill assembly 32 to the casing mill end
48 may optionally be more carefully controlled to maintain
substantially constant weight on the casing mill end 48 by
using weight bars and bumper subs (not shown) . As axial
force is applied to move the casing mill end 48 into the
well casing 12 and cement 14, and torque is applied to
rotate the casing mill end 48, the well casing 12 is
perforated, and the cement 14 is penetrated, as depicted in
FIGURE 3. The weight bars are thus suitably sized for
efficiently perforating the well casing 12 and penetrating
the cement 14 and, to that end, may, by way of example, be
sized at 150 pounds each, it being understood that other
weights may be preferable depending on the well. Weight
bars and bumper subs, and the sizing thereof, are considered
to be well known in the art and, therefore, will not be
discussed in further detail herein.
[0030] As the casing mill end 48 penetrates the cement
14, the collar 34 seats in the chamfer 27, and the
perforation of the well casing is terminated. The rod 30
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and casing mill assembly 32 are then withdrawn from the shoe
18, leaving a perforation 52, which remains in the well
casing 12, as depicted in FIGURE 4. Notably, the cement 14
is preferably not completely penetrated. To obtain fluid
communication with the petroleum reservoir/deposit of
interest, a horizontal extension of the perforation 52 is
used, as discussed below with respect to FIG. 5.
[0031] FIGURE 5 depicts a horizontal extension
technique that may be implemented for extending the
perforation 52 (FIG. 4) laterally into the formation 16 in
accordance with present invention. The shoe 18 and tubing
are maintained in place. A flexible hose 62, having a
nozzle 64 affixed to a lower end thereof, is extended
through the tubing 20, the guide chamfer 29 and passageway
15 24 of the shoe 18, and the perforation 52 into the cement
14. The flexible hose 62 is preferably a high-pressure
(e.g., tested for a capacity of 20,000 PSI or more) flexible
hose, such as a Polymide 2400 Series hose, preferably
capable of passing through a curve having a radius of three
20 inches. The hose 62 is preferably circumscribed by a spring
66 preferably comprising spiral wire having a square cross-
section which abuts the nozzle 64 for facilitating "pushing"
the hose 62 downwardly through the tubing 20. The spring 66
may alternatively comprise spiral wire having a round cross-
section. The nozzle 64 is a high-pressure rotating nozzle,
as described in further detail with respect to FIGS. 6-10.
A plurality of annular guides, referred to herein as
centralizers, 68 are preferably positioned about the spring
66 and suitably spaced apart for inhibiting bending and
kinking of the hose 62 within the tubing 20. Each
centralizer 68 has a diameter that is substantially equal to
or less than the inside diameter of the tubing 20, and
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preferably also defines a plurality of slots and/or holes
68a for facilitating the flow of fluid through the, tubing
20. The centralizers 68 are preferably also configured to
slide along the spring 66 and rest and accumulate at the top
of the shoe 18 as the hose 62 is pushed through the
passageway 24 and perforation 52 into the formation 16.
[0032] Drilling fluid is then pumped at high pressure
through the hose 62 to the nozzle 64 using conventional
equipment 67 (e.g., a compressor, a pump, and/or the like)
at the surface of the well 10. The drilling fluid used may
be any of a number of different fluids effective for eroding
subterranean formation, such fluids comprising liquids,
solids, and/or gases including, by way of example but not
limitation, one or a mixture of two or more of fresh water,
produced water, polymers, water with silica polymer
additives, surfactants, carbon dioxide, gas, light oil,
methane, methanol, diesel, nitrogen, acid, and the like,
which fluids may be volatile or non-volatile, compressible
or non-compressible, and/or optionally may be utilized at
supercritical temperatures and pressures. The drilling
fluid is preferably injected through the hose 62 and ejected
from the nozzle 64, as indicated schematically by the arrows
66, to impinge subterranean formation material. The
drilling fluid loosens, dissolves, and erodes portions of
the earth's subterranean formation 16 around the nozzle 64.
The excess drilling fluid flows into and up the well casing
12 and tubing 20, and may be continually pumped away and
stored. As the earth 16 is eroded away from the frontal
proximity of the nozzle 64, a tunnel (also referred to as an
opening or hole) 70 is created, and the hose 62 is extended
into the tunnel. The tunnel 70 may generally be extended
laterally 200 feet or more to insure that a passageway
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extends and facilitates fluid communication between the well
and the desired petroleum formation in the earth's
formation 16.
[0033] After a sufficient tunnel 70 has been created,
5 additional tunnels may optionally be created, fanning out in
different directions at substantially the same level as the
tunnel 70 and/or different levels. If no additional tunnels
need to be created, then the flexible hose 62 is withdrawn
upwardly from the shoe 18 and tubing 20. The tubing 20 is
10 then pulled upwardly from the well 10 and, with it, the shoe
18. Excess drilling fluid is then pumped from the well 10,
after which petroleum product may be pumped from the
formation.
[0034] FIGURE 6 depicts one preferred embodiment of
the nozzle 64 in greater detail positioned in the tunnel 70,
the tunnel having an aft portion 70a and a fore portion 70b.
As shown therein, the nozzle 64 includes a hose fitting 72
configured for being received by the hose 62. In a
preferred embodiment, the hose fitting 72 also includes
circumferential barbs 72a and a conventional band 73 clamped
about the periphery of the hose 62 for securing the hose 62
onto the hose fitting 72 and barbs 72a.
[0035] The hose fitting 72 is threadingly secured to a
housing 74 of the nozzle 64 via threads 75, and defines a
passageway 72b for providing fluid communication between the
hose 62 and the interior of the housing 74. A seal 76, such
as an O-ring seal, is positioned between the hose fitting 72
and the housing 74 to secure the housing 74 against leakage
of fluid received from the hose 62 via the hose fitting 72.
The housing 74 is preferably fabricated from a stainless
steel, and preferably includes a first section 74a having a
first diameter, and a second section 74b having a second
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diameter of about 2-20% larger than the first diameter, and
preferably about 10% larger than the first diameter. While
the actual first and second diameters of the housing 74 are
scalable, by way of example and not limitation, in one
preferred embodiment, the second diameter is about 1-1.5
inches in diameter, and preferably about 1.2 inches in
diameter. About eight drain holes 74c are preferably
defined between the first and second sections 74a and 74b of
the housing 74, for facilitating fluid communication between
the aft portion 70a and the fore portion 70b of the tunnel
70. The number of drain holes 74c may vary from eight, and
accordingly may be more or less than eight drain holes.
[0036] A rotor 84 is rotatably mounted within the
interior of the housing 74, and includes a substantially
conical portion 84a and a cylindrical portion 84b. The
conical portion 84a includes a vertex 84a' directed toward
the hose fitting 72. The cylindrical portion 84b includes
an outside diameter approximately equal to the inside
diameter of the housing 74 less a margin sufficient to avoid
any substantial friction between the rotor 84 and the
housing 74. The cylindrical portion 84b abuts a bearing 78,
preferably configured as a thrust bearing, and race 88,
which seat against an end of the housing 74 opposed to the
hose fitting 72. The thrust bearing 78 is preferably a
carbide ball bearing, and the race 88 is preferably
fabricated from carbide as well. A radial clearance seal
(not shown) may optionally be positioned between the rotor
84 and the bearing race 88 to minimize fluid leakage through
the bearing 78. A center extension portion 84c of the rotor
84 extends from the cylindrical portion 84b through the
thrust bearings 78 and'race 88, and two tangential jets 84d
are formed on the rotor center extension portion 84c. Each
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jet 84d is configured to generate a jet stream having a
diameter of about 0.025 to 0.075 inches, and preferably
about 0.050". Passageways 84e are defined in the rotor 84
for facilitating fluid communication between the interior of
the housing 74 and the jets 84d.
[0037] As shown most clearly in FIG. 7, the tangential
jets 84d are offset from a center point 84f and are directed
in substantially opposing directions, radially spaced from,
and tangential to, the center point 84f. Referring back to
FIG. 6, the jets 84d are preferably further directed at an
angle 91 of about 45 from a centerline 84g extending
through the rotor 84 from the vertex 84a through the center
point 84f.
[0038] Further to the operation described above with
respect to FIGS. 1-5, and with reference to FIGS. 6 and 7,
fluid is pumped down and through the hose 62 at a flow rate
of about 15 to 25 gallons per minute (GPM), preferably about
GPM, and a pressure of about 10,000 to 20,000 pounds per
square inch (PSI), preferably about 15,000 PSI. The fluid
20 passes through the passageway 72b into the interior of the
housing 74. The fluid then passes into and through the
passageways 84e to the jets 84d, and is ejected as a
coherent jet stream of fluid 90 from the jets 84c at an
angle 91 from the centerline 84g. The jet stream of fluid
90 impinges and erodes earth in the fore portion 70b of the
tunnel 70. A tangential component of the stream of fluid 90
(FIG. 7) causes the rotor 84 to rotate in the direction of
an arrow 85 at a speed of about 40,000 to 60,000 revolutions
per minute (RPM), though a lower RPM are generally
preferred, as discussed in further detail below with respect
to FIGS. 8-11. As the rotor 84 rotates, the stream of fluid
90 rotates, further impinging and eroding a cylindrical
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portion of earth in the fore portion 70b of the tunnel 70,
thereby extending longitudinally the tunnel 70. As earth is
eroded, it mixes with the fluid, drains away through the
holes 74c, passes through the aft portion 70a of the tunnel
70, and then flows upwardly through and out of the well 10.
The nozzle 64 is then urged via the hose 62 toward the fore
portion 70b of the tunnel 70 to extend the tunnel 70 as a
substantially horizontal portion of the well 10.
[0039] FIGURES 8 and 9 depict the details of a nozzle
100 according to an alternate embodiment of the present
invention. Since the nozzle 100 contains many components
that are identical to those of the previous embodiment
(FIGS. 6-7), these components are referred to by the same
reference numerals, and will not be described in any further
detail. According to the embodiment of FIGURES 8 and 9, a
brake lining 102 extends along, and is substantially affixed
to, the interior peripheral surface of the housing 74. The
brake lining 102 is preferably fabricated from a relatively
hard material, such as hardened carbide steel. Two or more
brake pads 104, likewise fabricated from a relatively hard
material, such as hardened carbide steel, are positioned
within mating pockets defined between the rotor 84 and the
brake lining 102, wherein the pockets are sized for matingly
retaining the brake pads 104 proximate to the brake lining
102 so that, in response to centrifugal force, the brake
pads 104 are urged and moved radially outwardly to
frictionally engage the brake lining 102 as the rotor 64
rotates.
[0040] Operation of the nozzle 100 is similar to the
operation of the nozzle 64, but for a braking effect
imparted by the brake lining 102 and brake pads 104. More
specifically, as the rotor 84 rotates, centrifugal force is
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generated which is applied onto the brake pads 104, urging
and pushing the brake pads 104 outwardly until they
frictionally engage the brake lining 102. It should be
appreciated that as the rotor 84 rotates at an increasing
speed, or RPM, the centrifugal force exerted on the brake
pads 104 increases in proportion to the square of the RPM,
and resistance to the rotation thus increases exponentially,
thereby limiting the maximum speed of the rotor 84, without
significantly impeding rotation at lower RPM's.
Accordingly, in a preferred embodiment, the maximum speed of
the rotor will be limited to the range of about 1,000 RPM to
about 50,000 RPM, and preferably closer to 1,000 RPM (or
even lower) than to 50,000 RPM. It is understood that the
centrifugal force generated is, more specifically, a
function of the product of the RPM squared, the mass of the
brake pads, and radial distance of the brake pads from the
centerline 84g. The braking effect that the brake pads 104
exert on the brake lining 102 is a function of the
centrifugal force and the friction between the brake pads
104 and the brake lining 102, and, furthermore, is
considered to be well known in the art and, therefore, will
not be discussed in further detail herein.
[0041] FIGURE 10 depicts the details of a nozzle 110
according to an alternate embodiment of the present
invention. Since the nozzle 110 contains many components
that are identical to those of the previous, embodiments
(FIGS. 6-9), these components are referred to by the same
reference numerals, and will not be described in any further
detail. According to the embodiment of FIGURE 10, and with
reference also to FIGURE 11, an additional center jet 84h,
preferably smaller than (e.g., half the diameter of) the
tangential jets 84d, is configured in the center extension
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portion 84c of the rotor 84, interposed between the two
tangential jets 84d for ejecting a jet stream 112 of fluid
along the centerline 84g.
[0042] Operation of the nozzle 110 is similar to the
operation of the nozzle 100, but for providing an additional
jet stream of fluid from the center jet 84h, effective for
cutting the center of the tunnel 70.
[0043] By the use of the present invention, a tunnel
may be cut in a subterranean formation in a shorter radius
than is possible using conventional drilling techniques,
such as a slim hole drilling system, a coiled tube drilling
system, or a rotary guided short radius lateral drilling
system. Even compared to ultra-short radius lateral
drilling systems, namely, conventional water jet systems,
the present invention generates a jet stream which is more
coherent and effective for cutting a tunnel in a
subterranean formation. Furthermore, by utilizing bearings,
the present invention also has less pressure drop in the
fluid than is possible using conventional water jet systems.
[0044] It is understood that the present invention may
take many forms and embodiments. Accordingly, several
variations may be made in the foregoing without departing
from the spirit or the scope of the invention. For example,
the conical portion 84a of the rotor 84, or a portion
thereof, may be inverted to more efficiently capture fluid
from the hose 62. The brake pads 104 (FIG. 9) may be
tapered to reduce resistance from, and turbulence by, fluid
in the interior of the housing 74 as the rotor 84 is
rotated. The thrust bearing 78 may comprise types of
bearings other than ball bearings, such as fluid bearings.
Having thus described the present invention by reference to
certain of its preferred embodiments, it is noted that the
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embodiments disclosed are illustrative rather than limiting
in nature and that a wide range of variations,
modifications, changes, and substitutions are contemplated
in the foregoing disclosure and, in some instances, some
features of the present invention may be employed without a
corresponding use of the other features. Many such
variations and modifications may be considered obvious and
desirable by those skilled in the art based upon a review of
the foregoing description of preferred embodiments.
Accordingly, it is appropriate that the appended claims be
construed broadly and in a manner consistent with the scope
of the invention.
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