U.S. patent application number 13/226478 was filed with the patent office on 2012-03-22 for apparatus and method for lateral well drilling.
This patent application is currently assigned to NITRO DRILL TECHNOLOGIES, LLC. Invention is credited to James M. Savage.
Application Number | 20120067646 13/226478 |
Document ID | / |
Family ID | 45810950 |
Filed Date | 2012-03-22 |
United States Patent
Application |
20120067646 |
Kind Code |
A1 |
Savage; James M. |
March 22, 2012 |
Apparatus and Method for Lateral Well Drilling
Abstract
A downhole tool assembly for cutting laterally into an earthen
formation from a wellbore. The downhole tool assembly includes a
cutting head assembly and a flexible tubular shaft member, wherein
the cutting head assembly includes a rotatable nozzle and a cutting
head sized and configured to cut laterally into the earthen
formation.
Inventors: |
Savage; James M.; (Ragley,
LA) |
Assignee: |
NITRO DRILL TECHNOLOGIES,
LLC
|
Family ID: |
45810950 |
Appl. No.: |
13/226478 |
Filed: |
September 6, 2011 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61402799 |
Sep 7, 2010 |
|
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|
61402803 |
Sep 7, 2010 |
|
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Current U.S.
Class: |
175/61 ;
175/77 |
Current CPC
Class: |
E21B 17/017 20130101;
E21B 7/068 20130101; E21B 7/061 20130101; E21B 17/20 20130101 |
Class at
Publication: |
175/61 ;
175/77 |
International
Class: |
E21B 7/04 20060101
E21B007/04 |
Claims
1. An apparatus for cutting laterally into an earthen formation
from a wellbore comprising: a flexible tubular member formed from a
series of interconnectable drive segments, wherein the
interconnectable drive segments collectively form at least one
tubular member inner passageway, the flexible tubular member being
sized and configurable such that an attached cutting head assembly,
the at least one tubular member inner passageway, and a fluid
pumping source may be in fluid communication, and wherein a first
flexible tubular member end portion is sized and configured to be
attachable to a rotation means and a second flexible tubular member
end portion operatively coupled to the cutting head assembly such
that torque applied to the first flexible tubular member end
portion by the rotational source may be translated to the cutting
head assembly.
2. The apparatus of claim 1 wherein the cutting head assembly
comprises at least one cutting surface sized and configured to
mechanically cut into the earthen formation.
3. The apparatus of claim 1 wherein the cutting head assembly
comprises a nozzle having at least one orifice for the ejection of
fluid, gas or combination thereof positioned on or near the cutting
head assembly and capable of being in fluid communication with the
fluid pumping source.
4. The apparatus of claim 1, further comprising sorts of flutes or
grooves on the drive segments that can facilitate the removal of
cuttings.
5. The apparatus of claim 1, wherein the cutting head assembly
further comprises a centering member sized and configured to retain
the cutting head assembly substantially longitudinal about the axis
of a substantially horizontal wellbore created by the apparatus
when engaged in cutting laterally into the earthen formation and
wherein the cuttings from the earthen formation may travel past the
centralizing mechanism toward the wellbore.
6. The apparatus of claim 1 further comprising one or more
secondary tubular member disposed within the at least one flexible
tubular member inner passageway and capable of providing a
substantially leak-proof fluid conduit between the pumping source
and the cutting head assembly.
7. The apparatus of claim 6 further comprising flexible sealing
material positioned between the interconnectable drive segments for
the creation of a substantially leak-proof fluid passageway within
the at least one flexible tubular member inner passageway so as to
establish a fluid conduit between the pumping source and the
cutting head assembly.
8. The apparatus of claim 6, wherein the substantially leak-proof
fluid conduit is created by selected from the group consisting of
an elastomeric material, hose, braided-hose, flexible tubing,
KEVLAR.RTM., tubing, convoluted tubing, interlocking hose,
semi-rigid tubing, and combinations thereof.
9. The apparatus of claim 1 comprising two or more interconnectable
drive segments each having a base plane situated generally
perpendicular to an axis of rotation and having at least two male
teeth generally positioned on at least one sides of the base plan
and having at least two female sockets generally positioned on the
opposing side of the base plane, such that the at least two male
teeth on one side of the base plane of an interconnectable drive
segment can mesh into at least two mating female sockets on an
adjacent interconnectable drive segment thereby permitting the
articulation and transference of torque of the flexible tubular
shaft member around a radius.
10. The apparatus of claim 9 comprising interconnectable drive
segments having both male teeth and female sockets on each side of
the base plane.
11. The apparatus of claim 1 comprising two or more
interconnectable drive segments having an outer profile that is
generally cylindrical or barrel-shaped.
12. The apparatus of claim 1 comprising two or more
interconnectable drive segments having a base plane situated
generally perpendicular to an axis of rotation and having at least
one male drive tooth generally situated on one side of the base
plan and at least one mating female socket on an opposing side
wherein two or more lines bounding an edge of the male tooth do not
meet at a single point on one side of the base plane, even if said
lines bounding the edge(s) are extended.
13. The apparatus of claim 3 being capable of emitting fluid from
the at least one orifice on the nozzle providing at least one of
the following benefits: keeping the cutting head clean, keeping the
cutting head cool, emitting fluid to better dispose the formation
to be cut, emitting chemicals for treating the formation, or
emitting fluid to provide a medium for carrying formation cuttings
back toward the wellbore.
14. The apparatus of claim 1 wherein the flexible tubular member is
deployed within a wellbore by means selected from the group
consisting of production tubing, wireline, slickline unit, coiled
tubing, and combinations thereof.
15. The apparatus of claim 1 further comprising a rotational source
selected from the group consisting of a fluid-driven motor, an
electrical motor, or combinations thereof.
16. The apparatus of claim 1 further comprising a tensioning means
to hold the interconnectable drive segments together.
17. The apparatus of claim 16, wherein the tensioning system is
selected from the group comprising: the placement of an elastomeric
material between the interconnectable drive segments so as to hold
them in tension, the placement of a preload on a hose running
through an inner tubular passageway of the flexible tubular shaft
member, the placement of a preload on a cable(s) running through an
inner passageway of the flexible tubular shaft member, the
incorporation of a spring situated above the interconnectable drive
segments wherein the spring pushes the interconnectable drive
segments together, directly, pulls the interconnectable drive
segments together by pulling tension on a hose, wire or cable(s)
running through an inner passageway of the interconnectable drive
segments, and combinations thereof.
18. The apparatus of claim 1 further comprising a whipstock to
guide the interconnectable drive segments.
19. The apparatus of claim 18, wherein the whipstock comprises a
passageway through which formation cuttings can pass from the
cutting head assembly to a location below the whipstock.
20. The apparatus of claim 1 further comprising a sealing apparatus
used in conjunction with a wireline unit allowing fluid
communication with surface pumping equipment, said sealing
apparatus providing a sealing mechanism between a fluid motor and a
tubular extending to the surface through which fluid can be pumped,
said sealing mechanism diverting flow from the surface pumping
equipment through said tubular and into the fluid motor causing
rotation of the motor and attached interconnectable drive segments
and ultimately cutting head assembly, said motor connected to a
wireline whereby the flexible tubular member may be lowered so as
to create a lateral borehole in the earthen formation.
21. A method for cutting laterally into an earthen formation from a
wellbore comprising: guiding a downhole tool assembly comprising a
series of interconnectable drive segments, defining at least one
inner passageway, through a channel defined by a guide assembly and
positioning the downhole tool assembly so that the downhole tool
assembly contacts a portion of the earthen formation to be
laterally cut, wherein the downhole tool assembly is coupled to a
conduit, such that the conduit and downhole tool assembly are in
fluid communication; pumping one or more fluids through the conduit
and into the downhole tool assembly; rotating a cutting head of the
downhole assembly; and cutting a borehole into the earthen
formation with the cutting head in a direction lateral to the
wellbore.
22. The method of claim 21, wherein the downhole tool assembly is
operatively connected to a rotational source and the rotational
source is coupled to a conduit, such that the conduit, rotational
source, and downhole tool assembly are in fluid communication;
activating the rotational source, wherein a torque is applied to
the interconnected drive segments forming a flexible tubular
member; and translating the torque to a cutting head of the
downhole tool assembly, wherein the torque causes the cutting head
to rotate.
23. The method of claim 22, wherein the rotational source is
activated by the fluid flow through the conduit into the rotational
source.
24. The method of claim 21, wherein the interconnected drive
segments collectively define a tubular member inner passageway, and
the downhole tool assembly further comprises a nozzle defining one
or more openings in fluid communication with at least a portion of
a secondary tubular member disposed within the tubular member fluid
passageway, wherein the method further comprises pumping one or
more fluids through the secondary tubular member; and emitting the
pumped fluid from the nozzle openings, whereby the fluid contacts
the cutting head.
25. The method of claim 24, wherein the nozzle openings comprise
one or more orifices selected from the group consisting of a nozzle
orifice at the center of the cutting head, a nozzle orifice(s) that
are situated about the radius of the axis of rotation of the nozzle
head, a rotating nozzle, a pulsing nozzle, a nozzle that creates a
swirling pattern in its discharge flow, a nozzle designed to
produce cavitation, and combinations thereof.
26. The method of claim 21, wherein fluid is pumped through a fluid
motor so as to rotate the flexible tubular member and the cutting
head so as to cut earthen formation.
27. The method of claim 21, further comprising forming a lateral
borehole through a pre-existing hole created thru the casing; said
hole created by one or more of the following methods: milling out
the section of casing, abrasively cutting the casing, punching
through the casing, cutting a hole in the casing, or using chemical
to erode the wellbore casing.
28. The method of claim 21, further comprising forming a hole
through a wellbore casing and further lowering said tools under
rotation so as to cut through any adjacent cement and into the
earthen formation.
29. The method of claim 21, further comprising pumping fluid to a
location beneath the downhole tool assembly and at a sufficient
velocity so as either suspend formation cuttings within the
wellbore or to lift the cuttings to the surface.
30. The method of claim 21, further comprising a means to vibrate
at least a portion of the downhole assembly so as to mitigate the
cutting head and/or flexible tubular member assembly from becoming
stuck in the borehole.
31. The method of claim 21, wherein the wellbore is an open hole
wellbore and a borehole is formed into the earthen formation in a
direction lateral to the open hole wellbore.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] The present application claims priority to U.S. Provisional
Application No. 61/402,799 and U.S. Provisional Application No.
61/402,803, both filed on Sep. 7, 2010.
FIELD
[0002] The present invention relates to an apparatus and method for
cutting wellbore components and/or earthen formation surrounding
the wellbore. More specifically, the invention relates to an
apparatus and method for mechanically cutting earthen formation
surrounding the wellbore, and optionally, casing and/or cement
disposed in the wellbore, through the use of a rotatable,
mechanical cutting head assembly.
BACKGROUND
[0003] A multitude of wells have been drilled into earth strata for
the extraction of oil, gas, and other material there from. In many
cases, such wells are found to be initially unproductive, or may
decrease in productivity over time, even though it is believed that
the surrounding strata still contains extractable oil, gas, water
or other material. Such wells are typically vertically extending
holes including a casing usually of a mild steel pipe having an
inner diameter of from just a few inches to over eight inches used
for the transportation of the oil, gas, or other material upwardly
to the earth's surface. In other instances, the wellbore may be
uncased at the zone of interest, commonly referred to as an
"openhole" completion.
[0004] In an attempt to obtain production from unproductive wells
and increase production in under producing wells, methods and
devices for forming a hole in a well casing, if present, and
forming a lateral passage there from into the surrounding earth
strata are known. For example, a hole in cased wells can be
produced by punching a hole in the casing, abrasively cutting a
hole in the casing, milling a hole in the casing wall or milling
out a vertical section of casing. While more or less efficacious,
such methods are generally familiar to those in the art. In
openhole wells, the steps to form a hole in the casing are not
required, but the methods for forming a lateral passage into the
surrounding strata may be virtually identical to those used on
cased well.
[0005] Under both the cased and uncased well scenarios, a type of
whipstock is typically incorporated to direct the cutting head out
of the wellbore and into the formation. The whipstock may be set on
the end of production tubing. Because of the time and economic
benefits, often the cutting tools are run on the end of coiled
tubing. In at least one known conventional horizontal drilling
method using coiled tubing, the cutting tool completes its
transition to the horizontal direction over a radius of at least
several feet and some methods require a radius of over 100 feet.
The size of the radius stems primarily from the length and diameter
of the cutting tools and the rigidity of the toolstring that must
transition around the radius. Other known methods for creating
horizontal drainage tunnels are able to transition a much tighter
radius (e.g. within 4.5'' casing) by not attempting to pass
relatively long and/or large diameter tools (e.g. a mud motor)
outside of the wellbore. Instead most such methods utilize a
flexible jetting hose with a specialized and relatively small
nozzle head (e.g., less than a few inches long). Such methods may
be efficacious, but typically suffer from a common problem that
that they do not and/or cannot provide adequate torque to
satisfactorily power a mechanical cutting means capable of cutting
harder formation. Accordingly, these methods may be limited only to
very soft formations.
[0006] Furthermore, most known methods and apparatus have also
generally been unable to provide technically or commercially
satisfactory results because of an accumulation of cuttings in the
wellbore. Many known apparatus utilizing a form of jetting nozzles
have been found unable to produce a satisfactorily large hole in
the strata and, even when directed at soft strata, have been found
to hang-up when trying to advance the nozzle into the
formation.
[0007] In addition to the aforementioned, cuttings created from the
lateral drilling process or materials in the wellbore can also be
problematic. If the rat-hole of the wellbore (the portion beneath
the work area) is not deep enough to accommodate these materials,
the materials can fill the wellbore up to or above the elevation of
the whipstock. This in turn, can effectively preclude the removal
of cuttings from the lateral borehole being drilled as the cutting
have nowhere to fall and hence cause a stop in forward cutting of
the lateral borehole. Additionally, cuttings in the wellbore can
fill-up so that repositioning of the whipstock, such as to a new
zone of interest, movement of the whipstock cannot be done.
[0008] In view of the above, it would be desirable to have a
cutting tool capable of being run on a wireline unit, on coil
tubing or on jointed tubing or rod, the tool being capable of being
run in a wellbore and capable of transitioning in a radius of less
than about 36 inches to a substantially horizontal orientation,
wherein the cutting tool is provided with sufficient torque to cut
even hard formation, like dolomite. It would further be desirable
to have a cutting system capable of rotating under the power of
fluid and wherein the fluid may be emitted from the cutting tool to
provide assistance in the removal of cuttings, to clean the cutting
faces and/or to cool the cutting tool.
SUMMARY
[0009] An embodiment of the present invention is an apparatus for
cutting laterally into an earthen formation from a wellbore that
includes a flexible tubular member formed from a series of
interconnectable drive segments, wherein the interconnectable drive
segments collectively form at least one tubular member inner
passageway. The flexible tubular member is sized and configurable
such that an attached cutting head assembly, the tubular member
inner passageway, and a fluid pumping source may be in fluid
communication. Wherein a first flexible tubular member end portion
is sized and configured to be attachable to a rotation means and a
second flexible tubular member end portion operatively coupled to
the cutting head assembly such that torque applied to the first
flexible tubular member end portion by the rotational source may be
translated to the cutting head assembly.
[0010] The cutting head assembly can have at least one cutting
surface sized and be configured to mechanically cut into the
earthen formation. The cutting head assembly can have at least one
orifice for the ejection of fluid, gas or combination thereof
positioned on or near the cutting head assembly and is capable of
being in fluid communication with the fluid pumping source. The
cutting head assembly can also have a centering member sized and
configured to retain the cutting head assembly substantially
longitudinal about the axis of a substantially horizontal wellbore
created by the apparatus when engaged in cutting laterally into the
earthen formation and the cuttings from the earthen formation may
travel past the centralizing mechanism toward the wellbore.
[0011] There can be flutes or grooves on the drive segments that
can facilitate the removal of cuttings. There can be one or more
secondary tubular member disposed within the flexible tubular
member inner passageway and capable of providing a substantially
leak-proof fluid conduit between the pumping source and the cutting
head assembly. There can be a flexible sealing material positioned
between the interconnectable drive segments for the creation of a
substantially leak-proof fluid passageway within the flexible
tubular member inner passageway so as to establish a fluid conduit
between the pumping source and the cutting head assembly. The
substantially leak-proof fluid conduit can be created by utilizing
an elastomeric material, hose, braided-hose, flexible tubing,
KEVLAR.RTM., tubing, convoluted tubing, interlocking hose or
semi-rigid tubing, or combinations thereof.
[0012] The apparatus can include two or more interconnectable drive
segments each having a base plane situated generally perpendicular
to an axis of rotation and having at least two male teeth generally
positioned on at least one sides of the base plan and having at
least two female sockets generally positioned on the opposing side
of the base plane, such that the at least two male teeth on one
side of the base plane of an interconnectable drive segment can
mesh into at least two mating female sockets on an adjacent
interconnectable drive segment thereby permitting the articulation
and transference of torque of the flexible tubular shaft member
around a radius. In an embodiment the interconnectable drive
segments can have both male teeth and female sockets on each side
of the base plane.
[0013] The two or more interconnectable drive segments can have an
outer profile that is generally cylindrical or barrel-shaped. In an
embodiment the two or more interconnectable drive segments can have
a base plane situated generally perpendicular to an axis of
rotation and have at least one male drive tooth generally situated
on one side of the base plan and at least one mating female socket
on an opposing side wherein two or more lines bounding an edge of
the male tooth do not meet at a single point on one side of the
base plane, even if said lines bounding the edge(s) are
extended.
[0014] In an embodiment the apparatus is capable of emitting fluid
from the orifice on the nozzle providing benefits such as keeping
the cutting head clean, keeping the cutting head cool, emitting
fluid to better dispose the formation to be cut, emitting chemicals
for treating the formation, or emitting fluid to provide a medium
for carrying formation cuttings back toward the wellbore. The
flexible tubular member can be deployed within a wellbore by means
of production tubing, wireline, slickline unit, coiled tubing, and
combinations thereof.
[0015] The apparatus can include a rotational source selected from
a fluid-driven motor, an electrical motor, or some combination
thereof. The apparatus can include a tensioning means to hold the
interconnectable drive segments together. The tensioning system can
be the placement of an elastomeric material between the
interconnectable drive segments so as to hold them in tension, the
placement of a preload on a hose running through an inner tubular
passageway of the flexible tubular shaft member, the placement of a
preload on a cable(s) running through an inner passageway of the
flexible tubular shaft member, the incorporation of a spring
situated above the interconnectable drive segments wherein the
spring pushes the interconnectable drive segments together,
directly, pulls the interconnectable drive segments together by
pulling tension on a hose, wire or cable(s) running through an
inner passageway of the interconnectable drive segments, and
combinations thereof.
[0016] The apparatus can include a whipstock to guide the
interconnectable drive segments. The whipstock can include a
passageway through which formation cuttings can pass from the
cutting head assembly to a location below the whipstock. The
apparatus can include a sealing apparatus used in conjunction with
a wireline unit allowing fluid communication with surface pumping
equipment, said sealing apparatus providing a sealing mechanism
between a fluid motor and a tubular extending to the surface
through which fluid can be pumped. The sealing mechanism diverting
flow from the surface pumping equipment through said tubular and
into the fluid motor causing rotation of the motor and attached
interconnectable drive segments and ultimately cutting head
assembly, said motor connected to a wireline whereby the flexible
tubular member may be lowered so as to create a lateral borehole in
the earthen formation.
[0017] An embodiment of the present invention is an embodiment is a
method for cutting laterally into an earthen formation from a
wellbore utilizing the apparatus described above.
[0018] An embodiment of the present invention is an embodiment is a
method for cutting laterally into an earthen formation from a
wellbore by guiding a downhole tool assembly having a series of
interconnectable drive segments, defining at least one inner
passageway, through a channel defined by a guide assembly and
positioning the downhole tool assembly so that the downhole tool
assembly contacts a portion of the earthen formation to be
laterally cut. The downhole tool assembly is coupled to a conduit,
such that the conduit and downhole tool assembly are in fluid
communication. The method further includes pumping one or more
fluids through the conduit and into the downhole tool assembly,
rotating a cutting head of the downhole assembly and cutting a
borehole into the earthen formation with the cutting head in a
direction lateral to the wellbore.
[0019] In the method the downhole tool assembly can be operatively
connected to a rotational source and the rotational source is
coupled to a conduit, such that the conduit, rotational source, and
downhole tool assembly are in fluid communication. The method
further can include activating the rotational source, wherein a
torque is applied to the interconnected drive segments forming a
flexible tubular member and translating the torque to a cutting
head of the downhole tool assembly, wherein the torque causes the
cutting head to rotate.
[0020] The rotational source can be activated by the fluid flow
through the conduit into the rotational source. The interconnected
drive segments collectively define a tubular member inner
passageway, and the downhole tool assembly further includes a
nozzle defining one or more openings in fluid communication with at
least a portion of a secondary tubular member disposed within the
tubular member fluid passageway, wherein the method further
includes pumping one or more fluids through the secondary tubular
member and emitting the pumped fluid from the nozzle openings,
whereby the fluid contacts the cutting head.
BRIEF DESCRIPTION OF DRAWINGS
[0021] FIG. 1 illustrates a cross-sectional view of an openhole
completed wellbore containing a whipstock prior to the use of the
whipstock in conjunction with an embodiment of the present
invention.
[0022] FIG. 2 illustrates a cross-sectional view of a cased
wellbore containing a whipstock, wherein an embodiment of the
present invention is deployed in the wellbore and is disposed to
cut a lateral borehole thru a predefined hole in wellbore
casing.
[0023] FIG. 3 illustrates a cross-sectional view of a cased
wellbore containing a whipstock, wherein an embodiment of the
present invention is deployed in the wellbore, guided through a
guide channel in the whipstock, and has created a lateral borehole
through the casing and cement and is proceeding into the earthen
formation of interest.
[0024] FIG. 4A illustrates a plan view of an interconnected drive
segment consistent with an embodiment of the present invention and
consisting of male teeth or pins and mating female sockets (not
shown) on opposing sides of the drive segment. FIG. 4B illustrates
a cross-sectional view of generally cylindrical interconnected
drive segments of FIG. 4A consistent with an embodiment of the
present invention and showing the male teeth and mating female
sockets.
[0025] FIG. 4C illustrates a cross-sectional view of a series of
interconnected drive segments positioned around the radius of
whipstock and consisting of the configurations depicted in FIGS. 4A
and 4B with optional secondary tubular member, in this case a hose,
positioned inside one of the inner passageway of the drive segments
and consistent with an embodiment of the present invention.
[0026] FIG. 5A illustrates plan view of an interconnected drive
segment consistent with an embodiment of the present invention and,
in this case, consisting of multiple male teeth and female sockets
on each side of the drive segment (opposing side not shown). FIG.
5B illustrates a side view of a drive segment of FIG. 5A showing
both male teeth and female sockets on each side of the drive
segment and the overall barrel profile of the drive segment
consistent with an embodiment of the present invention. FIG. 5C
illustrates a side view of a series of interconnected drive
segments of FIGS. 5A and 5B articulating around a radius, shown
with optional secondary tubular member (in this case being
corrugated tubing) consistent with an embodiment of the present
invention.
[0027] FIG. 6A illustrates a frontal view of a rotatable cutting
head assembly, showing the cutting blades and a nozzle positioned
in a recess of the cutting head; fluid exiting the orifices on the
nozzle is used to keep the cutting blades clean and cool. FIG. 6B
illustrates a cross sectional view of the cutting head assembly
connected to a series of drive segments used for the transmission
of torque and which circumscribe a hose used for the transmission
of fluid to the cutting head assembly.
[0028] FIG. 7 illustrates a frontal view of a rotatable cutting
head assembly, showing the cutting blades, in this case diamond
inserts and an exit orifice positioned in a recess of the cutting
head; fluid exiting the orifices is used to keep the cutting blades
clean and cool. FIG. 7B illustrates a cross sectional view of the
cutting head assembly connected to a series of drive segments used
for the transmission of torque; in this case, the drive segments
have been used with an optional tensioning cable for holding the
drive segments together while fluid communication in the system is
established by elastomeric seals positioned between the drive
segments.
[0029] FIG. 8 illustrates an embodiment of the present invention
situated downhole and operated by a coiled tubing unit, wherein the
coiled tubing unit is pumping fluid to drive a fluid motor used to
rotate the flexible tubular shaft member consistent with an
embodiment of the present invention.
[0030] FIG. 9 illustrates an embodiment of the present invention
operated by means of a wireline unit in conjunction with pumping
equipment, whereby fluid pumped into production tubing is diverted
by a sealing mechanism into a downhole fluid motor and,
subsequently, traverses the flexible tubular shaft member and exits
at the cutting head.
[0031] FIG. 10 illustrates an embodiment of the present invention
wherein a coiled tubing unit and downhole motor are used to operate
the flexible tubular shaft member while an air compressor is used
to remove cutting from below the whipstock, by circulating them out
of the wellbore, consistent with an embodiment of the present
invention.
DETAILED DESCRIPTION
[0032] In an aspect of the current invention, an apparatus for
cutting laterally into an earthen formation from a wellbore is
provided. As used herein, the term "lateral" or "laterally" refers
to a borehole deviating from the wellbore and/or a direction
deviating from the orientation of the longitudinal axis of the
wellbore. The orientation of the longitudinal axis of the wellbore
in at least one embodiment is vertical, wherein such a wellbore
will be referred to as a vertical wellbore or substantially
vertical wellbore. However, it should be understood that the
orientation of the longitudinal axis of the wellbore may vary as
the depth of the well increases, and/or specific formations are
targeted. As used herein, the term "strata" refers to the
subterranean formation also referred to as "earthen formation." The
term "earthen formation of interest" refers to the portion of
earthen formation chosen by the operator for lateral drilling. Such
earthen formation is typically chosen due to the properties of the
formation relating to hydrocarbons.
[0033] The present invention relates to an apparatus, system, and
method for cutting laterally into an earthen formation. Optionally,
the apparatus may be used for cutting laterally into cement
disposed within the wellbore. Optionally, the apparatus may be used
for cutting laterally into the casing and cement disposed in the
wellbore. Using the apparatus to cut laterally through the casing,
cement, and earthen formation is advantageous in that the number of
trips of downhole can be reduced significantly. The apparatus may
be used in cased wellbores or openhole wellbores. Optionally, the
apparatus may be used in wellbores wherein the one or more hole may
have already been created through the casing and/or cement.
[0034] Generally, the apparatus will be run to a depth in the
wellbore suitable for the retrieval of hydrocarbons and/or other
desired materials. The location of the lateral boreholes will be
operator specific and may vary based on the needs and goals of the
operator. The location of the lateral boreholes may also be
determined by the location of the wellbore and the environmental
properties of the surrounding strata.
[0035] In at least one embodiment, the apparatus is a downhole tool
assembly including a cutting head assembly and a flexible tubular
shaft member attached to a means of rotation. When in use in a
wellbore, the downhole tool assembly can be connected to a spool
assembly including a conduit that can be used to lower the downhole
tool assembly inside the wellbore. For example, the downhole tool
assembly may be connected to a fluid motor and coil tubing that can
be lowered into a wellbore and operated so as to cause rotation of
the apparatus. In another embodiment, the downhole tool assembly is
coupled to jointed tubing or pipe and a pumping source, whereby the
downhole tool assembly is in fluid communication with pumping
equipment by virtue of the jointed tubing string. In another
embodiment, the downhole tool assembly is operatively connected to
pumping equipment and a slickline or e-line unit, which together
allow for placement, operation and/or retrieval of the downhole
tool assembly. In an embodiment, the downhole tool assembly is
operatively connected to pumping equipment and jointed rod which
together can be used to control the operation of the downhole tool
assembly.
[0036] One end portion, or first end portion, of a conduit or
tubing run into the wellbore can be coupled to a fluid pumping
source. Optionally, the second end portion of the conduit is
coupled to the first end portion of the flexible tubular shaft
member such that the fluid pumping source is in fluid communication
with the flexible tubular shaft member. The fluid pumping source
can be any conventional fluid pump capable of providing fluid
pressures to the downhole tool assembly such that the downhole tool
assembly is able to emit fluid from or near the cutting head.
Optionally, the fluid may be emitted at a pressure from about 100
to 5000 psi. Optionally, the fluid may be pumped at a pressure from
about 5,000 to about 15,000 psi. The flow rate of the fluid may
range from about 4 to about 12 gallons per minute (gpm). In another
embodiment, the operating flow ranges from about 10 to about 20
gpm. In a further embodiment, the operating flow ranges from about
15 to about 35 gpm. Nonlimiting examples of the fluid pumped from
the fluid pumping source include nitrogen, air, foam, diesel,
hydrochloric acid, water, formation brine, biocides, wettability
agents, surfactants, and the like.
[0037] In an embodiment, the second end portion of the conduit is
coupled to a rotational source in an embodiment of the present
invention. In at least one embodiment, the rotational source can be
a motor sized and configured to be run into the wellbore and
capable of operating at the depth and conditions desired by the
well operator. A nonlimiting example of such a motor is a mud
motor, such as the 175RS640 manufactured by Roper Pumps. The motor
can be operatively coupled to a first end portion of the flexible
tubular shaft member, discussed further below. The motor can be
coupled to the first end portion of the flexible tubular shaft
member such that a torque generated by the motor is applied to the
flexible tubular shaft member, thereby causing the flexible tubular
shaft member to rotate consistent with the torque applied by the
motor. The motor may be further configured such that the fluid
pumping source may be in fluid communication with the first end
portion of the flexible tubular shaft member, discussed more fully
below. In another embodiment, the rotation source of the downhole
toolstring may be a surfaced-based rotational source, such as a
power swivel, which is used to rotate the downhole toolstring by
virtue of rod or tubing connected to the downhole toolstring. In
yet another embodiment, the rotational source connected to the
downhole tool may be a DC motor, such as operated by an e-line
unit.
[0038] Optionally, the downhole tools may include a vibration
source. The vibration source may be sized and configured to impart
vibrations to shake the cutting head assembly and/or flexible
tubular shaft member to facilitate the removal of cuttings and
allows the cutting head assembly to more effectively penetrate into
and be retrieved from the earthen formation. Optionally, the
vibration source may be attached to the flexible tubular shaft
member or cutting head assembly. Optionally, the vibration source
may be derived directly from the rotational source. The rotational
source may further include a transmission, wherein the torque or
revolutions per minute (rpms) of the rotational source may be
adjustable.
[0039] As discussed above, the downhole tool assembly includes a
flexible tubular shaft member in at least one embodiment of the
present invention. The flexible tubular shaft member includes a
first end portion discussed above and a second end portion wherein
the second end portion can be coupled to the cutting head assembly.
The flexible tubular shaft member may define at least one hollow
tubular cavity, which may be referred to as a tubular member inner
passageway. In at least one embodiment, a secondary tubular member
defining an interior passageway (e.g. a hose) may be disposed
within a tubular member inner passageway and further coupled to and
in fluid communication with the cutting head assembly. In an
embodiment used with a sealing mechanism, described in more detail
below, the first end portion of the flexible tubular shaft member
allows for internal to external porting whereby fluid can enter
into the inside of the flexible tubular shaft member and optional
secondary tubular member thereby allowing it to flow to the cutting
head assembly. The first end portion of the flexible tubular shaft
member may be operatively connected to a motor, whereby torque
applied to the flexible tubular shaft member by the actuation of
the motor may be translated to the cutting head assembly coupled to
the second end portion of the flexible tubular shaft member. The
cutting head assembly may rotate from the translated torque thereby
cutting the earthen formation.
[0040] Optionally, the flexible tubular shaft member includes one
or more centralizing members that can enable it to be centralized
with respect to the wellbore and/or lateral borehole. Nonlimiting
examples of centralizing members include radially oriented pins,
brushes or springs.
[0041] In at least one embodiment, the downhole tool assembly may
include an upper cross-over member connected to the first end of
the flexible tubular shaft member. In at least one embodiment, the
upper cross-over member has at least one passageway allowing for it
to transmit fluid to the inside of the flexible tubular shaft
member. In at least one embodiment, the upper cross-over member is
coupled to a motor on the one side and to the flexible tubular
shaft member on the other side, so as to allow for the transmission
of torque to the flexible tubular shaft member. In at least one
embodiment, the upper cross-over member can both transmit torque,
such as by threading or splines, and allow for the transmission of
fluid through a passageway. In at least one embodiment, the upper
cross-over member can be used to help tension a tensioning system,
described in more detail below, used to keep the drive segments
engaged with one another. In at least one embodiment, the upper
cross-over member utilizes a nut and/or spring to keep the flexible
tubular shaft member's components engaged with one another. In at
least one embodiment, the upper cross-over member can transmit
torque, allow for the transmission of fluid, and be used to put
tension on a tensioning system running within the flexible tubular
shaft member.
[0042] In an embodiment, the flexible tubular shaft member
comprises a series of drive segments capable of transitioning
through and transmitting torque around a radius of less than 36
inches. The series of drive segments can be sized and configured
such that each drive segment engages at least one other drive
segment whereby torque is transmitted from drive segment to drive
segment. In an embodiment, the drive segments transmit torque
through one or more pins or teeth on a side of each drive segment
and a respective mating socket on an adjacent drive segment. In one
embodiment, each drive segment is configured with both a male tooth
and a female socket on each side of the drive segment. In either of
the aforementioned arrangements, each drive segment is configured
with both male and female parts. In at least one embodiment, there
are at least two male teeth and two female sockets on each side of
the drive segments. In an embodiment there are four teeth and four
sockets on each side of the drive segments. Each drive segment has
at least one opening, collectively defining at least one inner
tubular passageway. Optionally, the drive segments can be connected
by one or more hoses or cables used to as a tensioning system to
hold the drive segments together, as more fully discussed below.
The flexible tubular shaft member comprising the drive segments are
further sized and configured to transmit torque applied from the
rotational source to the cutting head assembly such that the
cutting head, discussed below, is supplied with sufficient torque
to cut the intended earthen formation. Optionally, one or more
drive segments defines at least one groove, spiral, or flute,
wherein the groove, spiral, or flute may allow cuttings and/or
fluid to be carried from the cutting head past the drive segment
and toward the wellbore.
[0043] As noted above, each drive segment may define one or more
drive segment openings, as a whole forming at least one tubular
member inner passageway. Optionally, a secondary tubular member,
such as flexible hose or tubing, may be disposed within the at
least one tubular member inner passageway. Nonlimiting examples of
the secondary tubular member are hose or braided hose, KEVLAR.RTM.,
convoluted tubing, interlocking hose, semi-rigid tubing, and the
like. The secondary tubular member is in fluid communication with
the fluid pumping source and the cutting head assembly. In certain
embodiments, the secondary tubular member sits in the center of the
series of drive segments. Optionally, the secondary tubular member
is disposed within the flexible tubular shaft member and is
connected to and in fluid communication with the cutting head
assembly. The secondary tubular member within the flexible tubular
shaft member can be fed, or transitioned, through a whipstock and
into the earthen formation with the flexible tubular shaft member.
In certain embodiments, the secondary tubular member can be
integral to or can circumscribe a tensioning system, discussed in
more detail below. In an embodiment, the circumscribed secondary
tubular member, the series of drive segments, the tensioning
system, described below, and the cutting head are rotated
simultaneously.
[0044] In certain embodiments wherein the flexible tubular shaft
member can be used without a secondary tubular member, seals
positioned at least in part between the interconnected drive
segments can be used to produce fluid communication between the
opposite ends of the flexible tubular shaft member. That is, in
this fashion fluid communication can be established between the
first end of the flexible tubular shaft member end and the second
end of the flexible tubular shaft member end, without usage of a
hose or similar continuous conduit. In this embodiment, a sealing
mechanism, such as elastomeric seals bonded to adjacent
interconnected drive segments, could allow for fluid to be pumped
through the passageway within the flexible tubular shaft
member.
[0045] In at least one embodiment, the drive segments are held in
contact with one another by a tensioning system. The tensioning
system may be comprised of one or more tensioning lines running
from and affixed to the cutting head assembly on the one end and to
an upper cross-over member, discussed below, on the other.
Optionally, the tensioning line may be comprised of one or more
hose(s) or cables(s). Non-limiting methods to put tension on the
tensioning lines include affixing one end to the cutting head
assembly, such as by a crimp or threaded connection and employing a
tensioning mechanism on the other end. Optionally, the other end of
the tensioning line may terminate in an upper cross over member,
discussed below, wherein a tensioning mechanism, such as a crimp
and adjustable nut, may be employed to set a predetermined amount
tension on the tensioning line. Optionally, the tensioning line may
connected to a spring, which can be preloaded and which may allow
for varying amounts of tension to be placed on the tensioning line.
Again, applying tension to the tensioning line will cause the drive
segments to be held together since the opposing ends of the
tensioning lines terminate beyond the opposing ends of the drive
segments. Optionally, the tensioning line(s) may be situated around
the axis of rotation of each drive segment (for example, at zero,
120 and 240 degrees) or it may be situated along the axis of
rotation. In another embodiment, the tensioning line may lie inside
the second tubular member situated inside the series of drive
segments. In an embodiment, the tensioning lines may be situated
about the exterior of the drive segments. An alternate embodiment
also employs a tensioning line(s) affixed to the cutting head
assembly on the one end and terminating at the upper cross over
member on the other. In this embodiment, a spring in the upper
cross over member may be used to push on the drive segments
themselves thereby holding them together and wherein the pushing
force terminates in the cutting head assembly by virtue of the
tensioning line also terminating there. These and similar
tensioning mechanism are intended to be within the scope of this
application.
[0046] Embodiments of the present invention may include an upper
cross over member, which may serve multiple purposes. As described
above, it may serve as part of the tensioning system used to keep
the drive segments of the flexible tubular shaft member engaged
with one another. Additionally, the upper cross over member may
allow for fluid communication to be established with the flexible
tubular shaft member, whether by merely conveying fluid exiting a
downhole motor into the flexible tubular shaft member or by
diverting flow from the upset tubing by virtue of a sealing
mechanism. Finally, the upper cross over member may provide a means
of transferring torque from a rotational source to the flexible
tubular shaft member, such as by splines or threading.
[0047] Optionally, an exterior surface of the flexible tubular
shaft member defines one or more flutes, grooves or rifling, which
can facilitate cuttings from the borehole to flow past the flexible
tubular shaft member and up the wellbore.
[0048] In an embodiment, the cutting head assembly includes a
cutting head, wherein the cutting head can be detachably attached
to the cutting head assembly and further configured to be rotatable
and to cut laterally through casing, cement, and/or earthen
formation. Optionally, the cutting head assembly defines a cutting
head sized and configured to cut laterally through casing, cement,
and/or earthen formation. The cutting head can form one or more
recesses within the cutting head assembly to allow for some or all
of the following: to provide placement of the one or more exit
orifices for the fluid flow, to allow for efficient cutting of the
formation and/or to allow provide a passageway for cutting to be
removed from the cutting head area. The cutting head includes one
or more cutting surfaces or faces, and may be configured such that
one or more orifices may be able to eject fluid, gas or a
combination thereof near the cutting surface(s) or face(s). A
cutting face may circumscribe a portion of a rotatable nozzle, or a
plurality of cutting faces may collectively circumscribe a portion
of a rotatable nozzle. The cutting head can be continuous or
segmented (e.g. serrated). The cutting face(s) can be formed from a
material of sufficient hardness for cutting the intended earthen
formation and/or casing and cement. For example, at least a portion
of the cutting face may be formed from carbide or diamond.
[0049] The cutting head can be defined by the cutting head assembly
or fixedly attached or can be detachably attached to the cutting
head assembly. A non-limiting example of a detachable attachment is
conventional threading. In an embodiment, the cutting head is
detachably attached to the cutting head assembly, wherein the
cutting head assembly includes one or more bearings or the like to
facilitate rotation of a rotatable nozzle. The bearing may be a
mechanical bearing, such as a bronze bushing, needle bearing, or
ball bearing. Optionally, the bearing may be a fluid bearing,
wherein a fluid bearing may be created upon the pumping of a fluid
into the flexible tubular shaft member and cutting head assembly.
Optionally, the fluid and/or mechanical bearings may be used in
conjunction with seals.
[0050] The cutting head assembly defines one or more head assembly
openings in an embodiment of the present invention. The head
assembly openings can be sized and configured to permit fluid flow
there through. The cutting head assembly can include the secondary
tubular member wherein the secondary tubular member defines one or
more secondary tubular member openings sized and configured to
permit fluid flow there through into a space or chamber located
inside the rotatable nozzle, discussed below. The cutting face may
define one or more cutting face openings and the interior face
surface may define one or more cutting face openings, wherein the
cutting face opening is in fluid communication with the fluid
pumping source. The head assembly openings and/or secondary tubular
member openings can be stationary with respect to the cutting head
or can move independently of the cutting head. Fluid flow through
the head assembly openings and/or secondary tubular member openings
can be used to keep the cutting head cool, facilitate the removal
of cuttings from the borehole, and/or impart rotation of the
cutting head and/or rotatable nozzle.
[0051] Optionally, the cutting head assembly includes one or more
centering members sized and configured to retain the cutting head
assembly centrally located along the longitudinal axis of a
borehole created by the apparatus when engaged in cutting laterally
into the earthen formation. Non-limiting examples of suitable
centering members include bow springs, brushes, pins, and fluids.
The centering member also may function to allow cuttings and fluid
or gases emitted from the cutting head assembly to readily pass the
cutting head assembly and move toward the wellbore.
[0052] In an embodiment, the pressure of the fluid at the nozzle
openings is greater than about 100 psi. In another embodiment,
based on desired operator parameters and treatment protocol, the
pump pressure may be from about 5,000 psi to about 12,000 psi. The
fluid pumped through the nozzle openings may accomplish one or more
of the following: keeping the cutting head cool for cutting face
longevity, keeping the cutting faces clean for efficient formation
drilling, providing a carrying medium for transporting of cutting
toward the wellbore, ejecting chemicals used to better dispose the
formation to mechanical cutting, or to inject a chemical (e.g.
biocides, inhibitors, wettability modifiers, etc.) to treat the
formation adjacent to the lateral borehole.
[0053] As stated above, the cutting head assembly can be connected
to the second end portion of the flexible tubular shaft member,
wherein a motor can be connected to the first end portion of the
flexible tubular shaft member, such that the flexible tubular shaft
member is rotatable when the motor is engaged. In an embodiment,
the motor can be driven by the flow of fluid from the conduit,
thereby causing the flexible tubular shaft member to rotate,
wherein at least a portion of the fluid used to drive the motor is
transmitted inside the flexible tubular shaft member to the cutting
head assembly and/or nozzle. Optionally, the motor may be driven by
the flow of fluid from the conduit, thereby causing the flexible
tubular shaft member to rotate and fluid from the fluid pumping
source is pumped through the secondary tubular member to the
cutting head assembly in order to drive the rotatable nozzle and/or
cutting head.
[0054] In an embodiment, the cutting head assembly may comprise a
specialty nozzle head, such as a rotating nozzle, a pulsing nozzle,
a nozzle that creates a swirling pattern in its discharge flow, a
nozzle designed to produce cavitation. Such a nozzle maybe
necessary or desirable to more effectively clean the cutting head
to facilitate the return of cuttings back to the wellbore and/or
for marketing purposes.
[0055] In an embodiment, the fluid leaving the nozzle opening(s) on
the cutting head can generate the rotation of a rotatable nozzle,
such as through an exit orifice asymmetrically oriented with
respect to the axis of rotation of the nozzle. Optionally, a
rotatable shaft contained in a mating body may be connected to the
rotatable nozzle to provide stabilization and a consistent axis of
rotation for that nozzle. Optionally, the rotatable nozzle and/or
attached rotatable shaft may comprise a fluid bearing with the
mating body. In yet another embodiment, in the presence of flowing
fluid, the configuration of the cutting head assembly may be used
to create a swirling or pulsing pattern in the fluid flow, thereby
causing rotation of the shaft connected to the rotatable nozzle
and, thus, the connected rotatable nozzle. At least a portion of
the rotatable nozzle can be disposed within a recess formed by the
cutting head. In at least one embodiment, the rotatable nozzle is
positioned toward the center of the recess formed by the cutting
head.
[0056] In an embodiment, the cutting head assembly further includes
a rotatable nozzle defining one or more nozzle openings. At least a
portion of the rotatable nozzle can be disposed within a recess
formed by the cutting head. In at least one embodiment, the
rotatable nozzle is positioned toward the center of the recess
formed by the cutting head. The nozzle openings can be defined in a
symmetric or asymmetric pattern by the rotatable nozzle. The nozzle
openings are sized and configured such that fluid pumped from the
fluid pumping source through the conduit and flexible tubular shaft
member can be emitted from the nozzle openings with the desired
pressure selected by the operator.
[0057] As discussed above, in at least one embodiment, the cutting
head forms a recess wherein at least a portion of the rotatable
nozzle is disposed within. In an alternate embodiment, the cutting
head forms a recess wherein the rotatable nozzle is disposed
substantially within the recess. In at least one embodiment, the
fluid exiting the nozzle(s) can flow to the outside of the cutting
head.
[0058] Turning now to a system and method for cutting laterally
into an earthen formation from a wellbore, a whipstock is employed
in at least one embodiment of the present invention. As used
herein, the term "whipstock" refers to any downhole device capable
of positioning the cutting head assembly toward the earthen
formation desired for lateral cutting. The whipstock defines a
guide channel sized and configured to receive and guide the cutting
head assembly and at least a portion of the flexible tubular shaft
member through the whipstock and proximate the earthen formation of
interest. In at least one embodiment, the whipstock may guide the
cutting head assembly into a substantially horizontal direction
from a vertical wellbore such that the cutting head assembly is
disposed approximately 90 degrees from the longitudinal axis of the
wellbore. The whipstock may be disposed in the casing prior to the
running of the downhole tool assembly. Optionally, the whipstock
may be set with a coil tubing unit, on the end of production tubing
or it may be set by a wireline unit. The whipstock may have one or
more passageways running through it that allow cuttings from the
lateral borehole to fall toward the bottom of the wellbore.
[0059] Optionally, the flexible tubular shaft member may comprise a
section that is adaptable to the whipstock and forms a seal with
the whipstock. This seal may restrict the backflow of fluid and
materials up the whipstock so as to seal out any cuttings washing
back from the lateral borehole. This may be desirable in order to
prevent cuttings from clogging the guide path of the whipstock,
which could inhibit the free travel of the flexible tubular shaft
member.
[0060] Optionally, the guide assembly may have one or more
passageways extending from the guide path to below the whipstock to
allow cuttings to freely fall toward the bottom of the
wellbore.
[0061] Optionally, the bottom hole assembly may define one or more
circulation passageways traversing from above the whipstock to
below the whipstock, allowing for cleanout of the wellbore. In an
embodiment, the circulation pathway(s) may extend around the
whipstock, connecting to the upset tubing on the one end and to a
passageway through the center of a packer on the other end. In
another embodiment, they extend through the bottom of the whipstock
and also serve to as the passageway(s) used to allow cuttings to
freely fall from the guide path toward the bottom of the wellbore.
The passageway(s) may serve as a circulation path for fluid that is
circulated through the wellbore for the removal of cuttings, sand,
paraffin and other materials that may have accumulated in the
wellbore below the whipstock. For example, it may be necessary to
remove cuttings from below the whipstock in order to allow the
bottom hole assembly to be repositioned to a lower zone of interest
for the creation of another lateral. Additionally, cleaning out any
cutting in the wellbore maybe necessary for the proper operation of
the packer. In an embodiment, the circulation opening(s) extend
around the whipstock to a location at the end of the bottom hole
assembly located 5 feet below the whipstock. Pumping of fluid to
circulate the wellbore through these opening(s) may be done
initially, periodically or continuously. In an embodiment, maximum
circulation velocity is attained by retracting the downhole tool
string into the primary wellbore (e.g. into the upset tubing). In
this fashion, unobstructed flow through the circulation
passageway(s) is best created, allowing for optimal wellbore
cleanout. Cleaning out the wellbore and unloading the well may be
accomplished by pumping fluid or gas at sufficiently high pressure
and volumes through one or more of the circulation passageways.
[0062] Optionally, the system may be used with a form of
containment system for the flexible tubular shaft member. This
system may be comprised of a series of collapsible cups, stackable
centralizers or sheathing. The purpose for this system is to allow
for the efficient transference of weight from the top of the
flexible tubular shaft member to the bottom of the flexible tubular
shaft member by preventing the flexible tubular shaft member from
forming a helical path or buckling when weight is applied to it
from above.
[0063] The flexible tubular shaft member connected to the cutting
head assembly can be fed, or transitioned, through a whipstock,
such that the cutting head of the cutting head assembly is
positioned proximate the earthen formation of interest for lateral
cutting. Optionally, the cutting head is positioned proximate the
portion of the casing and/or cement proximate the earthen formation
of interest for lateral cutting. In an embodiment, the motor
coupled to the first end portion of the flexible tubular shaft
member is actuated, whereby torque is generated by the motor and
applied to the flexible tubular shaft member. The tubular member is
sized and configured such that torque applied to the first end
portion of the flexible tubular shaft member can be translated to
the cutting head assembly coupled to the second end portion of the
flexible tubular shaft member. The cutting head of the cutting head
assembly rotates from the torque applied to the cutting head
assembly and, in turn, the cutting faces contact the earthen
formation, thereby cutting into the formation. Optionally, the
cutting faces contact the casing and/or cement in wellbore
environments wherein openings have not been pre-drilled in the
casing and/or cement proximate the earthen formation of
interest.
[0064] Optionally, a nitrogen generator at the surface may be
provided and used in conjunction with a closed loop system to clean
out cuttings from the lateral borehole and/or wellbore. Optionally,
pumping pressure and volumes may be sufficiently high so as to
allow the nitrogen and cuttings to be lifted back up the wellbore;
the nitrogen may then be circulated back to the generator, and the
process may be repeated. Optionally, the nitrogen may be pumped
through a downhole motor and to the cutting head. This closed loop
nitrogen system is cost beneficial since a smaller system may be
used and the need for a fluid pump including liquids may be
eliminated.
[0065] In an embodiment, a wellbore including a whipstock set at
the desired depth in the wellbore is equipped with a fluid pumping
source and a coil tubing unit including a spool of coil tubing,
wherein a first end portion of the coil tubing is coupled to the
fluid pumping source, and the second end portion of the coil tubing
is coupled to a rotational source. The rotational source can be a
motor as discussed above. The motor in this embodiment is attached
to a downhole tool assembly including a cutting head assembly and a
flexible tubular shaft member, wherein the fluid pumping source,
coil tubing, flexible tubular shaft member, and cutting head
assembly are in fluid communication. Optionally, at least a portion
of a secondary tubular member is disposed within the flexible
tubular shaft member and the secondary tubular member is in fluid
communication with the fluid pumping source and the cutting head
assembly. The coil tubing including the coupled motor and downhole
tool assembly are lowered into the wellbore wherein at least a
portion of the downhole tool assembly contacts the whipstock and is
guided into the guide channel and positioned proximate the earthen
formation of interest.
[0066] Optionally, the second end portion of the coil tubing is
coupled to the downhole tool assembly such that the coil tubing is
in fluid communication with the downhole tool assembly. The fluid
pumping source can be coupled to the first end portion of the coil
tubing in this embodiment. The coil tubing coupled to the downhole
tool assembly is lowered into the wellbore wherein at least a
portion of the downhole tool assembly contacts the whipstock and is
guided into the guide channel and positioned proximate the earthen
formation of interest.
[0067] Having described many of the apparatus of the present
disclosure, let us further discuss the methods by which they system
may be conveyed through the pre-positioned whipstock:
[0068] In an embodiment wherein a whipstock is disposed in a
wellbore, a coiled tubing and pumping equipment can be connected to
the upper end of the flexible tubular shaft member such that fluid
pumped through the coiled tubing can drive a fluid motor and the
attached flexible tubular shaft member and cutting head assembly.
Now under rotation, the flexible tubular shaft member and attached
cutting head can be directed out of the wellbore by the
pre-positioned whipstock in order to cut a lateral borehole in the
surrounding earthen formation. Optionally, the flexible tubular
shaft member and attached cutting head may be used to through the
casing and cement, if present, and proceed to cut into the
surrounding earthen formation.
[0069] In an embodiment, wherein a whipstock is disposed in a
wellbore and is coupled to a section of upset tubing, a slickline
unit, such as familiar to those in the industry, can be used to
position and control the travel of the downhole tool assembly. In
this embodiment, a fluid driven motor is connected to the end of
the slickline string on the one end and the flexible tubular shaft
member and attached cutting head on the other end. The system can
include one or more elastomeric sealing mechanisms positioned on or
above the motor; the elastomeric mechanisms forming a relatively
complete seal with the upset tubing. The sealing mechanism diverts
fluid flowing through the upset tubing into the fluid motor,
thereby causing the motor and attached flexible tubing member to
rotate. Now rotating, the toolstring can be lowered so as to allow
the cutting head to cut into the formation
[0070] In an embodiment wherein a whipstock is disposed in a
wellbore, a wireline unit, such as familiar to those in the
industry, can be used to position and control the travel of the
downhole tool assembly. In this embodiment, an electrically driven
motor is connected to the end of the wireline on the one end and to
the flexible tubular shaft member and attached cutting head
assembly on the other. This system can include one or more
elastomeric sealing mechanisms positioned on or above the motor;
the elastomeric mechanisms forming a relatively complete seal with
optional upset tubing. The sealing mechanism diverts fluid flowing
through the upset tubing into the flexible tubular shaft member and
to the cutting head. Now rotating, the tool string can be lowered
so as to allow the cutting head to cut into the formation.
[0071] In an embodiment wherein a whipstock is disposed in the
cased wellbore and a wireline unit, such as familiar to those in
the industry, can be used to position and control the travel of the
downhole tool assembly. In this embodiment, an electrically driven
motor is connected to the end of the wireline on the one end and to
the flexible tubular shaft member and attached cutting head
assembly on the other. This system can include one or more
elastomeric sealing mechanisms positioned on or above the motor;
the elastomeric mechanisms forming a relatively complete seal with
optional upset tubing. The sealing mechanism diverts fluid flowing
through the upset tubing into the flexible tubular shaft member and
to the cutting head. Now rotating, the tool string can be lowered
so as to allow the cutting head to cut into the formation.
[0072] In an embodiment a pumping equipment and jointed tubing,
positioned by drilling or work-over equipment, can be connected to
the upper end of the flexible tubular shaft member such that fluid
pumped through the jointed tubing can drive a fluid motor and the
attached flexible tubular shaft member and cutting head assembly.
Now under rotation, the flexible tubular shaft member and attached
cutting head can be directed out of the wellbore by the
pre-positioned whipstock in order to cut a lateral borehole in the
surrounding earthen formation. Optionally, the flexible tubular
shaft member and attached cutting head may be used to through the
casing and cement, if present, and proceed to cut into the
surrounding earthen formation.
[0073] Turning now to the Figures, FIG. 1 illustrates an open hole
completed wellbore (10) containing an orienting device (12),
illustrated as a whipstock, coupled to a section of upset tubing
(14). The whipstock (12) defines a guide channel (16) sized and
configured to guide at least a portion of the flexible tubular
member (not shown) of this disclosure to a position proximate the
earthen formation of interest (20). The wellbore (10) includes a
layer of cement (22) disposed between the casing (24) and earthen
formation (20). An incline (26) is situated above the orienting
device (12) to guide tools (not shown) into the guide channel (16).
A circulation passageway (13) extending around the orienting device
(12) formed, in this case, by a tubular member (9) in fluid
communication with the upset tubing (14) at an upper entrance
opening (7) and with the wellbore (10) at a lower exit opening (8)
situated below the orienting device (12).
[0074] Looking now at FIG. 2, illustrated is a portion of the
downhole tool assembly (18) that has been guided through the guide
channel (16) defined by a whipstock (12) positioned on a packer
(28). The cutting head (46) of the downhole tool assembly (18) is
disposed in a pre-defined opening (31) in a portion of the casing
(24) proximate the cement (22) and earthen formation (20). The
first end portion (38) of the flexible tubular shaft (36) is
operatively coupled to a rotational source (40) while the second
end portion (34) of the flexible tubular shaft (36) is connected to
a cutting head assembly (32). When activated, the motor (40)
applies torque to the flexible tubular shaft (36), which has been
sized and configured to transfer the torque to the cutting head
assembly (32), thereby enabling cutting of the cement (22) and
earthen formation (20).
[0075] FIG. 3 illustrates a downhole tool assembly (18) consistent
with an embodiment of the present invention including a flexible
tubular shaft member (36) comprising a series of drive disks (42),
wherein a first end portion of the flexible tubular member (38) is
coupled to an upper cross over member (90) in turn coupled to a
motor (40) shown disposed in upset tubing (14) and the second end
portion of the flexible tubular member (34) is situated in a
lateral borehole (50) and connected to a cutting head assembly
(32). The orienting device (12) is shown with optional lower
passageway (3) in communication with the guide channel (16) and
allows for any cuttings (C) in the orienting device (12) to fall
through a passageway (29) in the packer (28) As shown, the cutting
head assembly (46) has been used to cut a hole (30) through the
casing (24) and cement (22) and is beginning to form a lateral
borehole (50) thru the earthen formation (20). Fluid (F) pumped
from a fluid pumping source (not shown) down a conduit (76) engages
the motor (40) and imparts rotation of the flexible tubular member
(36) and attached cutting head assembly (32). The fluid (F), shown
by arrows, exits the motor (40) passes thru an upper cross over
member (90) and into an optional secondary tubular member (66),
shown here as a hose. The fluid (F), shown by arrows, exits the
secondary tubular member (66) traverses thru a passageway (58) in
the cutting head assembly (32) and exits at orifices (49).
[0076] FIGS. 4A illustrates an embodiment of a drive disk (42a) of
the flexible tubular member (not shown in full). The drive disk
(42a) defines a plurality of male teeth (82) and a plurality of
inner passageways (78 and 37), illustrated here as four openings,
sized and configured such that three tensioning cables (80) and a
hose (69) may be inserted through the respective openings on the
drive disk (42a). FIG. 4B shows a plan view of the drive segment
(42) in FIG. 4A. Evident in the figure are the teeth (82) and
female sockets (84) of a drive segment (42). In this case, the
overall profile of the drive segment (42) is cylindrical in shape
(as shown by dotted lines). The inner passageway (37) and
circumscribed hose (69) are shown; however, in this view and for
purposes of clarity, the tensioning cables and their holes are not
shown.
[0077] FIG. 4B shows a cross-sectional view of the drive disk (42a)
in FIG. 4A wherein the teeth (82) and female sockets (84) are
evident, as is the inner passageway (37) containing the hose (69).
In this case, the overall profile of the drive disk (42a) is
cylindrical in shape (as shown by outer set of dotted lines). Note:
for purposes of clarity, the cables, which run parallel to hose
(69) are not shown in this view. The teeth (82) on the drive disk
(42a) are used to drive rotation of the adjacent drive disk (not
shown) while the hose (69) allows for fluid communication through
the series of drive disks (not all shown).
[0078] FIG. 4C, shows an alternate version of a flexible tubular
shaft member (36) in a radius (11) of a whipstock (not shown in
full). The series of drive disks (42) of the flexible tubular shaft
member (36) are similar to those depicted in FIGS. 4A and 4B.
Evident is the hose (69), which serves as a secondary tubular
member, and which run through the tubular member inner passageway
(37) of the flexible tubular shaft member (36) and serves to help
keep the individual disks (42a, 42b, 42c etc.) held together. The
series of drive disks (42) transmit torque generated from a motor
(not shown) through the teeth (82) and respective mating sockets
(84) on an adjacent drive disk (42), in this fashion torque may be
transmitted from drive disk to drive disk. In this configuration,
the plurality of the drive disks (42) are configured to each have
one male side (83) and one female side (85). Tension on the drive
series of disks (42) is enabled through the tensioning cables (80),
as discussed more fully, below.
[0079] FIG. 5A shows an alternate embodiment of an individual drive
disk (42a) having an inner passageway (37) and five male teeth (82)
and five female sockets (84) on both sides (opposing side not
shown) for transmission of torque. In this figure, no separate
passageway for the tensioning system is shown, however, one will
notice a slightly wider diameter (45) beyond that of the teeth (82)
due to the barrel shaped nature of the drive disk (42a); this
barrel profile is better evident in FIG. 5B.
[0080] FIG. 5B is a plan view of the FIG. 5A wherein male teeth
(82) and female sockets (84) are evident on both sides of the drive
disk (42a). The teeth (82) and sockets (84) have radius breaks (86)
to allow for easier meshing of the teeth (82) into their respective
mating sockets (not shown) of the adjacent drive disk (not shown).
Additionally, it is evident that the profile of the drive disk (42)
has a barrel-shaped profile, as shown by the dotted lines.
[0081] FIG. 5C shows a radius (11) of a whipstock (not shown in
full) containing a partial flexible tubular shaft member (36)
comprised, in part, of a series of drive disks (42) like those
depicted in FIGS. 5A and 5B. The teeth (82a) of a drive disk (42a)
can be seen to mate into a respective female socket (84b) on an
adjacent drive disk (42b), thereby allowing for the transmission of
torque. In this embodiment, the inner tubular passageway (37) of
the series of drive disk (42) is shown with a corrugated hose (89)
serving as the means to provide fluid communication through the
flexible tubular shaft member (36).
[0082] FIG. 6A illustrates a frontal view of a cutting head
assembly (32) consistent with an embodiment of the present
invention. Evident on the cutting head assembly (32) are the
cutting faces (48) and the rotating nozzle head (52) with exit
orifices (49) situated in a recess open to the exterior (54) of the
cutting head assembly (32). In this depiction, rotation of the
cutting head assembly (32) is counterclockwise, as shown by arrow.
Fluid (F) exiting the exit orifices (49) can clean the cutting
faces (48) and flow to the outside of the cutting head assembly
(32), as shown by curved arrows.
[0083] FIG. 6B illustrates a cutting head assembly (32) and a
partial flexible tubular shaft member (36) consistent with an
embodiment of the present invention. A connection fitting (47) ties
the hose (69) to the cutting head (46). The connection fitting (47)
has passageway (51) to enable fluid communication between the hose
(69) and exit orifices (49) on the cutting head assembly (32). In
conjunction with the connection fitting (47), tension pulled on the
hose (69) in the direction of the arrow (T) may serve to keep the
series of drive disks (42) held together. The cutting head assembly
(32) includes a nozzle head (53) disposed within a recess open to
the exterior (54) of the cutting head assembly (32). The cutting
head assembly (32) has a centralizing mechanism (62), shown as
pins. The nozzle head (53) is in fluid communication with the hose
(69) and exit orifices (49) by interior nozzle passageway (58).
Fluid (F) exits (as shown by arrows) the nozzle head (53) to keep
the cutting faces (48) clean and cool. The cutting faces (48) are
shown with optional carbide inserts (150) for improved cutting of
the earthen formation (not shown).
[0084] FIG. 7A illustrates a frontal view of a cutting head
assembly (32) consistent with an embodiment of the present
invention. Evident on the cutting head assembly (32) are diamond
inserts (151) for improved cutting of the earthen formation (not
shown) with cutting faces (48) an exit orifices (49). As shown by
arrow indicating direction of rotation, behind the cutting faces
(48) are back support areas (63) which provide structural support
to the cutting faces (48) so as to resist breakage of the cutting
faces (48) when cutting earthen formation (not shown).
[0085] FIG. 7B shows a lateral borehole (50) in an earthen
formation (20) containing an embodiment of the flexible tubular
shaft member (36) composed of a series of drive disks (42) coupled
to a cutting head assembly (32) having diamond inserts (151) on its
cutting faces (48) (only visible on 1 side). In this case, the
inner passageway (37) of the flexible tubular shaft member (36)
contains elastomeric material (71) spanning between the drive disks
(42) and the cutting head assembly (32) to form seals. Fluid (F) in
the flexible tubular member inner passageway (37) traverses through
the cutting head assembly (32) thru passageway (61) in a connector
(130) secured to a tensioning cable (122) and cutting head (46);
the fluid (F) traverses passageways (58) and exits the cutting head
(32) at orifices (49) so as to keep the cutting faces (48) clean
and cool. The tensioning cable (122) runs through the flexible
tubular member inner passageway (37) and terminates at a connector
(130) located in the cutting head assembly (32). By pulling on the
tensioning cable (122), in the direction shown by arrow (T), one is
able to keep the series of drive disks (42) engaged with one
another.
[0086] FIG. 8 illustrates a cross sectional view of an embodiment
of the present invention wherein a whipstock (12) with guiding
plane (26) is positioned on upset tubing (14) in a wellbore (10)
surrounded by earthen formation (20). The illustration shows the
downhole tool assembly (18) being operated by a coiled tubing unit
(97) and pumping equipment (96), used to pump fluid (not shown)
down the conduit (76), in this case coiled tubing, to the motor
(40) so as rotate the flexible tubular shaft member (36) and
attached cutting head (32).
[0087] FIG. 9 illustrates a wireline unit (95) and pumping
equipment (96) positioned on a wellbore (10) in an embodiment of
the present invention. In this case, the downhole tool assembly
(18) is positioned above a whipstock (12) situated on a packer (28)
and connected to upset tubing (14) which is also serves as a
conduit to carry fluid (F), shown by arrows, from the pumping
equipment (96) to the motor (40) that is attached to the flexible
tubular shaft member (36) at an upper cross over member (128).
Seals (41) positioned between the fluid motor (40) and the upset
tubing (14) direct (shown by arrows) fluid (F) into the motor (40)
which in turn causes the attached flexible tubular shaft member
(36) and cutting head assembly (32) to rotate. As shown by arrows,
the fluid (F) exits the cutting head assembly (32)
[0088] FIG. 10 illustrates a coiled tubing unit (97), air
compressor (99) and cutting return tank (100) positioned on a
wellbore (10) wherein the downhole tool assembly (18) is positioned
in upset tubing (14) consistent with an embodiment of the present
invention. Periodically, an air compressor (99) may be used to pump
gas (G) down the upset tubing (14) and thru a lower passageway (3)
below the whipstock (12) where it traverses a passageway (5) in a
tubular member (4) and exits (6) so as to lift cuttings (C) out of
the wellbore (10), as shown by arrows, where they may return to the
cutting return tank (100).
[0089] As used herein, the term "hose" refers to elastomeric hose,
single or multi-braided hose, sheathed hose, Kevlar.RTM. hose and
comparable means of providing a means for fluid conduit.
[0090] As used herein, the terms "wire" or "cable" refers to wire
and cable whether single or multi-stranded, wire rope and similar
means for securing or providing tension between two ends.
[0091] As used herein, the term "fluid" refers to liquids, gases
and/or any combination thereof.
[0092] Use of the term "optionally" with respect to any element of
a claim is intended to mean that the subject element is required,
or alternatively, is not required. Both alternatives are intended
to be within the scope of the claim. Use of broader terms such as
comprises, includes, having, etc. should be understood to provide
support for narrower terms such as consisting of, consisting
essentially of, comprised substantially of, etc.
[0093] Depending on the context, all references herein to the
"invention" may in some cases refer to certain specific embodiments
only. In other cases it may refer to subject matter recited in one
or more, but not necessarily all, of the claims. While the
foregoing is directed to embodiments, versions and examples of the
present invention, which are included to enable a person of
ordinary skill in the art to make and use the inventions when the
information in this patent is combined with available information
and technology, the inventions are not limited to only these
particular embodiments, versions and examples. Other and further
embodiments, versions and examples of the invention may be devised
without departing from the basic scope thereof and the scope
thereof is determined by the claims that follow.
* * * * *