U.S. patent application number 11/507145 was filed with the patent office on 2006-12-14 for method and apparatus for completing lateral channels from an existing oil or gas well.
This patent application is currently assigned to Horizontal Expansion Tech, LLC. Invention is credited to John R. Hunt, Henry B. Mazorow.
Application Number | 20060278393 11/507145 |
Document ID | / |
Family ID | 35238391 |
Filed Date | 2006-12-14 |
United States Patent
Application |
20060278393 |
Kind Code |
A1 |
Hunt; John R. ; et
al. |
December 14, 2006 |
Method and apparatus for completing lateral channels from an
existing oil or gas well
Abstract
A method and apparatus for completing a lateral channel from an
existing oil or gas well includes a well perforating tool for
perforating a well casing at a preselected depth, and a lateral
alignment tool for directing a flexible hose and blaster nozzle
through a previously made perforation in the casing to complete the
lateral channel. The disclosed apparatus also is effective to
provide an expanded groove within the earth strata beyond the well
casing. The apparatus eliminates the need to maintain the precise
alignment of a downhole "shoe" in order to direct the flexible hose
and blaster nozzle through a previously made perforation through
the well casing.
Inventors: |
Hunt; John R.; (The
Woodlands, TX) ; Mazorow; Henry B.; (Lorain,
OH) |
Correspondence
Address: |
PEARNE & GORDON LLP
1801 EAST 9TH STREET
SUITE 1200
CLEVELAND
OH
44114-3108
US
|
Assignee: |
Horizontal Expansion Tech,
LLC
|
Family ID: |
35238391 |
Appl. No.: |
11/507145 |
Filed: |
August 21, 2006 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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11121622 |
May 4, 2005 |
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11507145 |
Aug 21, 2006 |
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60568492 |
May 6, 2004 |
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60573013 |
May 20, 2004 |
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Current U.S.
Class: |
166/298 ;
166/55 |
Current CPC
Class: |
E21B 29/06 20130101;
E21B 7/18 20130101; E21B 43/114 20130101 |
Class at
Publication: |
166/298 ;
166/055 |
International
Class: |
E21B 43/11 20060101
E21B043/11 |
Claims
1. A well perforating tool having a substantially cylindrical body
having a proximal end and a distal end and defining a
circumferential wall of the perforating tool, said perforating tool
having a longitudinal axis and comprising an axial blind bore open
to said proximal end of the perforating tool and defining an axial
flow passage within the perforating tool, a hole provided through
the distal end of said tool, said hole having a lateral dimensions
smaller than the diameter of said blind bore, and at least one
lateral port located in the circumferential wall of said
perforating tool, said lateral port providing fluid communication
between said axial flow passage and a position exterior of said
perforating tool, said lateral port being adapted to accommodate a
jet of high pressure cutting fluid for perforating a well
casing.
2. A well perforating tool according to claim 1, comprising a
plurality of said lateral ports.
3. A well perforating tool according to claim 1, comprising upset
tubing operatively connected to said tool and being adapted to
convey said cutting fluid to said tool.
4. A well perforating tool according to claim 1, said lateral port
being provided as a port hole in an abrasion resistant insert, said
abrasion resistant insert being disposed within an aperture drilled
or punched substantially radially through the circumferential wall
of said perforating tool.
5. A well perforating tool according to claim 4, said abrasion
resistant insert being made from carbide material.
6. A well perforating tool according to claim 4, said abrasion
resistant insert being made from tungsten carbide.
7. A well perforating tool according to claim 4, comprising a
plurality of said lateral ports.
8. A well perforating tool according to claim 1, further comprising
a chamfered edge provided about the perimeter of said hole located
at an interior surface of said distal end of said tool.
9. A well perforating tool according to claim 1, further comprising
a plug member that is dimensioned and adapted to close the hole in
said distal end of said tool during operation thereof.
10. A well perforating tool according to claim 8, said hole in said
distal end of said tool being a circular hole, said tool further
comprising a spherical plug member having a diameter that is
selected to be received and seated against said chamfered edge to
thereby close said hole during operation of said tool.
11. A well perforating tool according to claim 10, said spherical
plug member being a steel ball bearing.
12. An apparatus comprising: a lateral channel alignment tool
comprising a substantially elongate basic body having a
longitudinal axis, a lateral alignment member pivotally attached to
the basic body, and a biasing mechanism effective to bias said
lateral alignment member in an angled or laterally engaged position
relative to said basic body, said basic body having a longitudinal
passage therethrough that is radially offset relative to the
longitudinal axis of said basic body and adapted to accommodate a
hose therein, said lateral alignment member comprising a first
portion that extends generally lengthwise, a terminal portion that
extends at an angle relative to the lengthwise direction of the
first portion, and an elbow-shaped passage provided within the
lateral alignment member, said elbow-shaped passage extending
through said respective first and terminal portions of said lateral
alignment member from an entrance located in said first portion to
an exit located in said terminal portion, said entrance of said
elbow-shaped passage being located adjacent a distal end of said
longitudinal passage in said basic body and being adapted to
receive a blaster nozzle and associated hose therefrom; and a hose
received within both said longitudinal passage and said
elbow-shaped passage, said hose comprising a first hose section, a
second hose section, and a thruster coupling including a thruster
port, wherein said first hose section and said second hose section
are operatively connected by said thruster coupling, said thruster
port being actuable based on fluid pressure in said hose.
13. An apparatus according to claim 12, said thruster port
comprising a valve having a characteristic cracking pressure such
that when said fluid pressure is above the cracking pressure, said
valve is opened and fluid is permitted to jet out of said thruster
port through said valve, and when said fluid pressure is below the
cracking pressure, said valve is closed and fluid is not permitted
to jet out of said thruster port.
14. A lateral channel alignment tool according to claim 13,
comprising a plurality of said thruster couplings provided along
the length of said hose, each said thruster coupling having a
thruster port including a valve having a characteristic cracking
pressure.
15. A lateral channel alignment tool according to claim 14, wherein
the thruster couplings and their associated thruster ports are
arranged so that their respective valves, at least some of which
having different characteristic cracking pressures, are provided at
desired locations along the length of said hose.
16. A lateral channel alignment tool according to claim 12, said
elbow-shaped passage being adapted to direct said hose, received
from said longitudinal passage, out said exit located in said
terminal portion to bore a lateral channel in an adjacent formation
of earth.
17. A method of completing a lateral channel from an existing oil
or gas well having a well casing, comprising the steps of:
providing a well perforating tool having a substantially elongate
body defining a circumferential wall of the perforating tool, said
perforating tool having a longitudinal axis and comprising an axial
blind bore open to a proximal end of said perforating tool and
defining an axial flow passage within the perforating tool, and at
least one lateral port located in the circumferential wall of said
perforating tool, said lateral port providing fluid communication
between said axial flow passage and a position exterior of said
perforating tool; suspending said well perforating tool at a
selected depth in said existing well; and pumping a fluid at high
pressure through said axial flow passage such that a jet of said
high pressure fluid shoots out from said lateral port, said jet
perforating said well casing and cutting away a portion of earth
strata beyond said well casing.
18. A method according to claim 17, further comprising operating
said well perforating tool to produce a perforation in said well
casing about the circumference thereof, and further to cut a
circular groove in the earth strata beyond said well casing.
19. A method according to claim 18, said perforation in said casing
and said groove in the earth strata having approximately the same
height and being aligned with one another.
20. A method according to claim 18, wherein said well includes a
cement encasement surrounding said well casing, said cutting tool
being operated to produce a perforation in said cement encasement
about the circumference thereof, in addition to the perforation in
said well casing and the circular groove cut in the earth
strata.
21. A method according to claim 20, the perforations provided in
said well casing and in said cement encasement and the groove cut
in said strata all cooperating to provide a composite groove that
expands radially outward from said well.
22. A method according to claim 18, further comprising the steps
of: providing a lateral channel alignment tool comprising a
substantially elongate basic body having a longitudinal axis, a
lateral alignment member pivotally attached to the basic body, and
a biasing mechanism effective to bias said lateral alignment member
in an angled or laterally engaged position relative to said basic
body, said basic body having a longitudinal passage therethrough
adapted to accommodate a hose therein, said lateral alignment
member comprising a first portion that extends generally
lengthwise, a terminal portion that extends at an angle relative to
the lengthwise direction of the first portion, and an elbow-shaped
passage provided within the lateral alignment member, said
elbow-shaped passage extending through said respective first and
terminal portions of said alignment member from an entrance located
in said first portion to an exit located in said terminal portion,
said entrance of said elbow-shaped passage being located adjacent a
distal end of said longitudinal passage in said basic body and
being adapted to receive a blaster nozzle and associated hose
therefrom; advancing said lateral channel alignment tool in said
well until the terminal portion of said lateral alignment member
reaches and engages through said perforation and into said groove
in the earth strata; and providing a flexible hose and directing it
through said elbow-shaped passage in said lateral alignment member,
out through the exit thereof and into engagement with the earth
strata to cut a channel through the strata.
23. A method according to claim 22, wherein said hose is a flexible
high-pressure hose comprising a plurality of thruster ports
disposed at spaced intervals along the length thereof, the method
further comprising actuating said thruster ports based on fluid
pressure within said flexible high-pressure hose.
24. A method according to claim 22, said lateral channel alignment
tool further comprising an extensible hose guide member provided in
said lateral alignment member and effective to extend from the
distal end of said terminal portion of said lateral alignment
member to help guide a high-pressure hose fed through said
elbow-shaped passage and exiting therefrom into engagement with the
strata.
25. A method according to claim 24, said hose guide member
comprising a series of guide sections, each said guide section
having a horizontal and two opposing vertical plate portions that
cooperate to provide a substantially U-shaped cross-section,
wherein each guide section is joined to adjacent guide section(s)
via a pivot joint, a first guide section having a locking flange
provided extending forward from the underside of a first horizontal
plate portion thereof, said flange having an upper surface that
extends substantially parallel to the bottom face of said first
horizontal plate portion, said flange being effective to prevent a
successive, second horizontal plate portion of a successive, second
guide section from pivoting below the plane of the first horizontal
plate portion of the first guide section.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is a continuation-in-part of U.S.
application Ser. No. 11/121,622 filed May 4, 2005, which claims the
benefit of U.S. Provisional Application No. 60/568,492 filed May 6,
2004, and U.S. Provisional Application No. 60/573,013 filed May 20,
2004, the disclosures of all of which are incorporated herein by
reference.
BACKGROUND OF THE INVENTION
[0002] 1. Field of the Invention
[0003] The invention relates to methods and apparatus for
completing lateral channels from existing oil or gas wells. More
particularly, it relates to improved methods and apparatus for
penetrating the well casing of an existing well at a given depth,
and completing one or more laterals at that depth.
[0004] 2. Description of Related Art
[0005] Oil and gas are produced from wells drilled from the earth
surface into a hydrocarbon "payzone." Once a well is drilled, it
essentially is a hole in the earth extending from the earth surface
downward several hundred or thousand feet into or adjacent a
hydrocarbon payzone. The thus drilled hole generally is not very
stable because, among other things, its earthen walls are highly
subject to erosion or shifting over time, whether due to the flow
of hydrocarbons to the surface, or other natural causes such as
water erosion from rain or flooding. This is especially of concern
considering many oil and gas wells stay online for several or tens
of years, or longer.
[0006] To impart stability to a drilled well, it is conventional to
encase the well bore with a casing material, typically made from
steel. The steel well casing essentially is a cylindrical-walled
pipe having an OD somewhat smaller than the ID of the well bore
drilled from the earth surface. The well casing is placed down in
the well bore, typically in discrete sections which are secured or
otherwise joined together as is known in the art. Once the well
casing is in place centrally within the earthen well bore, it is
conventional to fill in the thus-defined annular space between the
well casing and the well bore with cement.
[0007] The resulting construction is an oil or gas well consisting
of a cement-encased steel pipe extending from the earth surface
down into a hydrocarbon payzone from which hydrocarbons (oil and/or
gas) can be extracted and delivered to the surface via conventional
techniques. This steel pipe, also called the well casing, defines
an inner bore or passageway for the delivery of hydrocarbons to the
surface. The described construction has proven useful for decades
to produce oil or gas from hydrocarbon payzones located at, or
which empty into, the base (bottom end) of the well casing.
However, once these payzones dry up, either the well must be
abandoned or it must be treated in order to make it productive and
profitable once again.
[0008] There are several conventional treatment techniques for
revitalizing an otherwise unproductive well. Two of the most common
are referred to as acidizing and fracturizing. Both of these
techniques are designed to increase the adjacent formation's
porosity by producing channels in the formation allowing
hydrocarbons to flow more easily into the perforated well bore,
thereby increasing the well's production and its value. However,
the success of these operations is highly speculative and both are
very expensive and require dedicated heavy equipment and a large
crew.
[0009] A more efficient technique for stimulating a diminished
production well is to drill a hole through the well casing at a
depth below the earth surface, and then to bore a lateral channel
through the predrilled hole into an adjacent payzone using a high
pressure water jet nozzle (blaster nozzle). Various techniques and
apparatus for boring lateral channels downhole are known in the
art, for example as described in U.S. Pat. Nos. 6,530,439,
6,578,636, 6,668,948, and 6,263,984, the contents of all of which
are incorporated herein by reference. Generally, an elbow or "shoe"
is used downhole to redirect a cutting tool fed from the surface
along a radial or lateral path at a depth at which a lateral
channel is to be completed. The cutting tool is directed laterally
against the well casing to cut or drill a small hole through the
casing and the cement encasement beyond, and is then withdrawn to
make way for a separate blaster nozzle and associated high pressure
water hose that must be snaked through the previously drilled hole.
This technique, which is simple to describe, in practice can be
difficult to perform, with uncertain or irreproducible results.
[0010] For one thing, often it is difficult and sometimes even
impossible to determine with certainty that a hole actually has
been cut through the casing and the cement encasement. Also, even
assuming a successfully cut hole, it can be extremely difficult to
ensure accurate alignment of the elbow or downhole shoe in order to
direct the blaster nozzle through the previously cut hole. For
example, the shoe may be jerked or moved during withdrawal of the
cutting tool or insertion of the blaster nozzle. In addition, it is
extraordinarily difficult, if not impossible in most cases to
realign the shoe with a previously cut hole if the shoe alignment
is accidentally shifted, or if it must be shifted (e.g. to drill
another hole) subsequent to drilling the hole in the casing but
prior to feeding the blaster nozzle through the hole. Often it is
impossible to know at the surface if the alignment of the shoe with
the previously drilled hole has been disturbed and needs
readjustment.
[0011] There is a need in the art for a method of perforating the
well casing (and annular cement encasement) at depth within an
existing oil or gas well, wherein the precise alignment of a
downhole tool need not be exactly maintained to ensure a
subsequently introduced boring tool, such as a high pressure
blaster nozzle, can be directed through the previously made
perforation to bore a lateral channel or channels therefrom.
SUMMARY OF THE INVENTION
[0012] A well perforating tool is provided. The tool has a
substantially cylindrical body having a proximal end and a distal
end and defining a circumferential wall of the perforating tool.
The perforating tool has a longitudinal axis and includes an axial
blind bore open to the proximal end of the perforating tool, which
defines an axial flow passage within the perforating tool. A hole
is provided through the distal end of the tool. This hole has a
lateral dimensions smaller than the diameter of the blind bore. At
least one lateral port is located in the circumferential wall of
the perforating tool. The lateral port provides fluid communication
between the axial flow passage and a position exterior of the
perforating tool. The lateral port is adapted to accommodate a jet
of high pressure cutting fluid for perforating a well casing.
[0013] An apparatus is provided, which includes a lateral channel
alignment tool having a substantially elongate basic body having a
longitudinal axis, a lateral alignment member pivotally attached to
the basic body, and a biasing mechanism effective to bias the
lateral alignment member in an angled or laterally engaged position
relative to the basic body. The basic body has a longitudinal
passage therethrough that is radially offset relative to the
longitudinal axis of the basic body and adapted to accommodate a
hose therein. The lateral alignment member includes a first portion
that extends generally lengthwise, a terminal portion that extends
at an angle relative to the lengthwise direction of the first
portion, and an elbow-shaped passage provided within the lateral
alignment member. The elbow-shaped passage extends through the
respective first and terminal portions of the lateral alignment
member from an entrance located in the first portion to an exit
located in the terminal portion. The entrance of the elbow-shaped
passage is located adjacent a distal end of the longitudinal
passage in the basic body and is adapted to receive a blaster
nozzle and associated hose therefrom. A hose is received within
both the longitudinal passage and the elbow-shaped passage. The
hose includes a first hose section, a second hose section, and a
thruster coupling including a thruster port, wherein the first hose
section and the second hose section are operatively connected by
the thruster coupling. The thruster port is actuable based on fluid
pressure in the hose.
[0014] A method of completing a lateral channel from an existing
oil or gas well having a well casing is also provided. The method
includes the steps of: providing a well perforating tool having a
substantially elongate body defining a circumferential wall of the
perforating tool, the perforating tool having a longitudinal axis
and an axial blind bore open to a proximal end of the perforating
tool, wherein the blind bore defines an axial flow passage within
the perforating tool, at least one lateral port being located in
the circumferential wall of the perforating tool, the lateral port
providing fluid communication between the axial flow passage and a
position exterior of the perforating tool; suspending the well
perforating tool at a selected depth in the existing well; and
pumping a fluid at high pressure through the axial flow passage
such that a jet of said high pressure fluid shoots out from the
lateral port, wherein the jet perforates the well casing and cuts
away a portion of earth strata beyond the well casing.
BRIEF DESCRIPTION OF THE DRAWINGS
[0015] FIG. 1a is a side view of a well perforating tool;
[0016] FIG. 1b is a side view of a further embodiment of a well
perforating tool;
[0017] FIG. 2 is an end view of the well perforating tool of FIG.
1a;
[0018] FIG. 3a is a side perspective view of the well perforating
tool of FIG. 1a;
[0019] FIG. 3b is a side perspective view of the well perforating
tool of FIG. 1b;
[0020] FIG. 4a is a side view of a lateral channel alignment tool,
with the lateral alignment member pivoted in an extended
position;
[0021] FIG. 4b is a side view as in FIG. 4a, but with the lateral
alignment member pivoted in a laterally engaged position;
[0022] FIG. 5 is a front perspective view of the lateral channel
alignment tool of FIG. 4;
[0023] FIG. 6 is a schematic view showing the well perforating tool
of FIG. 1a lowered into the well casing of an existing oil or gas
well at an early stage of a well perforating operation.
[0024] FIG. 7 is a schematic view as in FIG. 6, but at a later
stage of the well perforating operation;
[0025] FIG. 7a is a schematic view showing the same stage of the
boring operation as FIG. 7, but according to a further preferred
embodiment where the well perforating tool is operated to cut a
circular groove in the earth strata beyond the well casing, in
addition to perforating the well casing and the cement encasement
surrounding the well.
[0026] FIG. 8 is a schematic view showing the lateral channel
alignment tool of FIG. 4 lowered into the well casing of an
existing well after a well perforating operation, shown at an early
stage of a lateral channel boring operation;
[0027] FIG. 9 is a schematic view as in FIG. 8, but at a later
stage of the lateral channel boring operation;
[0028] FIG. 9a is a schematic view showing the same stage of the
boring operation as FIG. 9, but according to the embodiment
illustrated in FIG. 7a where a circular groove is cut in the earth
strata during the well perforating operation;
[0029] FIG. 9b is a schematic view as in FIG. 9a, except
illustrating a further embodiment wherein an extensible hose guide
member 260 is used;
[0030] FIG. 10 is a schematic view as in FIG. 9 but at a still
later stage of the lateral channel boring operation;
[0031] FIG. 11 is a side view of a thruster coupling according to
an aspect the invention;
[0032] FIG. 12 is a cross-sectional view of the thruster coupling
taken along line 12-12 in FIG. 11;
[0033] FIG. 13 is a longitudinal cross-sectional view of the
thruster coupling taken along line 13-13 in FIG. 12;
[0034] FIG. 14 is a perspective view of a flexible hose having
thruster couplings;
[0035] FIG. 15a is a perspective view of a blaster nozzle;
[0036] FIG. 15b is an alternate perspective view of a blaster
nozzle;
[0037] FIG. 16 is a perspective view of a flexible hose having
thruster ports provided directly in the sidewall according to an
embodiment of the invention;
[0038] FIG. 17 is a side view of a thruster coupling having
adjustable thruster ports according to an embodiment of the
invention;
[0039] FIG. 17a is a side view as in FIG. 17, schematically
illustrating an embodiment wherein pressure-relief or check valves
are provided in the thruster ports, which have a characteristic
cracking pressure and will permit the flow of cutting fluid
therethrough once the fluid pressure within the hose has reached or
exceeded each respective valve's cracking pressure.
[0040] FIG. 18 is a cross-sectional view of the thruster coupling
taken along line 18-18 in FIG. 17;
[0041] FIG. 19 is a close-up view of an adjustable thruster port
indicated at broken circle 19 in FIG. 17;
[0042] FIG. 20 is a side view of a lateral channel alignment tool
similar to that shown in FIG. 4a, except that it includes an
extensible hose guide member located at the distal end of the
terminal portion 206 of the lateral channel alignment tool 200;
and
[0043] FIG. 21 is a close-up perspective view of the hose guide
member shown in FIG. 20.
DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS OF INVENTION
[0044] As used herein, when a range such as 5 to 25 (or 5-25) is
given, this means preferably at least 5 and, separately and
independently, preferably not more than 25. Also as used herein,
when referring to a tool used downhole in a well, such as the
perforating tool 100, the lateral channel alignment tool 200, or
the flexible hose assembly 10 described below, the proximal end of
the tool is the end nearest the earth surface when being used, and
the distal end of the tool is the end farthest from the earth
surface when being used; i.e. the distal end is the end inserted
first into the well. Also as used herein, a bore (such as a through
bore or a blind bore) need not be made, necessarily, by drilling.
It can be formed by any suitable method or means for the removal of
material, for example, by drilling or cutting, or by casting or
molding an object to have a bore.
[0045] Referring to FIGS. 1-5, a well perforating tool 100 (FIGS.
1-3) and a lateral channel alignment tool 200 (FIGS. 4-5) are
provided. When used together according to methods described herein,
these tools are useful to reproducibly complete lateral channels
from an existing oil or gas well at a desired depth, without having
to maintain the precise alignment of any downhole equipment between
a well perforating operation and a subsequent lateral channel
boring operation. First the structure of each of these tools is
described. Following is a description of methods for completing
lateral channels from an existing well, for example using a
flexible hose assembly as described herein.
[0046] Referring first to FIGS. 1-3, the well perforating tool 100
has a substantially cylindrical body having a longitudinal axis
101, preferably made from steel or stainless steel, most preferably
from 4140 steel. The perforating tool 100 has an axial blind bore
110 open to, preferably drilled from, the proximal end 107 of the
tool 100, preferably extending substantially the entire length of
the tool 100, but not through the distal end 108. The blind bore
110 defines an axial flow passage 115 within the perforating tool
100 to accommodate a high pressure abrasive cutting fluid as
described below. Less preferably, the bore 110 can be a through
bore drilled through the distal end 108 of the perforating tool
100, though this will have a substantially negative effect on the
pressure of the cutting fluid used to perforate the well casing as
will become evident below. In the embodiment illustrated in FIG.
1a, the blind bore 110 is closed at the distal end 108 of the
perforating tool 100; i.e. there is no fluid communication between
the interior of that bore 110 and the exterior of the tool adjacent
the distal end 108. In an alternate and preferred embodiment
illustrated in FIG. 1b, there is a small hole 109 provided through
the distal end 108 of the tool 100. By `small` here, it is meant
that the hole 109 has smaller lateral dimensions (e.g. a smaller
diameter) than the diameter of the blind bore 110. Preferably, a
chamfered edge 111 is provided about the perimeter of the hole 109
at the interior surface of the distal end 108 of the tool 100. The
chamfered edge 111 serves as a seat for a flow plug during
operation of the perforating tool 100 as will be later
described.
[0047] The perforating tool 100 preferably is machined at its
proximal end 107 adjacent the opening for blind bore 110, to
accommodate or be mated to the end of a length of upset tubing 500
as is known in the art. The exact means for attaching the upset
tubing 500 to the proximal end of the perforating tool 100 are not
critical, and can employ any known or conventional means for
attaching upset tubing to downhole drilling equipment, which means
are well known by those skilled in the art, so long as the
following conditions are taken into consideration. First, the means
employed should provide fluid tightness between the tubing 500 and
the tool 100 at high internal fluid pressure, preferably at least
2500, preferably at least 3000, preferably at least 3500,
preferably at least 4000, preferably at least 4500, preferably at
least 5000, preferably at least 6000, preferably at least 8000,
preferably at least 10,000, psi. By fluid tightness, it is not
intended or implied that there cannot be any fluid leaking out of
the tubing-perforating tool juncture or through the attachment
means at the above fluid pressures, or even that substantial fluid
cannot leak out; only that the fluid pressure in the axial flow
passage 115 is not thereby diminished by more than about 40,
preferably 30, preferably 20, preferably 10, preferably 5, percent.
Second, the means for attaching the upset tubing 500 to the
perforating tool 100 should be able to withstand rotational or
torsional stresses downhole, e.g. at a depth of 50-5000 feet or
more, based on rotating the upset tubing at the surface at a rate
of about 10-500, more preferably 15-100 RPMs. This is because, as
will be further described, the perforating tool 100 is caused to
rotate downhole by rotating the upset tubing at the surface.
Exemplary attachment means include threaded connections, snap-type
or locking connections that are or may be sealed using gaskets,
O-rings, and the like.
[0048] Preferably, the distal end 108 of the perforating tool 100
is chamfered to promote smooth insertion into and passage through
the well casing. Optionally, the proximal end 107 can be chamfered
as well to promote smooth retraction and withdrawal of the
perforating tool 100 from the well casing following a well
perforating operation.
[0049] The perforating tool 100 has at least one, and preferably
has a plurality of lateral ports 120 located in the circumferential
wall of the tool 100. Preferably, each port 120 is provided with an
abrasion resistant insert 125 that has a port hole provided or
drilled therethrough, and which is inserted and accommodated within
an aperture drilled or punched substantially radially through the
circumferential wall of the perforating tool 100. The lateral ports
120 provide fluid communication between the axial flow passage 115
and a position exterior the perforating tool 100, and are
passageways for jets of the high pressure abrasive cutting fluid
used to perforate the well casing as will be further described. The
inserts 125 are resistant to abrasion or erosion from the cutting
fluid which is the reason they are used. The ports 120 can be
provided by first inserting solid inserts 125 made from carbide or
other resistant material into predrilled apertures in the
circumferential wall of the tool 100, and then drilling port holes
through the inserts. Alternatively, the inserts 125 can have the
port holes predrilled therein prior to being inserted in the
apertures of the perforating tool 100 wall.
[0050] Preferably, the abrasion resistant inserts 125 are made from
carbide material, most preferably from tungsten carbide. Less
preferably, the abrasion resistant inserts 125 can be made from
another suitable or conventional abrasion resistant material that
is effective to withstand the high pressure abrasive cutting fluid
that will be jetted through the ports 120, with little or
substantially no erosion of the inserts 125 following 2, 3, 4, 5,
6, 7, 8, 9 or 10, well perforating operations (described below).
However, it should be understood the inserts 125 (even those made
from tungsten carbide) eventually will erode from the abrasive
cutting fluid to the point that either the inserts 125 or the
entire perforating tool 100 should be replaced.
[0051] The lateral ports 120 are of minor diameter compared to the
diameter of the perforating tool 100, preferably not more than 20
or 15 percent the OD of the perforating tool, most preferably not
more than 12, 10, 8, 6 or 5, percent the OD of the perforating
tool.
[0052] In operation, the perforating tool 100 is rotated downhole
via the upset tubing 500 from the surface, and the high pressure
abrasive cutting fluid is pumped through the axial flow passage 115
and jetted out the lateral ports 120 to perforate the well casing
at the desired depth. Therefore, it is desired the tool 100 be
designed to be substantially balanced during a perforating
operation. By balanced, it is meant that when the tool 100 is
rotated within the well casing as high pressure cutting fluid is
jetted out from the lateral ports 120, the perforating tool 100
rotates uniformly about its longitudinal axis without being thrust
against the surrounding well casing. To achieve such a balanced
design, preferably the plurality of ports 120 are provided 1)
having substantially equal diameters and spaced circumferentially
apart from one another according to the following relation when
viewed along the longitudinal axis 101 of the perforating tool 100:
circumferential spacing of ports =2.pi. radians/(number of
ports)
[0053] resulting in a circumferential spacing of .pi. radians for 2
ports, 2.pi./3 radians for 3 ports, .pi./2 radians for 4 ports,
etc.; and 2) such that each port 120 is radially aligned with the
perforating tool 100 so that a centerline 121 of each port 120
intersects the longitudinal axis 101 of the perforating tool
100.
[0054] When the ports 120 are provided as described in the
preceding paragraph, the sum of the lateral thrust vectors
resulting from the cutting fluid jetting out the ports 120 is
substantially zero. Thus, the principal net force acting on the
perforating tool 100 during a perforating operation is the
rotational force or torque supplied via the upset tubing from the
surface, and substantially no net lateral thrust or force moments
act on the tool 100 as a result of the fluid jetting from lateral
ports 120. Therefore, the perforating tool 100 is permitted to
rotate freely within the well casing based on the torque supplied
from the upset tubing 500, without substantially binding or seizing
against the well casing as it is rotated.
[0055] Also, it is preferred that lateral ports 120 are provided
spaced longitudinally of the perforating tool 100 in the
circumferential wall thereof, in order to provide a perforation or
groove 425 (FIG. 7) in the well casing 400 of sufficient width to
accommodate a terminal portion 206 of the lateral channel alignment
tool 200 (discussed below). It is noted that a net moment may
result due to the longitudinal spacing of the ports 120 along the
length of the perforating tool 100, which moment would tend to
cause the tool 100 to rotate about an axis perpendicular to its
longitudinal axis 101. However, such a moment is countered by the
upset tubing 500 which extends from the surface generally along the
longitudinal axis 101, and is rigidly connected to the perforating
tool 100. Conversely, the upset tubing 500 is relatively
ineffective to prevent lateral movement of the perforating tool 100
downhole, which is why it is desired the ports 120 be provided so
the lateral force vectors from jetting fluid balance out.
[0056] The well perforating tool 100 can be supplied in a multitude
of dimensions depending on the diameter of the well casing that is
to be perforated. Generally, it is preferred the perforating tool
100 be provided such that its OD is slightly smaller than the ID of
the well casing so the tool 100 slides readily down into the well
casing until the desired depth has been reached. For example, for
standard 41/8'' well casing, the perforating tool 100 can have an
OD of 33/4'' to 4 1/16'', and more preferably about 37/8'' to about
4 1/32''. It will be understood the OD of the perforating tool 100
is provided to effect smooth rotation thereof within the well
casing during a well perforation operation. From the present
disclosure, a person of ordinary skill in the art can, without
undue experimentation, make a perforating tool 100 having
appropriate dimensions to suit the particular well casing in a
particular well.
[0057] Referring now to FIGS. 4a, 4b, and 5, the lateral channel
alignment tool 200 has a substantially elongate basic body 202 of
generally cylindrical shape having a proximal end 207 and a distal
end 208, and a lateral alignment member 204 pivotally attached to
the basic body 202 at or adjacent the distal end 208 via a fulcrum
or pivot joint 240. The basic body 202 preferably is made from a
round steel billet. The body 202 has a longitudinal through bore
220 drilled therethrough, which defines a longitudinal passage 225
adapted to accommodate a blaster nozzle and associated high
pressure hose (later described). The basic body 202 preferably is
further machined at its proximal end 207 to accommodate or be mated
to the end of a length of upset tubing (not shown) as is known in
the art. As seen in FIG. 4a, the machined opening 212 adjacent the
proximal end 207 preferably includes a mating portion 213 for
mating the upset tubing, and a neck potion 214 to provide a smooth
transition and fluid communication between the mating portion 213
and the through bore 220.
[0058] Most preferably, the through bore 220, and therefore the
longitudinal passage 225, is radially offset relative to the
longitudinal axis 201 of the body 202. Typically, the longitudinal
passage 225 has a smaller diameter than the mating portion 213
because the blaster nozzle and hose that must be accommodated by
the passage 225 are of smaller diameter than the upset tubing that
must be accommodated by the mating portion 213--typically 23/8'' to
27/8'' diameter. Therefore, the machined mating portion 213 is
provided more centrally (though not necessarily concentrically) in
the proximal end 207 of the basic body 202 to accommodate its
larger diameter. In this construction, as seen in FIG. 4a, the neck
portion 214 is provided as a reducing portion in order to provide a
smooth transition between the larger diameter of the more centrally
aligned mating portion 213 and the smaller diameter of the radially
offset through bore 220. The through bore 220 (longitudinal passage
225) is radially offset in order to accommodate larger diameter
high pressure hose, and consequently greater drilling fluid flow
rates, for boring a lateral channel into the earth's strata than
has heretofore been possible or practical in the art as will be
described.
[0059] The lateral alignment member 204 is pivotally attached to
the basic body 202 at or adjacent the distal end 208 via fulcrum or
pivot joint 240. The lateral alignment member 204 has a generally
elbow shape, including a major or first portion 205 that extends
generally lengthwise, and a terminal portion 206 that extends
transversely on or at an angle relative to the lengthwise direction
of the first portion 205. An elbow-shaped passage 230 is provided
within the lateral alignment member 204, extending through the
respective first and terminal portions 205 and 206 thereof, from an
entrance located adjacent the pivot joint 240 along a substantially
arcuate path to an exit located in the terminal portion 206. The
entrance of the elbow-shaped passage 230 is located adjacent the
distal end of the longitudinal passage 225 in the basic body 202,
and is adapted to receive a blaster nozzle and associated high
pressure hose therefrom. Thus received, the elbow-shaped passage
230 is adapted to direct the blaster nozzle and hose out the exit
located in the terminal portion 206 and out into the earth strata
to complete a lateral channel boring operation in the adjacent
formation (described below). As seen in FIG. 4a, the diameter of
the elbow shaped passage 230 (including its entrance) can be larger
than that of the longitudinal passage 225, so long as the two
passages are arranged so that the blaster nozzle and higher
pressure hose can be delivered from the latter to the former when
fed down through the alignment tool 200.
[0060] The lateral alignment member 204 preferably is machined from
A-2 or D-2 tool steel, and is machined in two mirror-image or
clamshell halves via conventional techniques to provide the
above-described construction. When made as clamshell halves, the
two halves are fastened to one another, e.g., using socket head cap
screws. The member 204 preferably is heat treated to acquire a
hardness of 55-65 RC.
[0061] The alignment tool 200 includes a biasing mechanism
effective to bias the lateral alignment member 204 in an angled or
laterally engaged position relative to the basic body 202 as shown
in FIG. 4b. In the illustrated embodiment, the biasing mechanism is
a pneumatic or hydraulic compression cylinder 250 attached to first
and second tensioning brackets 252 and 254 located respectively on
the basic body 202 and lateral alignment member 204. Compression
cylinders generally are well known in the art, and the particular
compression cylinder used (e.g. N.sub.2, air, other gas, hydraulic,
etc.) is not critical so long as it has the tendency to pull the
brackets 252 and 254 closer together and thus bias the member 204
in the laterally engaged position shown in FIG. 4b. The first and
second tensioning brackets 252 and 254 preferably are located on
the respective body 202 and member 204 such that they extend
generally in the same radial direction (when viewed along an end of
the basic body 202--arrow A in FIG. 4a) as the transversely
extending terminal portion 206 of the member 204. The pivot joint
or fulcrum 240 between the body 202 and member 204 is arranged such
that the lateral alignment member 204 pivots along an arc located
in a plane with the first and second tensioning brackets 252 and
254. When a compression cylinder 250 is used as the biasing
mechanism, preferably the basic body 202 has a cylinder pocket 251
provided or machined therein to accommodate the cylinder 250 within
the overall geometric dimensions of the body 202, thereby
facilitating unobstructed insertion of the entire assembly
downhole.
[0062] With the construction described in the preceding paragraph,
when the lateral channel alignment tool 200 is provided downhole
within a well casing, the compression cylinder 250 urges or forces
the terminal portion 206 of the lateral alignment member 204 (and
correspondingly the exit of the elbow-shaped passage 230) toward an
engaged position in a lateral direction radially outward relative
to the longitudinal axis of the basic body 202 and against the well
casing. (FIG. 4b shows the alignment tool 200 in the engaged
position). Alternatively, other suitable biasing mechanisms can be
used to achieve this effect, for example a torsion spring located
at or coupled to the pivot joint 240, spring clips, helical spring
or elastic band connected to the brackets 252 and 254, or any other
suitable or conventional means. In order to insert the tool 200
into the well casing, the lateral alignment member 204 is forced
into an extended position against the action of the biasing
mechanism (compression cylinder 250), shown in FIG. 4a, such that
the basic body 202 and member 204 are substantially longitudinally
aligned to facilitate insertion of the tool 200. Once in the well
casing, the external force holding the member 204 in the extended
position is removed, and the terminal portion 206 is forced against
the well casing by operation of the compression cylinder 250.
[0063] Methods for completing lateral channels from an existing
well will now be described.
[0064] Referring first to FIG. 6, a conventional cement and steel
encased oil or gas well is depicted schematically, having a steel
well casing 400, an annular cement encasement 450, and showing the
earth strata (oil bearing formation) 475 beyond. First, the well
perforating tool 100 is connected to the distal end of a length of
upset tubing 500 via suitable attachment means as previously
described. The perforating tool 100 is lowered into the well casing
400 via the upset tubing 500 to a depth at which it is desired to
perforate the casing and complete a lateral channel into the
adjacent formation 475. The perforating tool 100 is suspended at
the desired depth at the end of the upset tubing 500. On the
surface, the upset tubing is connected to a high pressure abrasive
cutting fluid source (not shown), capable of supplying high
pressure cutting fluid at a pressure of 1000-10,000 psi, preferably
2000-8000 psi, more preferably about 2500 to 5000 psi. A suitable
or conventional swivel tool as known in the art (also not shown) is
coupled to the proximal end of the upset tubing 500 extending out
from the well casing at the earth surface. The swivel tool is
engaged, and supplies torque to the upset tubing 500, which in turn
supplies torque to the perforating tool 100 downhole to rotate the
tool 100. The swivel tool is operated to achieve a rotational
velocity for the perforating tool 100 of 5-500, preferably 10-250,
preferably 15-200, preferably 15-150, RPMs. Alternatively to a
swivel tool at the surface, torque can be supplied to rotate the
perforating tool 100 from a downhole motor as known in the art.
[0065] The high pressure cutting fluid source is engaged, and pumps
abrasive cutting fluid through the upset tubing 500, and into the
axial flow passage 115 of the tool 100, such that the cutting fluid
is caused to jet out from the lateral ports 120 under high pressure
and impinge against the well casing 400, preferably at 2500-5000
psi. The abrasive cutting fluid can be any known or conventional
cutting fluid suitable to abrade and perforate the well casing
400.
[0066] As the tool 100 rotates and jets of the high pressure
abrasive cutting fluid impinge on the well casing 400, the jets
continually abrade and degrade the well casing 400 about its entire
circumference along a 360.degree. path. The tool 100 continues to
rotate, and the cutting fluid is continuously pumped for a period
of time, preferably 5-60, more preferably about 10-40 or 10-30
minutes, depending on the material and the integrity of the well
casing 400, until ultimately the casing 400 and the cement
encasement 450 surrounding the casing 400 have been worn away about
the entire 360.degree. circumference thereof. The results are a
substantially severed well casing 400 and cement encasement 450
(see FIG. 7), yielding a circular perforation or groove 425 in the
casing 400 and cement encasement 450 at the depth at which the
perforating operation was performed. It is noted the upper portions
of the now-severed well casing 400 and cement encasement 450
generally will not fall, thus closing the newly made groove 425,
because these will remain suspended, held up by the surrounding
earth. However, for relatively newer wells where the earth has not
yet sufficiently bound to the encasement to prevent collapse, or
otherwise for grooves 425 made at great depths, it is desirable to
place one or a plurality of support members 430 in the groove 425
to support the upper portions of the severed casing 400 and cement
encasement 450 to prevent collapse.
[0067] Alternatively, the circular perforation or groove 425 can be
provided by the following, alternative method. Once the perforating
tool 100 has been lowered to the appropriate depth at which it is
desired to provide the groove 425, the abrasive cutting fluid is
pumped into the axial flow passage 115, causing jets from the
lateral ports 120 as before to impinge against the well casing 400.
In this method, the well perforating tool 100 is alternately
extended and withdrawn (i.e. translated alternately upward and
downward) a certain distance corresponding to the desired overall
height of the finished groove 425, such that the impinging jets
against the well casing 400 cut a vertical slot through the casing
400. Once the vertical slot has been completed, the perforating
tool 100 is rotated within the well casing incrementally such that
the lateral port(s) 120 is/are aligned with a portion of the casing
immediately adjacent the previously cut vertical slot. Then the
jetting and alternate vertical translating steps are repeated to
cut a subsequent vertical slot in the well casing, that is located
circumferentially adjacent the prior-cut vertical slot, such that
the vertical slots together define a substantially continuous
opening through the casing. This operation is repeated ultimately
until a substantially continuous circular perforation or groove is
provided in the casing. In this embodiment, only one lateral port
120 may be necessary in the circumferential wall of the perforating
tool 100 because the height of the groove 425 is provided based on
the upward/downward translation of the tool 100. However, it may be
desirable to provide multiple ports 120 at the same longitudinal
elevation but at a different circumferential location, such as
180.degree. offset, in order to improve cutting efficiency or time
to produce the groove 425.
[0068] In a further alternative method, the circular perforation or
groove 425 can be provided by simultaneously rotating, and
translating alternately upward and downward, the well perforating
tool 100 as the jets of the high pressure abrasive cutting fluid
emerge from the ports 120 and impinge on the well casing 400.
During this operation, the jets continually abrade and degrade the
well casing 400 about its entire circumference along a 360.degree.
path based on the rotation of the perforating tool 100. At the same
time, a groove 425 having a desired overall height is provided
based on the upward/downward translation of the perforating tool
100 as it is rotated.
[0069] Regardless of the particular method of operation of the
cutting tool 100 to perforate the well casing, the high pressure
abrasive cutting fluid is forced out the ports 120 based on the
pressure of that fluid being delivered to the flow passage 115
(defined by blind bore 110). During operation, the distal end 108
of the cutting tool 100 is closed to the flow of cutting fluid in
order to ensure maximum fluid pressure through the ports 120. In
the embodiment of FIG. 1a, this is achieved by the distal end 108
being a solid, imperforate wall. In the embodiment of FIG. 1b, a
plug member 112 is provided to close the hole 109 during operation
of the perforating tool 100. In the embodiment where the hole 109
is circular and has a chamfered edge 111 located at its interior
circumference, the plug member 112 can be a ball bearing, such as a
steel ball bearing, whose diameter is selected to be received and
seated against the chamfered edge 111, thereby closing off the hole
109. By `closing off,` `closed off` and other cognates thereof, it
is not meant that the plug member must provide a completely
fluid-tight seal to completely prevent fluid from passing through
the hole 109. Rather, the plug member simply closes the hole 109 to
a sufficient extent to retain a substantial proportion of the
cutting fluid pressure delivered to the axial flow passage 1 15,
(preferably at least 50%, more preferably at least 60%, 70%, 80%,
90% or 95%, of initial fluid pressure), for delivery through the
lateral port(s) 120, so that substantial pressure is not lost to
flow through the hole 109 during operation of the perforating tool
100. No particular retention means are necessary to hold the plug
member 112 in place, as it will be held in place, preferably seated
against chamfered edge 111, by the fluid pressure of the cutting
fluid during operation.
[0070] Once a particular cutting operation is complete (e.g. to
perforate well casing at a selected depth), the cutting tool 100
can be cleaned out by flushing water or some other cleaning fluid
in a `reverse flow` direction through the cutting tool 100. This
can be achieved by pumping a fluid (e.g. water) into the well
casing 400 from the surface, in the annular space defined between
the casing wall and the outer surface of the upset tubing 500. The
pressure of this fluid presses upward against the plug member 112
as it flows through the distal end 108 from the bottom surface
thereof, and flows upward through the flow passage 115, ultimately
through the upset tubing 500 to exit at the surface. Such a reverse
flow flushing step is desirable to clean out residual sand, grit or
other abrasive particles or particulates that are present in the
cutting fluid used to perforate the well casing. From time to time,
some of these solids can or may settle in the flow passage 115,
thereby restricting flow of the cutting fluid or perhaps blocking
flow through the ports 120 altogether. A high-pressure reverse-flow
flush as described here can be used to clean out the cutting tool
100, particularly to drive any settled or deposited solids upward
and out of the system through the upset tubing 500 to exit at the
surface. Once the flushing operation is complete, the water from
the annular space in the well casing 400 can be drained, the plug
member 112 re-set to close off the hole 109, and cutting operations
restarted. Preferably, the plug member 112 is a ball bearing as
mentioned above, whose diameter (and that of the corresponding
chamfered edge 111) relative to the interior diameter of the blind
bore 110 is sufficiently large that it will self-seat against the
chamfered edge 111 by gravity. It should be noted it may not be
necessary to pump the reverse-flow flushing fluid with sufficient
pressure to eject the plug member 112 at the surface, though that
may be desired to achieve adequate flushing of settled solids. If
the plug member 112 is ejected, then it or another one can be
replaced by simply dropping it through the upset tubing 500 from
the surface, and it will re-seat against the chamfered edge 111 by
gravity.
[0071] The foregoing flushing step will be desirable in the event
the perforating tool should become clogged with settled solids
during a perforating operation. Using the flushing method, the
perforating tool 100 can be cleaned downhole and in place without
moving it from the correct depth to complete the pending
perforation. It is therefore made unnecessary to withdraw it for
cleaning and then to attempt its re-alignment with the started
perforation, which may be difficult. Alternatively, if it is
desired to complete multiple casing perforations at different
depths, one can conduct a flushing operation in between successive
perforations, instead of withdrawing the perforating tool 100 each
time to clean it before conducting the next perforating operation
at a different depth.
[0072] Returning to drilling methods, once the circular perforation
or groove 425 has been completed, or multiple of them at selected
depths as the case may be, the perforating tool 100 is withdrawn
from the well casing and the lateral channel alignment tool 200 is
lowered in its place. As shown in FIG. 8, the alignment tool 200 is
attached to the end of upset tubing (not shown) and lowered into
the well casing 400 where the well perforating operation was
previously performed. To insert the alignment tool 200 into the
well casing, first the lateral alignment member 204 is pivoted in
the extended position against the action of the biasing mechanism
(compression cylinder 250) via an external force. Next, the tool
200 is inserted into the well casing and the external force is
removed, so that the basic body 202 is substantially slidably
disposed in the well casing 400 and the lateral alignment member
204 is biased such that the terminal portion 206 is forced up
against the casing 400 at a position generally below the basic body
202.
[0073] With the terminal portion 206 forced against the well casing
400, the alignment tool 200 is pushed downward via the upset tubing
from the surface, until the terminal portion 206 arrives at the
previously made groove 425 in the casing 400 and the cement
encasement 450. As the alignment tool 200 continues downward, due
to the biasing of the lateral alignment member 204 the terminal
portion 206 is caused to move laterally, and ultimately to lock
into place in a laterally engaged position (FIG. 4b) within the
groove 425 adjacent the severed upper and lower portions of the
casing and cement encasement. (See FIG. 9) Thus the lateral
alignment member 204, and hence the alignment tool 200,
automatically locks into place on reaching the groove 425, and the
exit of the elbow-shaped passage 230 is now provided adjacent,
preferably substantially up against, the earth formation 475
located laterally of the severed casing.
[0074] With the lateral alignment member 204 in this position, a
blaster nozzle 300 is fed down through the upset tubing at the end
of a length of high pressure hose 310, such as coil tubing or
macaroni tubing as known in the art. On reaching the basic body
202, the blaster nozzle 300 is fed through the machined opening 212
adjacent the proximal end 207 of the basic body 202, into and
through the longitudinal passage 225, into the entrance of the
elbow-shaped passage 230, and through that passage 230 to the exit
thereof located in the terminal portion 206, which is positioned
and oriented laterally against the earth formation in which a
lateral channel is to be completed.
[0075] Next, high pressure drilling fluid is pumped through the
high pressure hose 310, down to the blaster nozzle 300 at the end
thereof, so that the blaster nozzle 300 can bore a lateral channel
350 from the existing well adjacent the location where the well
casing and cement encasement previously were severed (See FIG. 10).
Nozzle blaster operations using high pressure fluid, such as water
with or without abrasive component additives at pressures ranging
from 2000-25,000 psi, generally are known in the art, and are
described, e.g., in the aforementioned U.S. patents which have been
incorporated herein. Generally, any suitable blaster nozzle and/or
high pressure hose can be used so long as the blaster nozzle and
hose can negotiate the longitudinal passage 225 and the
elbow-shaped passage 230 of the lateral channel alignment tool 200.
High pressure hose 310 is fed continuously from the surface until a
lateral channel 350 of desired length has been completed, at which
point the hose 310 is withdrawn at least to a sufficient extent to
withdraw the blaster nozzle 300 from the newly bored lateral
channel 350 in the earth strata. If it is desired to complete more
than one lateral channel at the same depth, then the alignment tool
200 simply is rotated from the previously completed lateral channel
and the process is repeated for a second lateral channel, and a
third, and so on. It will be evident one can complete multiple
lateral channels at a given depth without having to repeat a well
perforating operation.
[0076] To remove the alignment tool 200, it is simply withdrawn in
a conventional manner. The curved transition surface 290 between
the first and terminal portions 205 and 206 acts as a cammed
surface essentially forcing the alignment member 204 back into the
extended position so that it can be withdrawn from the well casing.
Alternatively, if it is desired to feed the alignment tool 200
deeper than the groove 425, for example down to a deeper groove 425
cut in the same well to complete additional lateral channels at a
greater depth, the biasing mechanism can be provided such that it
can be actuated to retain the member 204 in the extended position
until the terminal portion 206 has exceeded the depth of the first
groove. Then the biasing mechanism is de-actuated and once again is
effective to bias the member 204, and terminal portion 206, against
the well casing so it will automatically lock into place when the
next-deeper groove in the casing 400 is reached. Servos and other
actuating mechanisms and methods generally are known in the art.
For example, when a gas or hydraulic compression cylinder 250 is
used, gas or hydraulic pressure can be supplied or withdrawn via a
hydraulic fluid line or gas manifold based on actuation signals
from an operator. The implementation of such methods is within the
skill of a person having ordinary skill in the art, and will not be
described further here.
[0077] In a further preferred embodiment, the perforating tool 100
is used and operated similarly as described above to perforate the
well casing 400 and to provide the circumferential groove 425 in
the cement encasement 450. In this embodiment, however, the
perforating tool 100 continues to operate so that the jets of
cutting fluid emitted from the lateral ports 120 in the cutting
tool 100 are directed at and cut away strata material beyond the
cement encasement 450, to provide a circumferential groove 426 cut
out of the earth strata. This mode of operation is illustrate with
respect to FIGS. 7a and 9a. As is seen in these figures, the result
of this procedure is to provide a circumferential groove 425/426
whose horizontal expanse (diameter) is substantially increased
compared to when only the groove 425 in the cement encasement 450
is provided (FIG. 7a). An advantage to this embodiment is that it
will accommodate even larger-diameter high-pressure hose for boring
a lateral channel from the original well bore (encased by casing
400), than if only the groove 425 is provided (described more fully
below). This is because the terminal portion 206 of the lateral
channel alignment tool 200 is permitted to extend even further
horizontally than before, into the newly-formed groove 426 in the
strata (FIG. 9a). Consequently, a larger lateral alignment member
204, having a larger elbow-shaped passage 230 that has an outside
bend (shown as the right-most broken line for passage 230 in FIG.
4a) with a greater radius of curvature R.sub.1, able to accommodate
a larger-diameter hose, can be used.
[0078] In a further embodiment illustrated in FIG. 20, the lateral
channel alignment tool 200 includes an extensible hose guide member
260 that is designed to extend or telescope from the distal end of
the terminal portion 206 to help guide the high-pressure hose into
engagement with the strata. As seen more clearly in FIG. 21, the
hose guide member 260 is preferably provided as a series of guide
sections 262, each having a horizontal and two opposing vertical
plate portions that cooperate to provide a substantially U-shaped
cross-section. The guide sections 262 can be made from a sheet of
material (such as metal) that can be bent to provide the respective
horizontal and vertical plate portions in a U-shaped configuration.
Each guide section 262 is joined to the adjacent guide section(s)
262 via a pivot joint 264, which can be a simple hinge. A locking
lip or flange 266 is provided extending forward from the underside
of the horizontal plate portion of each guide section 262. The
flange 266 has an upper surface that extends substantially parallel
to the bottom face of horizontal plate portion to which it is
attached. This flange 266 prevents the successive (next-forward)
horizontal plate portion of the next successive guide section 262a
from pivoting below the plane of the horizontal plate portion of
the instant guide section 262b (see FIG. 21). Thus, when fully
extended, all of the guide sections 262 cooperate to provide a
substantially U-shaped guide passageway 208 to guide and support a
high-pressure hose exiting the elbow-shaped passage 230 at the
terminal portion 206 of the lateral alignment member 204. The
vertically extending plate portions are not attached to adjacent
ones on adjacent guide portions 262. When the guide member 260
(including its discrete guide portions 262) is retracted within the
lateral alignment member 204, the vertical plate portions on
adjacent guide portions 262 are able to deflect so that the guide
portions 262 can pivot relative to one another for storage within a
receiving compartment (for example within the elbow-shaped passage
230) that has a curved or elbow shape in order to accommodate the
overall shape of the member 204. The guide member 260 can be
actuated (extended and retracted) using suitable or conventional
means, including through use of a small servo motor as known in the
art. Alternatively, it can be spring-loaded so that it is biased
into an extended position via a conventional spring mechanism, with
a wire line connected to the proximal end and threaded up to the
surface through the upset tubing 500. To extend the guide member
260, tension in the wire line can be relaxed, thus permitting
extension of the guide member 260 by action of the spring that
biases it in an extended position. When it is desired to retract
the guide member 260, tension can be applied to the wire line to
retract the guide member 260 back into the lateral alignment member
204, against the biasing action of the spring mechanism that is
used. The disclosed hose guide member 260 may be useful if, for
example, a groove is cut in the earth strata beyond the casing to a
diameter too large for the terminal portion of the member 204 to
reach in a fully engaged position. In this event, the hose guide
member 260 can be extended or telescoped horizontally outward,
toward the base of the groove cut in the strata, to help guide the
flexible hose into contact with the strata at an appropriate
location along a horizontal or lateral path, as seen in FIG.
9b.
[0079] The disclosed tools and methods provide several advantages
over conventional lateral drilling systems and techniques. One such
advantage is that it is not necessary to maintain any downhole
equipment at the exact depth and in precise alignment with a
previously cut small hole through the well casing in order to align
the blaster nozzle with the previously cut hole. With the apparatus
herein described, once the well perforating operation has been
completed and the well casing has been severed or perforated as
described above, the alignment tool 200 is inserted downhole into
the well casing and automatically locks into place once it reaches
the previously made well perforation. Furthermore, because the well
is severed/perforated substantially about its entire circumference,
a lateral channel boring operation can be performed in any compass
direction radially outward from the well casing and it is not
necessary to maintain the precise compass alignment of the
alignment tool 200. In addition, once a lateral channel has been
bored in one compass direction, the blaster nozzle and hose can be
withdrawn into the alignment member 204, the tool 200 can be
rotated to another compass direction, and an additional drilling
operation or operations can be performed at the same depth in
different compass directions without having to drill additional
holes or repeat a well perforating operation in the well
casing.
[0080] A further advantage, described briefly above, is that a
larger diameter high pressure hose and blaster nozzle can be used
for boring a lateral channel in the earth strata from an existing
oil or gas well than previously was possible with conventional
equipment in a well having the same diameter. This is because,
conventionally, the downhole "shoe" for redirecting the blaster
nozzle and associated high pressure hose incorporated a
longitudinal channel for receiving the blaster nozzle and high
pressure hose that was substantially centrally aligned along the
longitudinal axis of the well casing. Conversely, as can be see in
FIG. 4a, the longitudinal passage 225 and the longitudinal portion
of the elbow-shaped passage 230 are radially offset from the
longitudinal axis 201. In this construction, the radius of
curvature R.sub.1 (FIG. 4a) for the pathway of the high pressure
hose is substantially increased compared to the case when the
longitudinal passage is provided centered on the longitudinal axis.
As a result, larger diameter high pressure hose can be employed to
bore lateral channels into the earth strata, because the high
pressure hose does not need to bend as tightly to be redirected in
a lateral direction, so the binding that otherwise would occur from
tightly bending a larger diameter hose is avoided. Simply
off-setting the longitudinal passage 225 (and consequently
offsetting or providing a relatively large inlet of the
elbow-shaped passage 230), in conjunction with providing the groove
425 in the cement encasement 450 as described above, enables
larger-diameter hose to be used than conventionally for reasons
already described. However, as also described above, further
providing a groove 426 in the strata beyond the encasement 450
enables even larger-diameter hose to be used, because now the
radius of curvature for the outside bend of elbow-shaped passage
230 can be increased even more. The length of the lateral alignment
member 204 may need to increase in order that the radius of
curvature, R.sub.1, can increase sufficiently so that the
high-pressure hose will be directed along a substantially
horizontal course on exiting the elbow-shaped passage 230, despite
further horizontal penetration of the terminal portion 206 of the
lateral alignment member 204.
[0081] One advantage of larger diameter high pressure hose is that
higher volume flowrates of drilling fluid can be accommodated in
the hose. This is particularly useful when a portion of the
drilling fluid is used to provide forward thrust to the hose and
the blaster nozzle via thrusters provided in the hose (described
below), because high pressure jets of the fluid can exit the
thrusters to thrust the blaster nozzle forward without
substantially sacrificing the flow rate and pressure of the
drilling fluid in the blaster nozzle used to bore the lateral
channel.
[0082] In one embodiment, the high pressure hose includes or is
provided as a flexible hose assembly comprising a flexible hose
with thrusters and a blaster nozzle coupled to and in fluid
communication with the terminal end of the hose. With reference to
FIG. 14, there is shown generally a flexible hose assembly 10 for
completing a lateral channel in a general direction indicated by
the arrow B, which preferably comprises a blaster nozzle 300 and a
high pressure hose 310. High pressure hose 310 includes a plurality
of flexible hose sections 22, a pair of pressure fittings 23
attached to the ends of each hose section 22, and a plurality of
thruster couplings 12, each of which joins a pair of adjacent
pressure fittings 23. Hose assembly 10 comprises a blaster nozzle
300 at its distal end and is connected to a source (not shown) of
high pressure drilling fluid, preferably an aqueous drilling fluid,
preferably water, less preferably some other liquid, at its
proximal end. Couplings 12 are spaced at least, or not more than,
5, 10, 20, 30, 40, 50, 60, 70, 80, 90 or 100 feet apart from each
other in hose 310. The total hose length is preferably at least or
not more than 100 or 200 or 400 or 600 or 700 or 800 or 900 or 1000
or 1200 or 1400 or 1600 or 1800 or 2000 feet. Hose sections 22 are
preferably flexible hydraulic hose known in the art, comprising a
steel braided rubber-TEFLON (polytetrafluoroethylene) mesh,
preferably rated to withstand at least 5,000, preferably at least
10,000, preferably at least 15,000, psi water pressure. High
pressure drilling fluid is preferably supplied at at least 2,000,
5,000, 10,000, 15,000, or 18,000 psi, or at 5,000 to 10,000 to
15,000 psi. When used to drill laterally from a well, the hose
extends about or at least or not more than 7, 10, 50, 100, 200,
250, 300, 350, 400, 500, 1000, or 2000 feet laterally from the
original well. In one embodiment the hose extends about 440 feet
laterally from the original well.
[0083] As illustrated in FIG. 11, in one embodiment a thruster
coupling 12 comprises a coupling or fitting, preferably made from
metal, preferably steel, most preferably stainless steel, less
preferably aluminum. Less preferably, coupling 12 is a fitting made
from plastic, thermoset, or polymeric material, able to withstand
5,000 to 10,000 to 15,000 psi of water pressure. Still less
preferably, coupling 12 is a fitting made from ceramic material. It
is important to note that when a drilling fluid other than water is
used, the material of construction of the couplings 12 must be
selected for compatibility with the drilling fluid and yet still
withstand the desired fluid pressure. Coupling 12 has two threaded
end sections 16 and a middle section 14. Preferably, end sections
16 and middle section 14 are formed integrally as a single solid
part or fitting. Threaded sections 16 are female-threaded to
receive male-threaded pressure fittings 23 which are attached to,
preferably crimped within the ends of, hose sections 22 (FIG.
14).
[0084] Alternatively, the fittings 23 can be attached to the ends
of the hose sections 22 via any conventional or suitable means
capable of withstanding the fluid pressure. In the illustrated
embodiment, each fitting 23 has a threaded portion and a crimping
portion which can be a unitary or integral piece, or a plurality of
pieces joined together as known in the art. Alternatively, the
threaded connections may be reversed; i.e. with male-threaded end
sections 16 adapted to mate with female-threaded pressure fittings
attached to hose sections 22. Less preferably, end sections 16 are
adapted to mate with pressure fittings attached to the end of hose
sections 22 by any known connecting means capable of providing a
substantially water-tight connection at high pressure, e.g.
5,000-15,000 psi. Middle section 14 contains a plurality of holes
or thruster ports 18 which pass through the thickness of wall 15 of
coupling 12 to permit water to jet out. Though the thruster ports
18 are shown having an opening with a circular cross-section, the
thruster port openings can be provided having any desired cross
section; e.g. polygonal, curvilinear or any other shape having at
least one linear edge, such as a semi-circle.
[0085] Coupling 12 preferably is short enough to allow hose 310 to
traverse the elbow-shaped passage 230 in the alignment member 204.
Therefore, coupling 12 is formed as short as possible, preferably
having a length of less than about 3, 2, or 1.5 inches, more
preferably about 1 inch or less than 1 inch. Hose 310 (and
therefore couplings 12 and hose sections 22) preferably has an
outer diameter of about 0.25 to about 3 inches, more preferably
about 0.375 to about 2.5 inches, and an inner diameter preferably
of about 0.5-2 inches. Couplings 12 have a wall thickness of
preferably about 0.025-0.25, more preferably about 0.04-0.1,
inches.
[0086] Optionally, hose 310 is provided with couplings 12 formed
integrally therewith, or with thruster ports 18 disposed directly
in the sidewall of a contiguous, unitary, non-sectioned hose at
spaced intervals along its length (see FIG. 16). A hose so
comprised obviates the need of threaded connections or other
connecting means as described above.
[0087] In the embodiments shown in FIGS. 11 and 17, thruster ports
18 have hole axes 20 which form a discharge angle .beta. with the
longitudinal axis of the coupling 12. The discharge angle .beta. is
preferably 5.degree. to 90.degree., more preferably 10.degree. to
90.degree., more preferably 10.degree. to 80.degree. , more
preferably 15.degree. to 70.degree. , more preferably 20.degree. to
60.degree. , more preferably 25.degree. to 55.degree. , more
preferably 30.degree. to 50.degree., more preferably 40.degree. to
50.degree., more preferably 40.degree. to 45.degree. , more
preferably about 45.degree.. The thruster ports 18 are also
oriented such that a jet of drilling fluid passing through them
exits the coupling 12 in a substantially rearward direction; i.e.
in a direction such that a centerline drawn through the exiting jet
forms an acute angle (discharge angle .beta.) with the longitudinal
axis of the flexible hose rearward from the location of the
thruster port, toward the proximal end of the hose assembly. In
this manner, high-pressure jets 30 emerging from thruster ports 18
impart forward drilling force or thrust to the blaster nozzle, thus
forcing the blaster nozzle forward into the earth strata (see FIG.
14). As illustrated in FIG. 12, a plurality of thruster ports 18
are disposed in wall 15 around the circumference of coupling 12.
There are 2 to 6 or 8 ports, more preferably 3 to 5 ports, more
preferably 3 to 4 ports. Thruster ports 18 are spaced uniformly
about the circumference of coupling 12, thus forming an angle
.alpha. between them. Angle .alpha. will depend on the number of
thruster ports 18, and thus preferably will be from 45.degree. or
60.degree. to 180.degree. , more preferably 72.degree. to
120.degree., more preferably 90.degree. to 120.degree.. Thruster
ports 18 are preferably about 0.010 to 0.017 inches, more
preferably 0.012 to 0.016 inches, more preferably 0.014 to 0.015
inches in diameter.
[0088] As best seen in FIGS. 11-13, thruster ports 18 are formed in
the wall 15 of coupling 12, extending in a substantially rearward
direction toward the proximal end of the hose assembly 10,
connecting inner opening 17 at the inner surface of wall 15 with
outer opening 19 at the outer surface of wall 15. The number of
couplings 12, as well as the number and size of thruster ports 18
depends on the desired drilling fluid pressure and flow rate. If a
drilling fluid source of only moderate delivery pressure is
available, e.g. 5,000-7,000 psi, then relatively fewer couplings 12
and thruster ports 18, as well as possibly smaller diameter
thruster ports 18 should be used. However, if higher pressure
drilling fluid is supplied, e.g. 10,000-15,000 psi, then more
couplings 12 and thruster ports 18 can be utilized. The number of
couplings 12 and thruster ports 18, the diameter of thruster ports
18, and the initial drilling fluid pressure and flow rate are all
adjusted to achieve flow rates through blaster nozzle 300 of 1-10,
more preferably 1.5-8, more preferably 2-6, more preferably
2.2-3.5, more preferably 2.5-3, gal/min. It is also to be noted
that because larger diameter hose can be used than conventionally
was possible, larger diameter or a greater number of thruster ports
18 also can be used to supply greater drilling thrust without
adversely impacting the pressure or flow rate of drilling fluid at
the blaster nozzle. This is a substantial advancement over the
prior art.
[0089] In one embodiment illustrated in FIG. 11, the thruster ports
18 are provided as unobstructed openings or holes through the side
wall of the thruster coupling 12. The ports 18 are provided or
drilled at an angle so that the exiting pressurized fluid jets in a
rearward direction as explained above.
[0090] In a further embodiment illustrated in FIG. 17, the thruster
couplings 12 and thruster ports 18 are similarly provided as
described above shown in FIG. 11, except that the thruster ports 18
are adjustable, including a shutter 31. The shutter 31 is
preferably an iris as shown in FIG. 17, and shown close-up in FIG.
19. The shutter 31 is actuated by a servo controller 32 (pictured
schematically in the figures) which is controlled by an operator at
the surface via wireline, radio signal or any other suitable or
conventional means. The servo controller 32 is preferably provided
in the sidewall of the coupling 12 as shown in FIG. 18, or is
mounted on the inner wall surface of the coupling 12. The servo
controller 32 has a small stepping motor to control or actuate the
shutter 31 to thereby regulate the diameter or area of the opening
34 for the thruster port 18. A fully open shutter 31 results in the
maximum possible thrust from the associated thruster port 18
because the maximum area is available for the expulsion of high
pressure fluid. An operator can narrow the opening 34 by closing
the shutter 31 to regulate the amount of thrust imparted to the
hose assembly by the associated thruster port 18. The smaller
diameter the opening 34, the less thrust provided by the thruster
port 18. Although an iris is shown, it will be understood that
other mechanisms can be provided for the shutter 31 which are
conventional or which would be recognized by a person of ordinary
skill in the art; e.g. sliding shutter, flap, etc. The servo
controller 32 is preferably a conventional servo controller having
a servo or stepping motor that is controlled in a conventional
manner. Servo controllers are generally known or conventional in
the art.
[0091] In a further preferred embodiment, the thruster ports 18 can
be provided so that different ones of them are opened, permitting
the jetting of water from those ports, based on the fluid pressure
in the high-pressure hose. For example, the thruster ports 18 can
be provided as or incorporating fluid check valves or
normally-closed relief valves (schematically illustrated at 38--See
FIG. 17a) as known in the art. Such valves prevent the flow of
fluid (from the hose, through the valve 38 and into the space
surrounding the hose) below a certain `cracking pressure,` which is
characteristic of each valve 38. Below the cracking pressure for
the valve 38, no flow is permitted; hence that thruster port 18 is
off. At the cracking pressure, however, fluid begins to be emitted
from the valve 38 and the thruster port 18 is turned on. Above the
cracking pressure, the valve opens fully and maximum flow of the
fluid jet through that thruster port 18 is achieved.
[0092] In an exemplary embodiment, all the thruster ports 18 in the
same thruster coupling 12 can be provided as check valves or relief
valves having the same cracking pressure. Couplings 12 with valves
of successively increasing cracking-pressure valves can be provided
along the length of the flexible hose. For example, the
lowest-cracking-pressure valves 38 can be provided in the hose
proximate the distal end where the blaster nozzle 300 is cutting
the strata. This way, the thruster ports 18 nearest the blaster
nozzle 300 are always or nearly always open, providing thrust to
the blaster nozzle 300 from a position just behind that nozzle.
Also, the rearwardly-directed thruster ports 18 nearest the blaster
nozzle 300 continuously sweep freshly made cuttings backward so
they are less likely to interfere with continued operation of the
blaster nozzle. The cracking pressure of more proximally-located
thruster ports 18 (in thruster couplings 12) are higher so that
they are not opened unless an operator selects a higher operating
fluid pressure for the drilling operation. This may provide a more
efficient method of operation because the rearward-most thruster
ports 18, which are least able to impart useful thrust to the
blaster nozzle 300, are only open when sufficient pressure and flow
is employed so that the pressure and flowrates at the blaster
nozzle 300 do not suffer from significant fluid and pressure
exiting through the whole series of thruster ports 18 disposed
along the entire length of the high-pressure hose (which can be
several hundred feet or yards, or even greater.
[0093] Alternatively, other arrangements of pressure-actuated
thruster ports 18 also can be used, and the foregoing arrangement
with increasing cracking pressures distal-to-proximal in the
high-pressure hose merely illustrates a preferred embodiment.
[0094] In addition to providing thrust, the thruster ports 18 also
provide another desirable function. Thruster ports 18 keep the bore
clear behind blaster nozzle 300 as the rearwardly jetting high
pressure drilling fluid (water) washes the drill cuttings out of
the lateral bore so that the cuttings do not accumulate in the
lateral bore. The high pressure drilling fluid forced through the
thruster ports 18 also cleans and reams the bore by clearing away
any sand and dirt that has gathered behind the advancing blaster
nozzle 300, as well as smoothing the wall of the freshly drilled
bore.
[0095] This is a desirable feature because, left to accumulate, the
cuttings and other debris can present a significant obstacle to
lateral boring, effectively sealing the already-bored portion of
the lateral bore around the advancing hose assembly 10. This can
make removal of the hose assembly 10 difficult once boring is
completed. In a worst case, the remaining debris can cause the
lateral bore to reseal once the hose assembly 10 has been
withdrawn. By forcing these cuttings rearward to exit the lateral
bore, the rearwardly directed drilling fluid jets 30 ensure the
lateral bore remains substantially open and clear after boring is
completed and the hose assembly 10 is removed. By providing the
thruster ports 18 along substantially the entire length of the hose
assembly 10, drill cuttings can be driven out of the lateral bore
from great distances, preferably at least 50, 100, 200, 250, 300,
350, 400, 500, 1000, or more, feet.
[0096] In one embodiment, adjustable thruster ports 18 are operated
sequentially such that when a thruster port or a group of
longitudinally aligned thruster ports is closed, the next-most
proximal thruster port or group of longitudinally aligned thruster
ports is opened, thereby sweeping cuttings in a proximal direction
out from the lateral channel and into the existing well. In this
method, the benefits of sweeping the cuttings out of the lateral
channel are obtained, while only a relatively small number of the
thruster ports 18 is open at any one time. The result is that
drilling fluid pressure through the blaster nozzle is maximized,
while drilling thrust and lateral channel sweeping is provided by
the sequentially operated thruster ports.
[0097] Blaster nozzle 300 is of any type that is known or
conventional in the art, for example, the type shown in FIGS.
15a-15b. In the illustrated embodiment, blaster nozzle 300
comprises a plurality of holes 50 disposed about a front portion
46a which preferably has a substantially domed shape. Holes 50 are
positioned to form angle .theta. with the longitudinal axis of
blaster nozzle 300. Angle .theta. is 10.degree.-30.degree., more
preferably 15.degree.-25.degree., more preferably about 20.degree..
Blaster nozzle 300 also comprises a plurality of holes 46b, which
are oriented in a reverse or rearward direction on a rear portion
60 of blaster nozzle 300, the direction and diameter of holes 46b
being similar to that of thruster ports 18 disposed around
couplings 12. Holes 46b serve a similar function as thruster ports
18 to impart forward drilling force to blaster nozzle 300 and to
wash drill cuttings rearward to exit the lateral bore. Optionally,
front portion 46a is rotatably coupled to rear portion 60, with
holes 50 oriented at an angle such that exiting high-pressure
drilling fluid imparts rotational momentum to front portion 46a,
thus causing front portion 46a to rotate while drilling. Rear
portion 60 is either fixed with respect to hose 310 unable to
rotate, or is rotatably coupled to hose 310 thus allowing rear
portion 60 to rotate independently of hose 310 and front portion
46a. In this embodiment, holes 46b are oriented at an angle
effective to impart rotational momentum to rear portion 60 upon
exit of high-pressure drilling fluid, thus causing rear portion 60
to rotate while drilling. Holes 50 and 46b can be oriented such
that front and rear portions (46a and 60 respectively) rotate in
the same or opposite directions during drilling.
[0098] The hose assembly 10 may be provided with a plurality of
position indicating sensors 35 along its length. Position
indicating sensors 35 are shown schematically in FIG. 14 attached
to the thruster couplings 12 and blaster nozzle 300. Alternatively,
the position indicating sensors 35 can be provided in the coupling
walls, or in the hose wall along its length. The position
indicating sensors 35 can emit a radio signal or can be monitored
by wireline from the surface to determine the location and
configuration of the flexible hose. The adjustable thruster ports
18 can be controlled based on position and configuration
information received from these position indicating sensors 35.
Preferably, a computer receives information from the position
indicating sensors 35 and regulates the adjustable thrusters based
on that information to achieve the desired position control of the
hose assembly 10 as it drills a lateral bore.
[0099] Although the hereinabove described embodiments of the
invention constitute preferred embodiments, it should be understood
that modifications can be made thereto without departing from the
spirit and the scope of the invention as set forth in the appended
claims.
* * * * *