U.S. patent application number 10/854971 was filed with the patent office on 2004-12-30 for method and apparatus for multilateral junction.
This patent application is currently assigned to Smith International, Inc.. Invention is credited to Allison, Glenn L., Desai, Praful C., Dewey, Charles H., McGarian, Bruce H..
Application Number | 20040262006 10/854971 |
Document ID | / |
Family ID | 22934369 |
Filed Date | 2004-12-30 |
United States Patent
Application |
20040262006 |
Kind Code |
A1 |
Dewey, Charles H. ; et
al. |
December 30, 2004 |
Method and apparatus for multilateral junction
Abstract
A junction for the intersection of a main borehole and a lateral
borehole includes a main tubular having a main window with a ramp
aligned with the main window and a lateral tubular adapted to be
telescopingly received within the main tubular and having a lateral
window. The main tubular and lateral tubular each have an
orientation surface. The lateral tubular has a first position with
one end partially disposed within the main tubular. The lateral
tubular is telescoped into the main tubular with the end of the
lateral tubular engaging the ramp which guides the end of the
lateral tubular through the main window and into the lateral bore.
The orientation surfaces engage to orient the lateral window with
the main window and form a common opening between the tubulars.
Inventors: |
Dewey, Charles H.; (Houston,
TX) ; Allison, Glenn L.; (Spring, TX) ; Desai,
Praful C.; (Kingwood, TX) ; McGarian, Bruce H.;
(Stonehaven, GB) |
Correspondence
Address: |
CONLEY ROSE, P.C.
P. O. BOX 3267
HOUSTON
TX
77253-3267
US
|
Assignee: |
Smith International, Inc.
16740 Hardy Street
Houston
TX
77032
|
Family ID: |
22934369 |
Appl. No.: |
10/854971 |
Filed: |
May 27, 2004 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
10854971 |
May 27, 2004 |
|
|
|
09992219 |
Nov 6, 2001 |
|
|
|
6752211 |
|
|
|
|
60247295 |
Nov 10, 2000 |
|
|
|
Current U.S.
Class: |
166/313 ;
166/117.6; 166/50 |
Current CPC
Class: |
E21B 41/0042 20130101;
E21B 17/07 20130101; E21B 43/305 20130101 |
Class at
Publication: |
166/313 ;
166/050; 166/117.6 |
International
Class: |
E21B 007/06 |
Claims
What is claimed is:
1. An apparatus comprising: a tubular borehole casing having an
inner surface and a casing aperture in one side thereof; a tubular
having a cylindrical portion with an opening in one side thereof;
an orienting member disposed on said inner casing surface above
said casing aperture; and wherein said tubular has a first position
with said casing and said tubular being coaxial and a second
position with said tubular engaged with said orienting device, said
tubular opening substantially aligned with said casing aperture and
said tubular cammed out said casing aperture with one end of said
tubular projecting from said casing aperture.
2. The apparatus of claim 1 wherein said casing aperture and
tubular opening form a common window between said casing and
tubular.
3. The apparatus of claim 1 wherein said tubular further includes
an orienting member disposed on an outer surface of said tubular
cylindrical portion above said tubular opening, wherein said
tubular orienting member is configured to mate with said casing
orienting member.
4. The apparatus of claim 1 further comprising a deflector disposed
inside said borehole casing below said casing aperture.
5. The apparatus of claim 1 wherein said casing aperture forms
opposing edges providing a ramp adjacent said casing aperture.
6. The apparatus of claim 4 wherein said ramp includes an arcuate
surface cut at an angle in said tubular.
7. A method of deploying a Y junction, the method comprising:
pre-milling an aperture in a portion of borehole casing, said
aperture forming opposing edges providing a guide surface adjacent
said aperture; inserting one end of a tubular into said borehole
casing portion; further inserting said tubular into said casing
portion against said guide surface in said casing portion; guiding
said one end of said tubular along said guide surface through said
casing aperture; and extending said one end of said tubular through
said aperture with another end of said tubular remaining in said
casing portion to form a Y junction.
8. A method of deploying a Y junction, the method comprising:
inserting one end of a tubular into a borehole casing portion, said
casing portion having an aperture in one side thereof and said
tubular having an opening in one side thereof; further inserting
said tubular into said casing portion toward said aperture; camming
said one end of said tubular through said aperture; orienting said
tubular and said casing portion using cooperative orientation
surfaces on said tubular and said casing portion such that said
opening and said aperture align with each other; extending said one
end of said tubular through said aperture with another end of said
tubular remaining in said casing portion; and mating said
orientation surfaces to form a Y junction wherein said opening and
said aperture form a common window.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is a continuation of prior U.S. application
Ser. No. 09/992,219, filed Nov. 6, 2001, which claims the benefit
of 35 U.S.C. .sctn. 119(e) of U.S. Provisional Application No.
60/247,295, filed Nov. 10, 2000 and entitled "Method And Apparatus
For Multilateral Completions," hereby incorporated herein by
reference for all purposes.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not applicable.
BACKGROUND OF THE INVENTION
[0003] 1. Field of the Invention
[0004] The present invention relates generally to a method and
apparatus for the completion of multilateral wells, that is, when
one or more lateral wells are drilled from a primary well bore, and
more particularly to a new and improved method and apparatus for a
junction between the primary well bore and a lateral well bore.
[0005] 2. Background of the Invention
[0006] Multiple lateral bores are typically drilled and extended
from a primary or main well bore. The main well bore can be
vertical, deviated, or horizontal. Multilateral technology can be
applied to both new and existing wells, and provides operators
several benefits and economic advantages over drilling entirely new
wells from the surface. For example, multilateral technology can
allow isolated pockets of hydrocarbons, which might otherwise be
left in the ground, to be tapped. In addition, multilateral
technology allows the improvement of reservoir production,
increases the volume of recoverable reserves, and enhances the
economics of marginal pay zones. By using multilateral technology,
multiple reservoirs can be produced simultaneously, thus
facilitating heavy oil production. Thin production intervals that
might be uneconomical to produce alone become economical when
produced together with multilateral technology. Consequently, it
has become a common practice to drill deviated, and sometimes
horizontal, lateral boreholes from a primary wellbore in order to
increase production from a well.
[0007] In addition to production cost savings, development costs
also decrease through the use of existing infrastructure, such as
surface equipment and the well bore. Multilateral technology
expands platform capabilities where space is limited, and allows
more well bores to be added to produce a reservoir without
requiring additional drilling and production space on the platform.
In addition, by sidetracking depleted formations or completions,
the life of existing wells can be extended. Finally, multilateral
completions accommodate more wells with fewer footprints, making
them ideal for environmentally sensitive or challenging areas.
[0008] The primary wellbore may be sidetracked to produce the
lateral borehole into another production zone. Further, a lateral
wellbore may be sidetracked into a common production zone. In
sidetracking, a whipstock and mill assembly is used to create a
window in the wall of the casing of a wellbore. The lateral
wellbore is then drilled through this window out into the formation
where new or additional production can be obtained.
[0009] One of the objectives of a multilateral well is containment
of the surrounding formation. Production from a lateral borehole
can be difficult if the lateral borehole is drilled through a loose
or unconsolidated formation. If the lateral borehole is drilled
through an unstable or unconsolidated formation, the formation will
tend to cave into the borehole. The formation can also slough off,
causing deleterious debris to mix with the production fluids. Thus,
it is preferred to contain the formation to prevent cave-ins and
slough-offs.
[0010] Formations that contain a significant amount of shale can be
a particular problem. If the bore surfaces at and near the junction
are not covered with a liner, chips and aggregate in this area tend
to be drawn into the produced fluids and foul the production.
Unfortunately, lining the bore surfaces near the junction can be
complex and time consuming. Various devices have been proposed to
provide a junction at the interface of the primary and lateral
wellbores.
[0011] There have been attempts to use a perforated insert through
the window to allow production from both the primary bore and
lateral bore while reducing contamination from chips and aggregate.
The perforations are aligned with the primary bore and fluid from
the primary bore passes through the perforations. Unfortunately,
the perforations tend to become clogged by the chips and aggregate
and allow the chips and aggregate to contaminate the product,
thereby reducing the effectiveness of this type of insert. Also,
the use of a perforated insert hinders the ability to reenter the
main bore below the junction.
[0012] The junction of the lateral borehole with the primary
wellbore is usually ragged and rough as a result of the milling of
the window through the casing to drill the lateral borehole. It is
particularly difficult to seal around the window which is of a
peculiar shape and has a jagged edge around its periphery.
[0013] A large area is exposed to the formations when the window is
cut in the casing. A tie-back assembly may be disposed adjacent the
junction of the lateral borehole and primary wellbore. See for
example U.S. Pat. No. 5,680,901. The tieback assembly and liner
limit the exposure of the formation through the window cut in the
casing.
[0014] U.S. Pat. No. 5,875,847 discloses a multilateral sealing
device comprising a casing tool having a lateral root premachined
and plugged with cement. A profile receives a whipstock for the
drilling of the lateral bore hole through the lateral root and
cement plug. A lateral liner is then inserted and sealed within the
lateral root.
[0015] TAML (Technology Advancement Multi-Lateral) defines six
levels for a multi-lateral junction for a lateral borehole. For
example, level three merely includes a junction with the main
casing and a liner extending into the lateral borehole without
cementing or sealing the junction. If the liner is merely cemented
at the junction, it is a level four since cement is not acceptable
as a seal. Level four simply includes cement around the junction.
Level five requires pressure integrity at the junction.
[0016] Prior art multilateral wells are sealed with cement using a
method well-known to those with skill in the art and described
hereinafter.
[0017] Level five includes seals used to achieve pressure integrity
around the junction. For example, in level five, separate tubulars
extend through the main borehole and through the lateral borehole.
A packer is placed around the upper ends of these tubulars to pack
off with the casing of the cased main borehole. The lower end of
the tubular extending through the main tubular includes a packer
for sealing with the main tubular below the junction, and the lower
end of the other tubular extending through the lateral borehole
seals with an outer tubular in the lateral borehole below the
junction. The lateral borehole preferably has been previously cased
so that a seal can be set with that tubular extending into the
lateral borehole. Since there are separate tubulars and both bores
are now packed off, there can be independent production from each
bore without commingling. The pair of tubulars above the junction
may extend all the way to the surface, or one well may be produced
through a production pipe extending to the surface and the other
well may be produced through the annulus formed by the casing and
the production pipe extending to the surface.
[0018] Where the formation pressure is substantially the same in
the pay zones being produced by the main and lateral boreholes, the
hydrocarbons from the main and lateral boreholes may be commingled.
However, it is sometimes desirable to separate production so that
each well can be independently controlled, such as where the pay
zone pressures are different. In that case, separate tubulars are
used to produce the individual wells, as previously described in a
level five junction, or one well may be plugged off if necessary.
Whether production is commingled or independent has no bearing on
how a multilateral well is classified.
[0019] If the formation is a solid formation, the lateral borehole,
for example, need not even include a casing or liner and may be
produced open hole. If the lateral borehole is unconsolidated or
unstable and would tend to cave in, the lateral borehole would be
cased off or include a liner to contain the formation. For example,
it is common in the prior art to run and set a liner in the lateral
borehole with the liner extending from the flowbore of the casing
and down into the lateral borehole. Cement is then pumped down
through the cased main borehole, across the junction into the
lateral borehole below the junction, and into the lateral borehole
both inside and outside the liner. Then, the bore of the cased main
borehole is cleaned out by drilling out the cement, including
milling off that portion of the liner extending into the bore of
the cased main borehole, leaving an exposed end of the liner at the
junction which extends into the lateral borehole. The liner is then
cleaned out giving access to both the main and lateral boreholes.
This procedure is tedious and includes the problem of the drill
tending to enter the liner as it removes the cement and liner end
from the main borehole. This method is also problematic because the
cement acts as both the junction and the seal. The cement is
subject to failure due to limitations in the cement material itself
or the ability to place the cement successfully at the junction.
More particularly, under downhole conditions, cement can fail by
deteriorating to such an extent that the seal begins to leak thus
contaminating the production fluids.
[0020] An alternative to the above-described method is described in
pending U.S. patent application Ser. No. 09/480,073, filed Jan. 10,
2000 and entitled "Lateral Well Tie-Back Methods and Apparatus." A
lateral well tie-back apparatus and method is used to help ensure
adequate flow and production from a lateral bore.
[0021] There are a variety of additional configurations that are
possible when performing multilateral completions. For example,
U.S. Pat. No. 4,807,704 discloses a system for completing multiple
lateral wellbores using a dual packer and a deflective guide
member. U.S. Pat. No. 2,797,893 discloses a method for completing
lateral wells using a flexible liner and deflecting tool. U.S. Pat.
No. 3,330,349 discloses a mandrel for guiding and completing
multiple lateral wells. U.S. Pat. Nos. 4,396,075, 4,415,205,
4,444,276, and 4,573,541 all relate generally to methods and
devices for multilateral completion using a template or tube guide
head. For a more comprehensive list of patents, U.S. Pat. No.
6,012,526 details these configurations and presents a patent
literature history of the well-recognized problem of multilateral
wellbore completion.
[0022] Notwithstanding the above-described attempts at obtaining
cost effective and workable lateral well completions, there
continues to be a need for new and improved methods and devices for
providing such completions, particularly sealing between the
juncture of primary and lateral wells, the ability to re-enter
lateral wells, particularly in multilateral systems, and achieving
zone isolation between respective lateral wells in a multilateral
well system. The present invention relates to a new and improved
method and apparatus for the construction and completion of a
multilateral well junctions, and overcomes the deficiencies of the
prior art.
BRIEF SUMMARY OF THE INVENTION
[0023] A junction for the intersection of a main borehole and a
lateral borehole includes a main tubular having a main window with
a ramp aligned with the main window, and a lateral tubular adapted
to be telescopingly received within the main tubular and having a
lateral window. The main tubular and lateral tubular each have an
orientation surface. The lateral tubular has a first position with
one end partially disposed within the main tubular. The lateral
tubular is telescoped into the main tubular with the end of the
lateral tubular engaging the ramp which guides the end of the
lateral tubular through the main window and into the lateral bore.
The orientation surfaces engage to orient the lateral window with
the main window and form a common opening between the tubulars. The
ramp is preferably an arcuate surface at an angle to the axis of
the main tubular and extends along the edges of the main window
between the inner and outer diameters of the main tubular. The
orientation surfaces are preferably mule shoe surfaces which engage
to rotate the tubulars into alignment.
[0024] The junction may also include a shear member to releasably
connect the lateral tubular within the main tubular until the
junction is to be deployed. Once the lateral tubular is released,
preferably by shearing the shear member, it telescopes down into
the main tubular until the lateral tubular reaches the ramp
adjacent the main window. The ramp deflects the lateral tubular out
through the main window by engaging the end of the lateral tubular.
The lateral tubular has one end extending from the main tubular to
form the junction between the lateral borehole and the primary
borehole. The main tubular extends into the main borehole and the
lateral tubular extends into the lateral borehole.
[0025] The present invention is also directed to a method of
multilateral well completions. To create a lateral well bore, a
milling assembly is run into the main well bore to a desired depth
and orientation. An anchor and/or packer are set. If a well
reference member is not previously set, a reference member may also
be set on the same run. A window is milled in the cased borehole
and a lateral rat hole is drilled. The milling assembly and
whipstock are then removed. The junction with main tubular and
lateral tubular is run into the main bore in substantial alignment.
The lateral tubular is partially disposed within the main tubular
and is releasably held by a shear member. The main window becomes
aligned with the lateral rat hole when an orienting member at the
bottom of the main tubular engages the downhole well reference
member, thereby rotating and orienting the junction assembly.
[0026] A weight is applied to the lateral tubular causing the
lateral tubular to disengage the main tubular allowing the lateral
tubular to be received within the main tubular. Any misalignment
that occurs while the lateral tubular is deflected out of the main
window via the ramp is corrected when the lateral orientation
member engages the orientation surface of the main tubular. When
the lateral orientation member and the main orientation surface are
fully engaged, the lateral and main windows are substantially
aligned and facing each other to form the junction.
[0027] There are many benefits to using the present invention.
Critical work is done prior to exposing the time dependent
formations. A level four multilateral well can be achieved without
milling excess liner. A minimal amount of cementing is required,
although cementing is optional for the present invention. The
access diameters for both the main and lateral tubulars are
maximized. The present invention allows re-entry capabilities in
both bores.
[0028] Other objects and advantages of the invention will appear
from the following description.
BRIEF DESCRIPTION OF THE DRAWINGS
[0029] For a detailed description of the preferred embodiments of
the invention, reference will now be made to the accompanying
drawings in which:
[0030] FIG. 1 is a schematic view of the deployed junction disposed
within the main and lateral boreholes;
[0031] FIG. 2 is a side elevation view of the main tubular shown in
FIG. 1;
[0032] FIG. 3 is a front elevation view of the main tubular and
main window of FIG. 2;
[0033] FIG. 4 is a back view of the top portion of the main tubular
of FIG. 2;
[0034] FIG. 5A is a cross section view of the main tubular taken
along plane A-A of FIG. 2;
[0035] FIG. 5B is a cross section view of the main tubular taken
along plane B-B of FIG. 2;
[0036] FIG. 5C is a cross section view of the main tubular taken
along plane C-C of FIG. 3;
[0037] FIG. 5D is a cross section view of the main tubular taken
along plane D-D of FIG. 3;
[0038] FIG. 5E is a cross section view of the main tubular taken
along plane E-E of FIG. 3;
[0039] FIG. 6 is a side elevation view of the lateral tubular shown
in FIG. 1;
[0040] FIG. 7 is a front elevation view of the lateral tubular and
lateral window of FIG. 6;
[0041] FIG. 8 is an enlarged cross section view of the upper
portion of the lateral tubular of FIG. 6;
[0042] FIG. 9 is a side elevation view of the main tubular of FIG.
2 with an orientation member disposed therein;
[0043] FIG. 10 is an enlarged view of the orientation member of
FIG. 9;
[0044] FIG. 11A is a front elevation view of a deflector for use
with the junction of FIG. 1;
[0045] FIG. 11B is a front enlarged view of an orientation member
coupled to the lower end of the deflector of FIG. 11A;
[0046] FIG. 12 is a side cross section view of the deflector of
FIG. 11A;
[0047] FIG. 13A is a back elevation view of the deflector of FIG.
11A;
[0048] FIG. 13B is a back enlarged view of an orientation member
coupled to the lower end of the deflector of FIG. 13A;
[0049] FIG. 13C is a cross section view of the orientation member
and deflector taken along plane C-C of FIG. 13B;
[0050] FIG. 13D is a cross section view of the orientation member
and deflector taken along plane D-D of FIG. 13B;
[0051] FIG. 14A is an enlarged view of the upper end of the
deflector of FIG. 12;
[0052] FIG. 14B is a cross section view of the deflector taken
along plane B-B of FIG. 12;
[0053] FIG. 14C is a cross section view of the deflector taken
along plane C-C of FIG. 12;
[0054] FIG. 14D is a cross section view of the deflector taken
along plane D-D of FIG. 13A;
[0055] FIG. 14E is a cross section view of the deflector taken
along plane E-E of FIG. 13A;
[0056] FIG. 15A is an elevation view of the whipstock assembly
lowered into the primary borehole;
[0057] FIG. 15B is an elevation view of the mills forming a window
and drilling a rat hole;
[0058] FIG. 15C is an elevation view of the mills having been
retrieved and a drilling assembly having drilled a lateral
borehole;
[0059] FIG. 15D is an elevation view of the whipstock assembly
being retrieved from the borehole;
[0060] FIG. 15E is an elevation view with the main tubular and
lateral tubular being lowered into the main borehole in the
undeployed coaxial position;
[0061] FIG. 15F is an elevation view with the junction deployed at
the intersection of the main borehole and lateral borehole;
[0062] FIG. 15G is an elevation view of a deflector disposed within
the main tubular;
[0063] FIG. 15H is an elevation view a liner disposed through the
lateral tubular and into the lateral borehole;
[0064] FIG. 16 is a side elevation view of an alternative lateral
tubular without a main tubular;
[0065] FIG. 17 is a side elevation view of a well reference member
disposed in the main cased borehole above the lateral borehole;
and
[0066] FIG. 18 is a side elevation view of the lateral tubular of
FIG. 16 deployed in the lateral borehole of FIG. 17.
NOTATION AND NOMENCLATURE
[0067] Certain terms are used throughout the following description
and claims to refer to particular system components. This document
does not intend to distinguish between components that differ in
name but not function. In the following discussion and in the
claims, the terms "including" and "comprising" are used in an
open-ended fashion, and thus should be interpreted to mean
"including, but not limited to . . . ".
[0068] The present invention relates to methods and apparatus for
providing a junction around a window cut in a casing and extending
a liner into a lateral borehole. The present invention is
susceptible to embodiments of different forms. There are shown in
the drawings, and herein will be described in detail, specific
embodiments of the present invention with the understanding that
the present disclosure is to be considered an exemplification of
the principles of the invention, and is not intended to limit the
invention to that illustrated and described herein.
[0069] In particular, various embodiments of the present invention
provide a number of different constructions and methods of
operation. It is to be fully recognized that the different
teachings of the embodiments discussed below may be employed
separately or in any suitable combination to produce desired
results. Reference to up or down will be made for purposes of
description with "up" or "upper" meaning toward the surface of the
well and "down" or "lower" meaning toward the bottom of the primary
wellbore or lateral borehole.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0070] Referring initially to FIG. 1, a preferred embodiment of a
junction 10 is shown deployed to produce hydrocarbons from a pay
zone 12 through a primary borehole 14 and through a lateral
borehole 16. Junction 10 includes a main tubular 20 and a lateral
tubular 40 with the main tubular 20 extending into the primary
borehole 14 and the lateral tubular 40 having its upper end
disposed within an upper portion of the main tubular 20 and its
lower end extending into the lateral borehole 16. Lateral tubular
40 includes a window 42 aligned with a window 26 in main tubular 20
in the deployed position whereby the production from pay zone 12
through primary and lateral boreholes 14, 16 may be commingled for
flow to the surface 18.
[0071] Referring now to FIGS. 2-5, main tubular 20 includes a
tubular body 22 having an upwardly facing orientation surface 24
and a main window 26 extending from an arcuate cut out 27 below
orientation surface 24 to a full tubular portion 28 near the lower
end of main tubular 20. The inside diameter 31 in the upper portion
of tubular body 22 is larger than the inside diameter 33 in the
lower portion of tubular body 22. The lower terminal end 30 of
tubular body 22 includes a counterbore 32 forming a downwardly
facing annular shoulder 34 for use with a deflector hereinafter
described. It should be appreciated that the lower terminal end 30
may include a threaded connection for connecting a spline sub
hereinafter described. Best shown in FIG. 4, orientation surface 24
includes a pair of main cam surfaces 36a,b forming a mule shoe
extending from an apex 38 down into a recess or mule shoe slot
44.
[0072] Main window 26 includes a straight portion 46 and a ramp
portion 48. Straight portion 46 is an arcuate cross-sectional cut
out in tubular body 22 along the length of portion 46 having the
enlarged inner diameter 31.
[0073] Referring still to FIGS. 2-5, the ramp surface 50 is
initiated at point 54 by milling arcuate ramp portion 58 with the
inside diameter 31 below the top of window 26 and continuing out
the window 26 to point 54a. FIG. 5A is a cross section at point 56
of the arcuate ramp portion 58 where it begins to intersect reduced
diameter 33. The mill has milled the arcuate portion 58 into the
wall 60 of tubular body 22 and into the inner diameter of the wall
60 in the bottom face 64 of tubular body 22. FIG. 5B is a cross
section showing the arcuate rails 62a,b milled into the wall 60 of
tubular body 22 with the inner diameter of wall 60 achieving
reduced diameter 33. FIGS. 5C, D, E illustrate the arcuate rails
62a,b milled into wall 60 in tubular body 22 along the lower
portions of ramp 50. As best shown in FIG. 3, the lower end of ramp
50 is an arcuate milling at 66 in the outer surface of tubular body
22.
[0074] Ramp portion 48 is formed using a mill to cut a ramp surface
50 in a method similar to that used in milling a whip face on a
whipstock. The radius is cut on a taper like a whip face. It is not
cut coaxially with tubular body 22 but at an angle to the axis of
tubular 22. In cutting the ramp surface 50, the mill mills the
tubular body 22 as though it were a solid piece of metal such as in
a whipstock. Thus instead of milling an arcuate surface into a
solid member, the arcuate surface is milled into a tubular member.
The taper of the ramp 50 may be between 11/2 and 3.degree. and is
preferably 3.degree..
[0075] Referring now to FIGS. 6-8, lateral tubular 40 includes a
tubular body 68 having an orientation member 70, with a downwardly
facing orientation surface 72, affixed, such as by welding, to the
top of lateral tubular body 68, and a main window 42 extending from
an arcuate cut out 74 below orientation surface 72 to a full
tubular portion 76 near the lower end of lateral tubular 40. The
inner and outer diameters of lateral tubular body 68 are preferably
uniform along its length.
[0076] Orientation member 70 is a tubular member which is received
over the upper end of lateral tubular body 68 and then preferably
welded in place. Downwardly facing orientation surface 72 includes
a pair of lateral cam surfaces 84a,b forming a mule shoe extending
from a recess or mule shoe slot 86 down to an apex 88. Orientation
member 70 is preferably disposed on a separate member for ease of
manufacture of the downwardly facing orientation surface 72.
Further, orientation member 70 is a separate member to provide a
connection 90 for a running tool. Connection 90 includes a
counterbore 92 having a plurality of holes 94 which engage latching
members on the running tool. Connector 100 includes a plurality of
fingers 102 cut into the wall 95 of lateral tubular body 68.
Fingers 102 have latch pads 104 attached to the free end 106 of
fingers 102, such as by screws 108.
[0077] Lateral window 42 is a precut window cut into lateral
tubular body 68. There is no radius cut for the window 42 in
lateral tubular 40. The upper portion 110 of window 42 has straight
sides 112 and the lower portion of window 42 forms a hyperbolic
portion 114. When lateral window 42 is aligned with main window 26,
the upper terminal end 116 of lateral window 42 is approximately
adjacent point 54 on ramp 50 in main window 26 and hyperbolic
portion 114 is aligned with the lower hyperbolic portion 65 of main
window 26. When in such alignment, facing windows 26, 42 form a
common opening 120, best shown in FIG. 1, between main tubular 20
and lateral tubular 40 for the commingling of flow through the main
tubular 20 from the primary borehole 14 and through lateral tubular
40 from the lateral borehole 16. Windows 26, 42 serve to provide
full exposure of communication between main and lateral tubulars
20, 40.
[0078] The outer diameter of lateral tubular 40 is substantially
the same as the enlarged inner diameter 31 of main tubular 20 at
the top of main tubular 20 to point 54, below the top of window 26,
at which point the inner diameter 31 begins to decrease as
previously described. Only a small sliding clearance of about 0.060
of an inch is provided between main tubular 20 and lateral tubular
40 above point 54.
[0079] In the assembled but not yet deployed position, the lower
end 78 of lateral tubular 40 is inserted into the upper end 25 of
main tubular 20 and main and lateral tubulars 20, 40 oriented such
that mule shoe point 38 on main tubular 20 is aligned with slot 86
on lateral tubular 40. Likewise, apex 88 on lateral tubular 40 will
be aligned with slot 44 on main tubular 20. Since apex 88 is
aligned with the centerline of lateral tubular window 42 and mule
shoe point 38 is aligned with the centerline of main tubular window
26, in this position, orientation surfaces 24, 72 are now oriented
such that windows 26, 42 face each other.
[0080] Upon insertion and alignment, a shear pin 122 in the lower
end of lateral tubular 40 is inserted into an aperture 124 in the
upper end of main tubular 20 thereby attaching main and lateral
tubulars 20, 40 together for lowering into the primary borehole 14
from the surface 18. Preferably, the shear pin 122 is rated at
35,000 pounds. Shear screw 122 prevents premature setting of
lateral tubular 40 within main tubular 20 should main tubular 20
encounter drag in the casing or become hung up in the casing. The
shear screw 122 also permits pushing the main tubular 20 on the
lower end of lateral tubular 40 through the borehole, particularly
a horizontal borehole.
[0081] In another embodiment, the lateral tubular 40 may include a
connector like that of connector 100 to attach lateral tubular 40
to a recess in the upper end of main tubular 20 such as at 27. In
the preferred embodiment, should the shear pin 122 break
prematurely, the connector will maintain the main tubular 20
disposed on the lower end of lateral tubular 40.
[0082] In operation, the junction 10 is deployed by disposing the
main tubular 20 on the lower end of lateral tubular 40 using shear
pin 122. A running tool on the lower end of a work string is
releasably attached to the upper end of lateral tubular 40 by
connection 90. This assembly is lowered into the primary borehole
14 until the assembly engages a well reference member, hereinafter
described, which prevents the further downward movement of the main
tubular 20 within the primary borehole 14. Weight is placed on the
assembly causing shear pin 122 to shear disconnecting lateral
tubular 40 from main tubular 20 and allowing the lateral tubular 40
to slide down into main tubular 20.
[0083] As the lower terminal end 78 of lateral tubular 40 moves
through the top of main tubular 20, end 78 engages the beginning of
ramp 50. End 78 first rides up the ramp 50 beginning at point 54
and cams lateral tubular 40 outward through main window 26. At
about point 56 end 78 begins to ride the rails 62a,b which are
initially in the interior walls 60 of main tubular 20. Arcuate
surfaces milled into main window 26 of main tubular 20 form a ramp
profile along the edges of window 26. This profile or ramp on the
inner sides of main tubular 20 are cut into the wall 60 of main
tubular 20, thereby reducing its equivalent diameter as shown in
FIGS. 2 and 5A-E. As best shown in FIG. 5, the opposing arcuate
rails 62a,b formed by the edges of open main window 26 then engage
and guide the lower end 78 of lateral tubular 40 out through window
26.
[0084] Summarizing, the lower end 78 engages ramp 50, initially
being guided by a ramp from points 54 to 56, then the rails 62a,b
in the inner diameter of the walls 60 of main tubular 20 and then
finally rides up rails 62a,b along the edges of window 26 and out
through the lower end of window 26. Thus the ramp 50 deflects the
lower end 78 of lateral tubular 40 outwardly through main window
26. It should be appreciated that the lateral tubular 40 may have
any predetermined length as required for the lateral borehole
16.
[0085] Referring again to FIG. 1, near the end of travel of the
lateral tubular 40 through main tubular 20, apex 88 will engage
orientation surfaces 36a,b and mule shoe point 38 will engage the
orientation surfaces 84a,b. As apex 88 and mule shoe point 38 ride
along these orientation surfaces 36, 84, the lateral tubular 40
will rotate into proper orientation with main tubular 20 thereby
aligning lateral window 42 with main window 26. Recess 44 shown in
FIG. 4 receives apex 88 and recess 86 receives mule shoe point 38.
Recesses 44, 86 avoid the additional expense of completing the
contour of orientation surfaces 36, 84.
[0086] As illustrated in FIG. 1, in the preferred embodiment, in
the deployed position, the lateral tubular 40 forms a Y junction
with main tubular 20. Connector 100 connects lateral tubular 40
with main tubular 20 by engaging end 27 on main tubular 20.
[0087] In an alternative embodiment, the inner diameter 31 of
tubular body 22 above and along the junction may be sized to
receive two conduits that may be sealed off inside the main tubular
20, such as when the production fluids from the primary borehole 14
and the lateral borehole 16 are from different pay zones. The two
conduits extend through the upper portion of main tubular 20 with
one conduit then extending through main tubular 20 and the other
independent conduit extending through lateral tubular 40.
Additional clearance may be obtained through main tubular in
reduced diameter 33 by increasing the inner diameter along the ramp
50 where the inner diameter is smaller. This can be achieved by
scaling back the inner diameter portions between opposing arcuate
rails 62a,b. Thus rails 62a,b remain intact while the portion of
main tubular 20 remaining after milling window 26 can be reduced to
enlarge inner diameters.
[0088] Referring now to FIGS. 9 and 10, another preferred
embodiment of the present invention includes an orientation member
130 disposed in the lower end 30 of main tubular 20. The
orientation member 130 includes a tubular body having an upwardly
facing orientation member or mule shoe 134 used to orient
subsequent tools lowered through the primary borehole 14 below the
junction with lateral borehole 16. The mule shoe 134 has a reduced
outer diameter 136 forming an upwardly facing annular shoulder 138
which engages the lower terminal end 30 of main tubular 20. Upon
orienting the mule shoe 134 with the window 26 and orientation
surface 24, orientation member 130 is welded to the lower end of
main tubular 20 at 140. The reduced outer diameter portion 136
includes a window or recess 142 for receiving a latching engagement
from a subsequently run tool to latch the tool in place within main
tubular 20 and thus in orientation with lateral borehole 16. The
lower end 144 may include threads 146 for threading engagement to a
lower tool such as a spline sub. Another method includes threading
an extension sub having a mule shoe into the lower end of main
tubular 20 and then orienting the mule shoe with respect to the
window 26.
[0089] Referring now to FIGS. 11-14, there is shown one tool,
namely a deflector 150, which may be used with orientation member
130 in main tubular 20 for directing other tools through the
lateral tubular 40. Deflector 150 is used after lateral tubular 40
is deployed within main tubular 20. For instance, it may become
necessary to re-enter the lateral borehole for further well
operations such as for drilling the lateral borehole 16. Deflector
150 includes a tubular body 152 having a lower connector or latch
154 with a plurality of collet finger slots 156, best shown in
FIGS. 14D and 14E, adapted to engage the orientation member 130,
and a ramp surface 160 extending from the upper terminal end 158 to
a point 162 approximately at the mid portion of tubular body 152.
Moreover, deflector 150 also includes an internal bore 164 which
allows downhole access to the main borehole 20 below the deflector
150.
[0090] Referring specifically to FIGS. 11B and 13B-D, it can be
seen that deflector 150 has a key, such as mule shoe 194, which
engages the mule shoe 134 of FIG. 10 to orient the deflector 150
with respect to windows 26 and 42. FIGS. 11B and 13B show the front
and back views of the orientation member or mule shoe 194 which is
coupled to the lower end of the deflector 150 of FIGS. 11A, 12, and
13A. Also shown are the collet fingers 157 of latch 154 which work
in conjunction with collet slots 156 to engage orientation member
130. Shear screws 161 releasably attach collet fingers 157 and mule
shoe 194 to the lower end of deflector 150. When it is necessary to
retrieve deflector 150, the screws 161 may be sheared by an upward
force exerted on deflector 150, thereby separating deflector 150
from both mule shoe 194 and collet fingers 157.
[0091] A recess 170 is provided through the upper end of ramp
surface 160 for connection to a retrieving tool to retrieve
deflector 150. Recess 170 includes a retrievable hook slot 172
which is used as a standard method of retrieval for a deflector.
Upon lifting the retrieving tool, the deflector 150 is also lifted
from within main tubular 20.
[0092] Deflector ramp surface 160 begins at the initial cam surface
166 on upper terminal end 158, best shown in FIG. 14A. The ramp
surface 160 extends past an upset 168 on tubular body 152 to mid
point 162. See FIGS. 14B and 14C. Ramp surface 160 is formed
similarly to ramp surface 50 of main tubular 20. Ramp surface 160
is spaced from orientation member 130 such that tools passing down
the upper portion of main and lateral tubulars 20, 40 are directed
by ramp 160 out through the lateral tubular 40 and into the lateral
borehole 16.
[0093] In operation, the deflector 150 is lowered from the surface
18 down through the cased borehole and into the main tubular 20. A
key, such as mule shoe 194 on the lower end of deflector 150,
engages the mule shoe 134 on orientation member 130. The mule shoe
134 of orientation member 130 in main tubular 20 is used to land
and orient deflector 150. As deflector 150 reaches slot 142, the
collet connector 154 on the lower end of deflector 150 latches onto
the orientation member 130.
[0094] In an alternative embodiment, a sealing assembly may be
attached to the lower end of deflector 150 such that the sealing
assembly seals or isolates primary borehole 14. A sealing assembly
on deflector 150 is optional.
[0095] In another embodiment the deflector is eliminated and ramp
50 is used to deflect subsequent tools being passed through the
junction. The main tubular bore size is reduced along the ramp 50
and below the junction. Machining a smaller bore in main tubular 20
causes the walls 60 to be wider. This will allow the ramp 50 in the
bottom of main tubular 20 to serve both the purpose of deploying
lateral tubular 40 and to serve the function of a deflector in
deflecting tools out into the lateral borehole 16. However, it is
necessary that the bore through the main tubular 20 be reduced.
[0096] Once junction 10 is in place, no tool can be run down
through junction 10 which is larger than the inner diameter of the
lateral tubular 40. In one size of the preferred embodiment,
lateral tubular 40 has an inner diameter of about 61/2 inches.
Thus, a subsequent tool or other member which is 61/2 inches in
outside diameter could pass down through the main tubular 20
because it will clear the ramp. However, nothing requires that the
bore through the main tubular 20 below the lateral tubular 40 be
61/2 inches in inside diameter. It could be smaller, such as 6
inches. Thus, if a tool 61/2 inches in diameter is run down hole,
it could not pass through main tubular 20 at the junction. It would
be deflected out into the lateral borehole.
[0097] Referring now to FIGS. 15A-H, there is shown the sequential
steps of a preferred method using the junction 10 of the present
invention. Referring to FIG. 15A, a one trip milling assembly 200
is lowered into cased primary borehole 14 on a work string 202. The
one trip milling assembly 200 includes a reentry tool 204, a spline
sub 206, a retrievable anchor 208, a debris barrier 210, a
production packer 212, a whipstock 214 having a ramp 216, and one
or more mills 218, 220 releasably attached at 222 to the upper end
of whipstock 214. The mills 218, 220 are disposed on the end of the
work string 202 extending to the surface 18. The one trip milling
assembly 200 is lowered onto a well reference member 230 which may
be previously installed at a predetermined location in the cased
primary borehole 14 for subsequent well operations, such as milling
a window 240 in the casing 224 of primary borehole 14. Well
reference member 230 may be termed an insert locator device (ILD)
which replaces the typical big bore packer. Well reference member
230 is shown and described in pending U.S. PCT Application Serial
No. PCT/JUS01/16442 filed May 18, 2001, hereby incorporated herein
by reference.
[0098] Reentry tool 204 is mounted on spline sub 206 and includes a
downwardly facing mule shoe 232 for engagement with upwardly facing
mule shoe 234 on well reference member 230.
[0099] Well reference member 230 locates and orients the one trip
milling assembly 200 above it. Well reference member 230 neither
serves as an anchor member nor as a sealing member; it merely
provides depth location and orientation for subsequent well
operations over the life of the well. The anchoring and sealing
functions are performed by other tools in the assembly 200 such as
retrievable anchor 208 and production packer 212, which may be a
weight set production packer. The assembly 200 is set down on the
well reference member 230 and then weight is applied to the work
string 202. The well reference member 230 orients the ramp 216 of
whipstock 214 in the preferred direction of the window to be milled
in the casing 224 shown in FIG. 15B. After anchor 208 is set, the
work string 202 is pulled or pushed causing the lead mill 218 to
shear connection 222 at the upper end of whipstock 214. Mills 218,
220 are then rotated and guided by whipstock ramp 216 into the
casing 224 as work string 202 rotates the mills causing them to
mill a window in casing 224.
[0100] Referring now to FIG. 15B, mill 218 is shown milling through
the main bore casing 224 to form a window 240. The window 240 is
milled using conventional milling techniques. The use and
configuration of these components in milling operations is well
known by those skilled in the art. The work string 202 is rotated,
thereby rotating mills 218, 220 as mills 218, 220 move downwardly
and outwardly on ramp 216 of whipstock 214. Ramp 216 guides the
rotating mills 218, 220 into engagement with the casing 224, thus
cutting window 240 in casing 224. The mills 218, 220 continue to
drill a rat hole 226, as the beginning of the lateral borehole 16,
best shown in FIG. 15C.
[0101] Referring now to FIG. 15C, once the rat hole 226 has been
drilled using mills 218, 220, the work string 202 and mills 218,
220 are retrieved and removed from the cased primary borehole 14. A
drill string (not shown) then is lowered into primary borehole 14
engaging the ramp surface 216 of whipstock 214 to enter rat hole
226 to drill the lateral borehole 16. Once the lateral borehole 16
has been completed, the drill string is removed from the cased
borehole 14 and retrieved to the surface 18.
[0102] Referring now to FIG. 15D, upon completing the drilling of
the lateral borehole 16, a whipstock retrieval tool 228 is lowered
and connected to the upper end of whipstock 214. The retrievable
anchor 208 is released from the cased borehole 14 and the whipstock
assembly 200 is retrieved from the well. Everything but the well
reference member 230 then has been removed from the main wellbore
14.
[0103] Referring now to FIG. 15E, the junction 10 is in a running
configuration and is attached to a running tool 238 on the lower
end of another work string 202 by releasably connecting running
tool 238 to connection 90 on the upper end of lateral tubular 40.
Running tool 238 attaches to the upper end of lateral tubular 40
just above orientation member 72. Shear screws fit into apertures
94 to attach running tool 238 to the upper end of lateral tubular
40.
[0104] The lower end of lateral tubular 40 is inserted into the
upper end of main tubular 20 and attached by shear pin 122. A
reentry orientation tool 242 is attached to the lower end 30 of the
main tubular 20. The reentry orientation tool 242 includes a
downwardly facing mule shoe 244 which engages the upwardly facing
mule shoe 234 on well reference member 230 to cam the entire
junction assembly of tubulars 20, 40 into the proper orientation
with respect to the window 240 which has been milled into the
casing of the cased borehole 14. In the preferred embodiment, the
reentry orientation tool 242 may or may not latch onto the well
reference member 230. A spline sub 206 is located just below main
tubular 20 and is used to properly orient the mule shoe 244 of
reentry tool 242 such that when the assembly is landed onto the
well reference member 230, the junction assembly is properly
oriented with respect to the window 240 in casing 224. The spline
sub 206 allows the reentry orientation tool 242 to be realigned in
5.degree. increments thus, providing 72 different positions.
[0105] Referring now to FIG. 15F, junction 10 is shown in the
deployed position. After the junction 10 has been oriented with
casing window 240, weight is applied to the junction assembly so as
to shear the shear pin 122. Since main tubular 20 has landed and
can no longer move further down into the main bore 14, the weight
causes lateral tubular 40 to move downwardly within the main
tubular 20 whereupon the lateral tubular engages the ramp 50 of
main tubular 20. As lateral tubular 40 continues its downward
movement, ramp 50 cams lateral tubular 40 out through main window
26 and into the lateral borehole 16. As the lateral tubular 40
moves through the main window 26, the downwardly facing lateral
tubular mule shoe 72 engages the upwardly facing mule shoe 24 on
main tubular 20 causing lateral.tubular 40 to rotate into alignment
with main tubular 20 whereby the windows 26, 42 are aligned forming
a common window 120 and a Y junction between primary borehole 14
and lateral borehole 16.
[0106] Referring now to FIG. 15G, deflector 150 may be lowered into
the main tubular 20 using a deflector running tool on a work
string. The mule shoe 194 on the lower end of deflector 150 engages
the upwardly facing mule shoe 134 on orientation member 130 to
properly orient deflector 150 so that ramp surface 160 of deflector
150 faces the casing window 240 and lateral bore 16.
[0107] Referring now to FIG. 15H, having deployed junction 10, a
liner 246 may be run through the lateral tubular 40 and into the
lateral bore 16. The liner 246 may or may not be used in the
present invention and is an alternative embodiment.
[0108] The junction 10 as shown in FIG. 15H is a level three
because the junction 10 includes a first tubular 20 extending into
the main borehole 14 and a second tubular 40 extending into the
lateral borehole 16 without cementing or sealing the junction. A
level four can be achieved by cementing in junction 10. To cement
junction 10, packers or plugs are set in primary borehole 14 below
main tubular 20 and then a flapper valve is set above the
orientation member 130 to prevent cement from reaching upwardly
facing mule shoe 134. A clean out tool is then run through the main
tubular 20 to just above orientation member 130 to remove the
cement in main tubular 20 and through the lateral tubular 40 to
remove the cement in lateral tubular 40. Thus a level four junction
has been achieved.
[0109] A level five may be achieved by running a pair of conduits
into the junction 10 with each conduit having a packer or other
sealing assembly on its lower end. A dual bore packer is attached
to the upper ends of the conduits. One conduit is run into the main
tubular 20 and its packer set to seal with the cased borehole below
the main tubular 20 and the other conduit is run into the lateral
tubular 40 and its packer is set below the lateral tubular 40 in
the lateral borehole 16. The dual bore packer is set above the
junction 10 in the cased primary borehole above the junction 10.
The sealing engagements of the packers provides the required
pressure integrity at the junction for a level five.
[0110] In another alternative embodiment of this invention, the
main tubular 20 and lateral tubular 40 can be run separately into
the well bore. This is typically necessary when the lateral tubular
40 includes a pipe string that is hundreds of feet long. Usually,
the lateral 40 is run as one piece with the main tubular 20, but
when it is so long that the lateral tubular 40 extends a great
distance into the lateral borehole 16, it becomes impractical to
run the assembly as one piece. In such an embodiment, the lateral
tubular 40 can be run in separately after the main tubular 20 has
landed onto the well reference member 230. After the main tubular
20 is run into the main bore 14, the main window 26 is aligned with
the casing window 240. The lateral tubular 40 may subsequently be
run through the main bore 14 and into the lateral bore 16,
similarly achieving alignment between the main window 26 and
lateral window 42.
[0111] Where a long pipe string is attached to the end of the main
tubular 20, a retainer may be added to the lower end of lateral
tubular 40 adjacent the shear pin 122 to carry the additional load
of the main tubular 20 on the lateral tubular 40. Also if a liner
is attached to the end of lateral tubular 40, a swivel may be used
to attach the lateral tubular 40 with the liner to allow the liner
to swivel freely as the liner is passing into the lateral borehole
16.
[0112] One advantage of the present invention is that a liner
several hundred feet long can be disposed on the end of the lateral
tubular 40 and run immediately after the borehole has been drilled.
This provides support for any unconsolidated formation in the
lateral borehole 16 within hours of drilling the borehole 16. For
example, if a 300 foot long lateral borehole 16 is drilled, it is
preferred to insert a liner into the 300 foot lateral borehole 16
using the end of the lateral tubular 40 right after drilling the
300 foot lateral borehole 16. Although it may be preferred in the
prior art to drill the borehole, set the liner, cement the liner
off, and then drill out the end of the liner in the lateral
tubular, this takes much longer and poses a problem with
unconsolidated formation which may cave into the lateral borehole
16 before the complete borehole is drilled and the liner installed.
Once the 300 foot liner has been installed, then the remainder of
the lateral borehole 16 can be drilled through the liner.
[0113] Referring now to FIGS. 16-18, in still another embodiment, a
well reference member 230, like that shown in pending U.S. PCT
Application Serial No. PCT/JUS01/16442, is disposed in the casing
224 of primary borehole 14 above the drilled lateral borehole 16.
This embodiment is described in Great Britain Application No. U.K.
0112456.9, filed on May 22, 2001, and entitled "Downhole Lateral
Completion System," hereby incorporated by reference. In this
embodiment the well reference member 230 is located above the
junction rather than below as in previous embodiments. Well
reference member 230 is set after the lateral borehole 16 is
drilled. As shown in FIGS. 16-17, well reference member 230 serves
as the orienting member for the lateral tubular 250, similar to
lateral tubular 40, which is lowered individually down the primary
cased borehole 14 without a main tubular 20. As shown in FIG. 16,
the lateral tubular 250 includes a mating orienting member 252,
such as a mating mule shoe, which engages well reference member 230
for orienting the window 254 in lateral tubular 250 with the window
240 of the lateral borehole 16. A deflector may be set below the
junction to guide the completion into the lateral borehole 16. As
shown in FIG. 18, production through the main borehole 14 passes
through the cased borehole below the junction since there is no
main tubular.
[0114] In a further embodiment, the junction may be used in a new
well where the operator knows that a lateral borehole 16 is to be
drilled. The main tubular 20 may be run as part of a casing string.
The ends of main tubular 20 have threaded connections so that it
could be attached to a length of casing. In one example, the main
tubular 20 is run as part of a 95/8 inch string of casing whereby
the inside diameter of top of the main tubular 20 may be 81/2
inches, allowing a larger ramp out angle through window 26. Also
larger sized tubulars may be run through main tubular 20. Window 26
in main tubular 20 is scabbed over by a sleeve which fits over the
outside of main tubular 20 to protect and close off window 26. The
sleeve may be a fiberglass sheath. The sleeve over window 26
permits the casing 224 to be cemented in the borehole 14 without
the cement flowing through window 26 and into the inside diameter
of main tubular 20.
[0115] Once the main tubular 20 has been cemented in place, the
main tubular 20 is then cleaned and the sleeve milled out to expose
the window 26 such that the lateral borehole 16 can be drilled
through window 26. A deflector 150 may be lowered into the main
tubular 20 to guide a tool to drill out the fiberglass sheath. The
lateral tubular 40 may then subsequently be run down through main
tubular 20 and ramped out into the newly drilled lateral borehole
16. This is basically a section of casing with a pre-milled window.
Pre-milled windows are taught by the prior art, thus one with skill
in the art can appreciate a pre-milled window scabbed over by a
sheath. However, the prior art casings with pre-milled windows do
not include ramps to guide an inner member out into the lateral
borehole 16.
[0116] In this alternative embodiment, the window 26 must be
oriented in the proper direction since it is more difficult to
rotate and align a string of casing. Preferably there is also
included a mule shoe profile in the main tubular 20 to properly
orient the subsequent lateral tubular 40 so that it is deployed out
into a subsequently produced lateral borehole. Thus, there may be a
profile, either above or below window 26 to guide, land, and orient
the lateral tubular 40 which is subsequently run into the well. In
one embodiment, the profile is above the window, as was seen in the
embodiment of FIGS. 16-18 on Great Britain Application No. U.K.
0112456.9. However, the profile may be disposed inside the main
tubular 20 causing the flowbore of the casing string to be
reduced.
[0117] The mule shoe may be part of the main tubular 20 if the
alignment of the window 26 with the lateral borehole 16 is known.
The well reference member 230 is used in the preferred embodiment
to align the entire assembly. If a well reference member is also
included in this embodiment, little advantage has been gained.
However, several advantages do emerge in this embodiment. One
advantage is that the window 26 has been pre-cut and will not have
to be milled, thus the operator knows the exact profile of the
window 26. When a window is milled into the casing, the edges of
the window in the casing are jagged and unpredictable, and
therefore hard to seal. Another advantage is that the mule shoe
could also be pre-milled inside the main tubular in the casing
string. The mule shoe is then set for depth and orientation. The
throughbore may be slightly larger in the alternative embodiment
than in the preferred embodiment, but not so much larger as to
encourage including the main tubular 20 in the casing string rather
than running it in later with the lateral tubular 40.
[0118] The above discussion is meant to be illustrative of the
principles and various embodiments of the present invention.
Numerous variations and modifications will become apparent to those
skilled in the art once the above disclosure is fully appreciated.
It is intended that the following claims be interpreted to embrace
all such variations and modifications.
* * * * *