Note: Descriptions are shown in the official language in which they were submitted.
~:-~ WO 94/29563 . ~ PCT/~JS94/U6414
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METHOD FOR COMPLETING MULTI-LATERAL WELLS
AND MAINTAINING SELECTIVE RE-ENTRY INTO LATERALS
Background of the Invention:
This invention relates generally to the completion of wellbores. More
particularly, this invention relates to new and improved methods and devices
for
completion of a branch wellbore extending laterally from a primary well which
S may be vertical, substantially vertical, inclined or even horizontal. This
invention finds particular utility in the completion of multilateral wells,
that is,
downhole well environments where a plurality of discrete, spaced lateral wells
extend from a common vertical wellbore.
Horizontal well drilling and production have been increasingly important
1Q to the oil industry in recent years. While horizontal wells have been known
for
many years, only relatively recently have such wells been determined to be a
cost effective alternative (~r at leashcompanion) to conventional vertical
well
drilling. Although drilling a horizontal well costs substantially more than
its
vertical counterpart, a horizontal well frequently improves production by a
factor
15 of five, ten, or even twenty in naturally fractured reservoirs. Generally,
projected productivity from a horizontal well must triple that of a vertical
hole
for horizontal drilling to be economical. This increased production minimizes
the number of platforms, cutting investment and operational costs. Horizontal
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drilling makes reservoirs in urban areas, permafrost zones and deep offshore
waters more accessible. Other applications for horizontal wells include
periphery wells, thin reservoirs that would require too many vertical wells,
and
reservoirs with coning problems in which a horizontal well could be optimally
distanced from the fluid contact.
Horizontal wells are typically classified into four categories depending on
the turning radius:
1. An ultra short turning radius is 1-2 feet; build angle is 45-60
degrees per foot.
2. A short turning radius is 20-100 feet; build angle is 2-5 degrees
per foot.
3. A medium turning radius is 300-1,000 feet; build angle is 6-2G
degrees per 100 feet.
4. A long turning radius is 1,000-3,000 feet; build angle is 2-6
degrees per 100 feet.
Also, some horizontal wells contain additional wells extending laterally
from the primary vertical wells. These additional lateral wells are sometimes
referred to as drainholes and vertical wells containing more than one lateral
well
are referred to as multilateral wells. Multilateral wells are becoming
increasingly important, both from the standpoint of new drilling operations
and
from the increasingly important standpoint of reworking existing wellbores
including remedial and stimulation work.
As a result of the foregoing increased dependence on and importance of
horizontal wells, horizontal well completion, and particularly multilateral
well
completion have been important concerns and have provided (and continue to
provide) a host of difficult problems to overcome. Lateral completion,
particularly at the juncture between the verkical and lateral wellbore is
extremely
important in order to avoid collapse of the well in unconsolidated or weakly
consolidated formations. Thus, open hole completions are limited to competent
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rock formations; and even then open hole completion are inadequate since there
is no control or ability to re-access (or re-enter the lateral) or to isolate
production zones within the well. Coupled with this need to complete lateral
wells is the growing desire to maintain the size of the wellbore in the
lateral well
as close as possible to the size of the primary vertical wellbore for ease of
drilling and completion.
Conventionally, horizontal wells have been completed using either slotted
liner completion, external casing packers (ECP's) or cementing techniques. The
primary purpose of inserting a slotted liner in a horizontal well is to guard
against hole collapse. Additionally, a liner provides a convenient path to
insert
various tools such as coiled tubing, in a horizontal well. Three types of
liners
have been used namely (1) perforated liners, where holes are drilled in the
liner,
(2) slotted liners, where slots of various width and depth are milled along
the
line length, and (3) prepacked liners.
Slotted liners provide limited sand control th~pugh selection of hole sizes
and slot width sizes. However, these liners are susceptible to plugging. In
unconsolidated formations, wire wrapped slotted liners have been used to
control
sand production. Gravel packing may also be used for sand control in a
horizontal well. The main disadvantage of a slotted liner is that effective
well
stimulation can be difficult because of the open annular space between the
liner
and the well. Similarly, selective production (e.g., zone isolation) is
difficult.
Another option is a liner with partial isolations. External casing packers
(ECPs) have been installed outside the slotted liner to divide a long
,horizontal
well bore into several small sections (FIGURE 1). This method provides limited
zone isolation, which can be used for stimulation or production control along
the
well length. However, ECP's are also associated with certain drawbacks and
deficiencies. For example, normal horizontal wells are not truly horizontal
over
their entire length, rather they have many bends and curves. In a hole with
i
WO 94129563 ; PCTI17~94106414 ~-~~
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several bends it may be difficult to insert a liner with several external
casing
packers.
Finally, it is possible to cement and perforate medium and long radius
wells as shown, for example, in I1.S. Patent 4,436,165.
While sealing the juncture between a vertical and lateral well is of
importance in both horizontal and multilateral wells, re-entry and zone
isolation
is of particular importance and pose particularly difficult problems in
multilateral
wells completions. Re-entering lateral wells is necessary to perform
completion
work, additional drilling and/or remedial and stimulation work. Isolating a
lateral well from other lateral branches is necessary to prevent migration of
fluids and to comply with completion practices and regulations regarding the
separate production of different production zones. Zonal isolation may also be
needed if the borehole drifts in and out of the target reservoir because of
insufficient geological knowledge or poor directional control; and because of
pressure differentials in vertically displaced strata as,~vill be discussed
below.
When horizontal boreholes are drilled in naturally fractured reservoirs,
zonal isolation is being seen as desirable. initial pressure in naturally
fractured
formations may vary from one fracture to the next, as may the hydrocarbon
gravity and likelihood of coning. Allowing them to produce together permits
crossflow between fractures and a single fracture with early water
breakthrough,
which jeopardizes the entire well's production.
As mentioned above, initially horizontal wells were competed with
uncemented slotted liner unless the formation was strong enough for an open
hole completion. Both methods make it difficult to determine producing zones
and, if problems develop, practically impossible to selectively treat the
right
zone. Today, zone isolation is achieved using either external casing packers
on
slotted or perforated liners or by conventional cementing and perforating.
The problem of lateral wellbore (and particularly multilateral wellbore)
completion has been recognized for many years as reflected in the patent
CA 02142113 2001-02-28
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literature. For example, U.S. Patent 4,807,704 discloses a system for
completing
multiple lateral wellbores using a dual packer and a deflective guide member.
U.5.
Patent 2,797,893 discloses a method for completing lateral wells using a
flexible liner
and deflecting tool. Patent 2,397,070 similarly describes lateral wellbore
completion using flexible casing together with a closure shield for closing
off the
lateral. In Patent 2,858,107, a removable whipstock assembly provides a means
for
locating (e.g., re-entry) a lateral subsequent to completion thereof. Patent
3,330,349
discloses a mandrel for guiding and completing multiple horizontal wells. U.5.
Patent Nos. 4,396,075; 4,415,205; 4,444,276 and 4,573,541 all relate generally
to
methods and devices for multilateral completions using a template or tube
guide head.
Other patents of general interest in the field of horizontal well completion
include
U.S. Patent Nos. 2,452,920 and 4,402,551.
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 vertical 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.
Summarv of the Invention
The above-discussed and other drawbacks and deficiencies of the prior art are
overcome or alleviated by the several methods and devices of the present
invention
for completion of lateral wells and more particularly the completion of
multilateral
wells. In accordance with U.S. Patent No. 5,311,936, a plurality of methods
and
devices were provided for solving important and serious problems posed by
lateral
(and especially multilateral) completion including:
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1. Methods and devices for sealing the junction between a vertical
and lateral well.
2. Methods and devices for re-entering selected lateral well to
perform completions work, additional drilling, or remedial and stimulation
work.
3. Methods and devices for isolating a lateral well from other lateral
branches in a multilateral well so as to prevent migration of fluids and to
comply
with good completion practices and regulations regarding the separate
production
of different production zones.
In accordance with the present invention, an improved method relating to
the foregoing multilateral and xelated completion methods is presented. In
particular, a method is presented for completing mufti-lateral wells and
maintaining selective re-entry into those mufti-lateral wells. To accomplish
this,
a primary wellbore is drilled and cased. Thereafter, a first lateral well is
drilled
out of the bottom of the wellbore and a running tool directs a string of
external
casing packers, having sliding sleeves provided ther~between and a packer bore
receptacle, therewithin (or in a preferred embodiment, a novel lateral
connector
receptacle is used in place of the packer bore receptacle). Next, a whipstock
and
anchor are mounted to the packer bore receptacle (or lateral connector
receptacle) and, once aligned, a second lateral well is drilled away from the
first
lateral well. After retrieving the whipstock and anchor, a novel diverter and
scoophead assembly is then run with preferably the same anchor alignment as
the
whipstock, anchor to properly mate the diverter head with the second lateral
well.
At this time, a second string of external casing packers also .having sliding
sleeves may be run into the second lateral well. A selective re-entry tool
with a ,
novel parallel seal assembly below may then be run on a single production
tubing
string and tied back to the surface to a standard wellhead. In a preferred .
embodiment, the selective re-entry tool includes a diversion flapper which may
be remotely shifted for selecting either the first or second lateral well
bores for
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re-entry. The diversion flapper does not prohibit fluid flow from either
lateral
below.
In a preferred embodiment, the scoophead includes a pair of parallel
offset bores, one of which communicates with the primary wellbore while the
other communicates with the lateral wellbore. The bore leading to the lateral
is
provided with a novel liner tie-back sleeve. Thereafter, both bores are
provided
with a novel parallel seal assembly and this parallel seal assembly then is
mated
to either a selective re-entry tool or other production tubing.
It will be appreciated that the present method provides for the ability to
enter any of the well bore completion strings for the purpose of conducting an
activity such as acidizing, fracturing, washing, perforating and the Like. The
present invention allows an operator to select from the surface any lateral by
use
of a remotely controlled string pr wireline methods and thereby convey the
equipment into the chosen lateral.
i5 do addition to the foregoing novel methods, the present invention includes
w
a plurality of important and novel tools and assemblies for use in the
described
methods as well as other completion methods (multilateral or otherwise). For
example; in accordance with the present invention, a novel lateral connector
receptacle or LCR is provided which functions to (1) provide means for running
a lower completion into the well; (2) provide means for orienting a
retrievable
whipstock assembly and/or scoopheadldiverter assembly; and (3) provides means
for attaching an upper completion to,a lower completion. The LCR includes an
upper section for housing a latch thread and smooth seal bore which
respectively
threadably attaches to, and mates with seals from, an orientation anchor. A
central section of the LCR includes an orientation lug for mating with the
orientation anchor and providing a fixed reference point to the retrievable
whipstock and/or scoophead/diverter assembly; and a lower section of the LCR
includes an inner mating (e.g., profiled) surface for attachment to an
appropriate
run-in tool. Preferably, the LCR includes three cylindrical, threadably mated
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subs (which respectively include the (1) latch thread and seal bore; (2) the
orientation anchor alignment lug and (3) the running profiled connecting
surfaces) and a fourth bottom sub. 'The LCR combines all of the aforementioned
features providing a novel tool which allows for the ability to stack infinite
laterals in a single well.
Another important tool assembly used is the method of lateral completion
of the present invention is the aforementioned novel scoophead/diverter
assembly
which is installed at the juncture between the primary wellbore and the
lateral
branch and which allows the production tubing of each to be oriented and
anchored. This scoophead/diverter assembly further provides dual seal bores
for
tying back to the surface with either a dual packer completion or a single
tubing
string completion utilizing a selective re-entry tool (SRT). The
scoophead/diverter comprises a scoophead, a diverter sub, two struts as
connecting members between the scoophead and diverter sub and a joint of
tubing communicating between the scoophead and diverter sub. The scoophead
has a large and small bore. The large bare is a receptacle for a tie back
sleeve
(described hereinafter) run on top of the lateral wellbore string, and the
small
bore is a seal bore to tie the primary wellbore back to surface. Below the
scoophead, a joint of tubing is threaded to the small bore. The tubing passes
through an angled smooth bore in the diverter sub which causes the tubing
joint
to deflect from the offset of the small bore of the scoophead back to the
centerline of the scoophead, and thus the centerline of the borehole with
which it
is concentric. Taking the offset through the length of a tubing joint
(typically
ft) allows for a gradual bend which will not restrict the passage of wireline
or
25 through tubing tools for lateral remedial and simulation work.
As mentioned, the scoophead and diverter sub are connected with two
struts which rigidly fix the scoophead and diverter sub both axially and
rotationally. Since the window length to the lateral wellbore entry vanes
depending on the hole size and build angle of the sidetrack, the distance
between
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the scoophead and diverter sub is rendered adjustable by varying the length of
the struts. This is important since for the system to function correctly, the
scoophead and diverter must straddle the lateral sidetrack's exit window from
the
primary wellbore.
In accordance with an important feature of the scoophead, the profile on
the top of the scoophead is configured so that it directs the production
tubing for
the lateral wellbore into the large bore of the scoophead and also orients the
_ parallel seal assembly (described hereinafter) when tying back to the
surface with
a dual packer completion or a single tubing completion. The orientation is
accomplished by combining a sloped profile with a slotted inclined surface
around the small bore and a compound angled surface above the slot. When
running the lateral wellbore tubing, if the nose first contacts the scoop it
is
directed into the large bore, and if it initially lands over the small
borehole; it is
prevented from entering due to the diameter of the nose being wider than the
slot
i5 over the small borehole. Since the nose cannot pass the slot, it slides
down the
compound angle which also directs it to the large borehole. Similarly, when
orienting the parallel seal assembly, the lateral wellbore seals, which are
longer
than the primary wellbore seals, first contact the scoophead, and are directed
to
the large borehole of the scoophead in exactly the same manner as described
for
the lateral wellbore tubing string. Once the lateral wellbore seals of the
parallel
seal assembly are directed into the correct borehole, the primary wellbore
seals
are limited in the amount of rotational misalignment they can have because the
parallel seal assembly can only pivot around the lateral wellbore seal axis by
the
amount of diametric clearance between the major diameter of the~parallel seal
assembly and the inside diameter of the concentric main wellbore in which they
are installed. The compound angle of the scoophead is configured such that its
surface will contain this amount of rotational misalignment, and apply a force
to
the primary wellbore seals to guide them into their seal bore.
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The aforementioned scoophead/diverter assembly functions to orient and
anchor multiple tubing strings at the Y juncture in an oil or gas well with
multiple lateral wellbores. An important advantage of this arrangement is to
provide communication to multiple reservoirs or tap different locations within
the
same reservoir and enable re-entry to these wellbores for remediation anc~
stimulation. The large bore of the scoophead enables a secondary wellbore's
production tubing (liner) to pass through until the top of the liner is in the
_ scoophead. In accordance with an important feature of this invention, a
novel
liner tie-back sleeve is used to thread onto the top of the liner, and locate,
latch
and provide a seal receptacle to isolate the secondary wellbore's production
fluids. The liner tie-back sleeve also includes a running profile fox a
suitable
running tool. The liner tie-back sleeve comprises two cylindrical parts that,
when assembled, provide a running tool profile for running the liner in the
w~llbore. The sleeve has a locating shoulder on the outer surface to indicate
when the sleeve is located in the scoophead, and a locking groove for locking
dogs from the scoophead to snap into, to provide resistance when pulling
tension
against the sleeve. ance the sleeve is in place and the running tool removed,
an
internal thread and seal bore is exposed for the parallel seal assembly (or
other
tool or production tubing) to plug into for isolating the secondary lateral
wellbore. Providing the seal point between the parallel seal assembly and
sleeve
eliminates the need to effect a seal in the scoophead on the large bore side.
In order to effect a seal inside the scoophead, a novel offset parallel seal
assembly with centralizer is utilized. This parallel seal assembly carries
compressive loads on the primary well bare side, and has a shear out mechanism
on the secondary wellbore side. This seal assembly also may constitute the
connection between the scoophead and the selective re-entry tool (SRT). As
described above, the SRT is the tool that ties the two separate tubing strings
below it into a single production tubing string to surface or the next
lateral. This
parallel seal assembly has two seal assemblies parallel to one another with
one
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seal assembly being larger diameter and longer than the other. The larger seal
assembly seals into the seal bore of the tie back sleeve which is latched into
the
scoophead, and is attached to the top of the secondary wellbore's production
tubing string. The smaller seal assembly seals in the small bore of the
scoophead. The smaller assembly acts to isolate the primary wellbore. The
larger seal assembly is longer than the smaller seal assembly to allow the
larger
seal assembly to enter the appropriate bore of the scoophead and align the
- overall assembly. The alignment is accomplished by trapping the larger seal
assembly in its bore and trapping the centralizer in the wellbore. This
positively
limits the rotational mis-alignment available to the smaller seal assembly
prior to
stabbing into the scoophead. The parallel seal assembly automatically aligns
with as much as 120° rotational misalignment. The centralizer
preferably
comprises two cylinders with two offset counter bores that bolt together. Once
bolted together, the couplings located within the counter bores connect the
seal
assemblies to their respective tubing subs and are trapped in the counter
bares.
This limits the axial movement available to the centralizer. An important
feature
of the centralizes is that it elevates the seal assemblies off the wellbore
wall
during running and stab-in; and facilitates the automatic alignment feature of
the
parallel seal assembly and scoophead as a system.
As mentioned, a selective re-entry tool is run on the completion string to
enable an operator to select the branch desired so as to enter such desired
branch
with a coil tubing workstring (or the like) and perform the appropriate
operation
(e.g., stimulation, fracture, cleanout, shifting, etc.). In a preferred
embodiment,
the selective re-entry tool includes an outer stationary sub and an inner
longitudinally shiftable mandrel or sleeve. Preferably, this sleeve is
connected to
a rectangular box which is spaced from an exit sub having a pair of exit
openings. A flapper is pivotally connected at the intersection between the
exit
opening. laterally extending ears on opposed sides of the flapper are received
in a respective pair of elongated, romped guide slots formed on opposed
lateral
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surfaces of the box. During operation, a known shifting tool will shift the
inner
sleeve upwardly or downwardly causing the box to similarly move (with respect
'
to the outer sub). Longitudinal movement of the box will cause the ears in the
flapper to move along the guide slots whereby the flapper will pivot between a
first position which guides a coiled tubing through one of the exit openings
to a
second position which guides the coiled tubing through the other exit opening.
Preferably, a double ended coliet is attached to a stationary sub and is
supported on the inner sleeve. The collet includes an interlocking bump which
mates with (e. g. , snap-locks into) one of the two corresponding grooves on
the
inner sleeve. The grooves are positioned so as to correspond to the two
desired
positions of the flapper. The collet will only disengage from the inner sleeve
when an appropriate snap-out force is exerted by the shifting tool such that
the
collet normally maintains the flapper in a fixed, locked position.
Preferably, the scoophead/diverter system is run into the wellbore using a
novel scoophead running tool. This running tool allows circulation through its
inside diameter, and has internal pressure integrity to test any seals below
the
running tool prior to releasing the scoophead. This run-in tool incudes a
mounting head from which extends a running stump and a housing (or
connecting mandrel). The running stump and housing are mutually parallel and
are sized and configured to be respectively received in the large and small
diameter bores in the scoophead. The scoophead running tool thus allows torque
to be transmitted about the centerline of the scoophead assembly in spite of
being
attached into one of the offset bores.l This torque transmission is
accomplished
by connecting the connecting mandrel between the running tool and scoophead at
,
the same offset as the large bore of the scoophead. This transfer of torque is
important in order to reliably manipulate the scoophead assembly with the
running string.
The connecting mandrel of the running tool has an internal bypass sleeve
that opens at a predetermined pressure that allows a tripping ball to be
circulated
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down to its seat if the scoophead is to be run and anchored into a closed
system.
This is necessary when having to hydraulically manipulate other equipment
(which mandates a closed system) downhole prior to installing the scoophead.
Once the bypass sleeve is shifted to allow circulation, the circulation can
only
S continue until the ball is seated. At that time, circulation ports are
closed off
from above, and the resultant increased tubing pressure will release the
running
tool.
The above-discussed and other features and advantages of the present
invention will be appreciated and understood by those skilled in the art from
the
following detailed description and drawings.
Brief Description of the Drawings:
Referring now to the drawings, wherein like elements are numbered alike
in the several FIGURES:
FIGURES 1-9 are sequential cross-sectional ~levational views depicting a
IS method for multilateral completion using a whipstock/packer assembly and a
selective re-entry tool;
FIGURE 10 is a side view, in cross-section, of a selective re-entry tool in
accordance with a first embodiment of the present invention;
FIGURE 11 is a top view, in cross-section, of the device of FIGURE 10;
FIGURE 12 is top view, in cross-section, of an embodiment of a
diversion flapper in accordance with the present invention;
FIGURE 12A is a cross-sectional elevation view along the line 12A-12A
of FIGURE 12;
FIGURES 13A and 13B are cross-sectional elevation views of a downhole
completion assembly for completing multilateral wells in accordance with a
preferred embodiment of the present invention;
FIGURE 13C is an enlarged cross-sectional view of a portion of the
downhole completion assembly depicted in FIGURE 13A;
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FIGURE 14 is a cross-sectional elevation view of a lateral connector
receptacle or LCR in accordance with the present invention;
FIGURES 1SA, B and C are respective top, side and bottom views of a
portion of the orienting anchor sub;
S FIGURE 16 is a side elevation view of a scoophead/diverter assembly in
accordance with the present invention;
FIGURE 17 is a left end view of the scoophead/diverter assembly of
- FIGURE 16;
FIGURES 18-20 are cross-sectional elevation views along the lines 18-18,
19-19 and 20-20, respectively of FIGURE 16;
FIGURES 18-A and 18B are cross-sectional elevation views along the
lines 18A-18A and 18B-18B, respectively of FIGURE 18;
FIGURE 21 is a cross-sectional elevation view of a liner tie back sleeve
in accordance with the present invention;
1S FIGURE 22 is a cross-sectional elevation viev~ of the liner tie back sleeve
of FIGURE 21 connected to a running tool;
FIGURE 23 is a cross-sectional elevation view of the parallel seal
assembly in accordance with the present invention;
FIGURE 24 is a cross-sectional elevation view along the line 24-24 of
FIGURE 23;
FIGURES 25 and 26 are cross-sectional elevation views of a preferred
embodiment of the selective re-entry tool, in accordance with the present
invention shown with the flapper valve disposed in respective primary and
lateral
wellbore positions;
2S FIGURE 27 is a side elevation view, partly in cross-section, depicting the
flapper sub-assembly used in the selective re-entry tool of FIGURES 2S and 26;
FIGURES 28 is a cross-sectional elevation view along the line 28-28 of
FIGURE 27;
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FIGURES 29 and 29A are cross-sectional elevation views of a
scoopheadldiverter assembly running tool in accordance with the present
invention;
FIGURES 30, 31 and 32 are cross-sectional elevation views along the
lines 30-30, 31-31 and 32-32, respectively of FIGURE 29;
FIGURE 33 is a schematic elevation view depicting the scoophead
running tool of FIGURE 29 running in a completion assembly in accordance
with the present invention; and
FIGURES 34A-1 are sequential diagrammatic views depicting a preferred
method of completing multilateral wellbores in accordance with the present
invention.
Descn_,ption of the Preferred Embodiment:
In accordance with the present invention, various embodiments and
methods and devices for completing lateral, branch oar horizontal wells which
extend from a single primary wellbore, and more particularly far completing
multiple wells extending from a single generally vertical wellbore
(multilaterals)
are described. It will be appreciated that although the terms primary,
vertical,
deviated, horizontal, branch and lateral are used herein for convenience,
those
skilled in the art will recognize that the devices and methods with various
embodiments of the present invention may be employed with respect to wells
which extend in directions, other than generally vertical or horizontal. For
example, the primary wellbore may be vertical,. inclined or even horizontal.
Therefore, in general, the substantially vertical well will sometimes be
referred
to as the primary well and the wellbores which extend laterally or generally
laterally from the primary wellbore may be referred to as the branch
wellbores.
Referring now to FIGURE 1, a vertical wellbore 10 has been drilled and
a casing 12 has been inserted therein in a known manner using cement 14 to
define a cemented well casing. As shown in FIGURES 2 and 2A, a first lateral
WO 94f29563 PCTIUS94106414
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well 16 is drilled and completed in a known manner using a liner 18 which, for
example, attaches to the casing 12 by a suitable liner hanger (not shown).
A string 20 including one or more external casing packers 22 are run into
the lateral well 16 through means of a running tool (not shown). It will be
appreciated that any number of external casing packers 22 may be employed
depending upon bore hole parameters. The external casing packers 22 are
preferably those manufactured and sold by the assignee of the present
invention.
The external casing packers 22 are inflatable and function to, among other
things, block fluid and gas migration.
Located on the string 20 and disposed between the external casing
packers 22 are sliding sleeves 24 which are provided, it will be appreciated,
for
opening and closing communication with one or more producing zones.
String 20 also includes a packer bore receptacle 26 disposed uphole of the
external casing packers 22 which is run within the lateral well 16 to a
location at
which it is desired to drill an additional well. The picker bore receptacle 26
is
employed for; among other things, releasably engaging a variety of tools
required for drilling additional lateral wells. The packer bore receptacle 26,
is
preferably manufactured and sold by the assignee of the present invention and
includes a receiving portion 2? and a key slot 28. It will be appreciated that
the
key slot 28 functions as a receptacle for orienting and aligning e.g. a
whipstock
for ensuring proper directional drilling which will be discussed hereinafter.
A
preferred and structurally altered packer;bore receptacle (also known as a
lateral
connector receptacle or LCR) is described in detail with reference to FIGURES
13, 14 and 15A-B. As will be described in detail hereinafter, the novel
lateral
connector receptacle acts as a mechanism for running in the lower completion,
orienting the whipstock assembly and scoophead/diverter assembly and providing
an interface between the lower and upper completions.
CA 02142113 2001-02-28
-17-
Next, a profile key sub 30 is run into the lateral well 16 to ascertain the
orientation of the key slot 28. The profile key sub 30, it will be
appreciated, includes
a measurement-while-drilling apparatus 32, a circulating sub 34 and a dummy
whipstock anchor 36. The dummy whipstock anchor 36 includes a male portion 38,
sized to fit within the receiving portion 27 of the packer bore receptacle 26,
and an
anchor key 40, dimensioned to mate with the key slot 28. A preferred anchor 26
is
depicted at 176 in FIGURE 13 and will be described in detail hereinafter. As
shown
in FIGURE 3, the male portion 38 is slid within receiving portion 27 and the
anchor
key 40 of the dummy whipstock anchor 36 is inserted into the key slot 28. The
profile
key sub 30 uses the measurement-while-drilling apparatus 32 for determining
the
radial direction of the key slot 28 (as best shown in FIGURE 2A) and
communicating
that information to the surface.
Turning now to FIGURE 4, after the key slot 28 alignment profile is
determined by the MWD technique, a retrievable whipstock assembly 50 is run
into
the lateral well 16 by a running tool 52. The whipstock assembly 50 preferably
includes a production injection packer assembly 54, an anchor 56 (also known
as
inflatable anchor) and an angled outer surface 58. The production injection
packer
assembly 54, as is well known, may be inflated by a fluid for affixing the
whipstock
assembly 50 Within the bore of the lateral well 16 once the anchor 56 is mated
with
the packer bore receptacle 26. The running tool 52 includes an elongated nose
portion
60 which may be releasably latched to a slot 62 disposed through the outer
surface 58
of the whipstock assembly 50. The anchor 56 includes a male portion 64 and an
anchor key 66 which are also both dimensioned to engage the receiving portion
27
and key slot 28 of the packer bore receptacle 26. The outer surface 58 of the
whipstock assembly 50 provides a surface angle to facilitate the drilling of
an
additional lateral well which will be described next. A preferred retrievable
whipstock assembly is disclosed in U.S. Patent No. 5,398,754,
CA 02142113 2001-02-28
-18-
entitled "Retrievable Whipstock Packer Assembly" invented by Daniel E.
Dinhoble
(Attorney Docket No. 93-1441), which is assigned to the assignee hereof.
As depicted in FIGURE 5, after the running tool 52 is released from the
whipstock assembly 50, a window may be milled (not shown) in the bore of
lateral
well 16. Thereafter, a suitable and known drill 70, may be employed to bore a
second lateral well 72 which communicates with the first lateral well 16.
After drilling of the second lateral well 72 is complete, the drill 70 is
removed
as shown in FIGURE 6 and a retrieving tool 80 is run down the primary well 10
and
into the first lateral well 16. The retrieving tool 80 includes a pair of
centralizers 82,
which are interconnected by a connector 84, and an elongated nose portion 86
which
is sized and shaped similarly to nose portion 60 of the running tool 52. The
nose
portion 86 is releasably latched to the slot 62 of the whipstock assembly 50
for the
removal of same. The centralizers 82 are provided for centering the nose
portion 86
within the well bore 16 for engagement with the whipstock assembly 50.
Connector
84 is located between the centralizers 82 at an acute angle which compensates
for the
increased volume at the juncture of well bore 16 and well bore 72 (see FIGURE
6A).
The retrieving tool 80 is thereafter removed taking with it the whipstock
assembly 50.
It will be appreciated that a preferred retrieving tool is disclosed in
aforementioned
U.S. Patent No. 5,398,754.
Next, referring to FIGURE 7, a scoophead running tool 88 is run into the well
bore 16. Connected to the scoophead running tool 88 is a tubular section 90
which
is, in turn, mounted to a diverter 91 and scoophead assembly 92 (see also
FIGURE
9A). The scoophead assembly has an input opening 94, a first output opening 96
and
a second output opening 98. Tubular section 90 includes an anchor 99 having a
male
portion 100 and a key 101 which mate with the packer bore receptacle 26 as
previously described. The scoophead assembly 92 is oriented so that once the
anchor
99 is mated with the packer bore assembly
WO 94129563 ~ ~ ~ ~ ~ ~ ~° PCT/US94106414
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26, the second output opening 98 is disposed in communication with the second
lateral well 72. After placing the scoophead and diverter assembly 92 in the
proper position, the running tool 88 may then be retrieved. A preferred
scoophead/diverter assembly is shown and described in detail hereinafter with
S regard to FIGURES 16-20. A preferred running tool 88 is also described in
detail hereinafter with regard to FIGURES 29-32.
At this time, as illustrated in FIGURE 8, a second string 102, including
at least one external casing packer 103, at least a pair of sliding sleeves
104 and
a tip end 106, may be run into the second lateral well 72. This is
accomplished
by running tool 110 which moves the second string 102 through the primary well
bore 10 and then into the assembly 92. It will be appreciated that the tip end
106 is shaped to engage and deflect from the diverter 91 wherein the second
string 110 will be forced into the second lateral well 72. Both the 'external
casing packers 103 and the sliding sleeves 104 are preferably those which have
been previously described. Once the second string I~10 is in place within the
second lateral well 72, the packers 103 are inflated, as previously described,
and
the running tool I 10 is then removed.
In accordance with an important feature of the present invention and
referring to FIGURES 9 and 9B, a selective re-entry assembly 120 is mounted to
the diverter and scoop assembly 92 and a single production tubing string 122
extends from the latter and is tied back to the surface to, for example, to a
standard well-head (not shown). The, production tubing string 122 includes a
packer 124, the function of which, is known. The selective re-entry assembly
120 includes a locator key 126 for orientation with the scoophead assembly 92.
The re-entry assembly 120 functions to either maintain access from the surface
to
the first lateral 16 or to permit access to the second lateral well 72.
Referring now to FIGURES 10 and 11, a novel selective re-entry
assembly 120 is provided which includes an input housing 150 which is
connected to an output housing 152. The output housing 1S2 includes a male
WO 94/29563 PCT/U~9d106414
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pardon 154 having threads 156 and a seal 158 for mounting to the input hausing
150. A pair of laterally spaced parallel bores 160 and 161 are disposed
axially
through the output housing 152. Bares 160 and 161 communicate with first
output opening 96 and second output opening 98 of the diverter and scoaphead
assembly 92.
The input housing 150 includes an input bore 159 which is connected to
the single production tubing string 122 by e.g. threads (not shown) and has a
collar 163 defining a generally stepped shape. Disposed within collar 163 is a
slidable tubular section 165 which comprises an uphole tubular slide 166, a
coupling 168 and a downhole tubular slide 170. The uphale slide 166 may be
formed of any suitable substance such as a steel alloy and includes an
alignment
slot 172, a pair of engagement grooves 174 and a central bore 176. The
alignment slot 172 is shaped to receive a protrusion 178 which extends from
the
inner surface 173 of collar 163. It will be appreciated that the engagement
grooves 174 function to receive keys (not shown) of ~ actuator (not shown)
such as the HB-2 Shift Tool, manufactured by the assignee hereof, which may be
mounted to the down hole end of a coil string, a standard threaded tubing
section
or the like.
Couple 168 is preferably threadably connected between the uphole slide
166 and the downhole slide 170 and is also preferably formed of steel.
The downhole slide 170 includes a central bore 180, a positioning collar
182 a,°~d a diversion flapper 184. Central bore 180 is of a
substantially larger
inner diameter than the inner diameter of central bore 176 of uphole slide 166
to
provide for communication between input bore 159 and either of the bores 160
or 161 of the output housing 152. The positioning collar 182 is employed to
facilitate a snaplockedly engaged, two position placement of the tubular
section
165. A first position for providing communication between input bore 159 of
the input housing 150 and bore 161 of the output housing 152 and a second
position for communication with bore 160. To facilitate this two position
-.-. V6V0 94/2953 ~ ~ ~ ~ ~. ) PCT/US94106414
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-21-
feature, the positioning collar 182 is preferably generally thin in cross-
section
and formed of a resilient material, e.g. a steel alloy. The positioning collar
182
is also cylindrical in shape and includes an annular protrusion 190 which
engages
either of a pair of annular grooves 192 and 194 disposed on an inner surface
196
of collar 164. The annular protrusion I90 includes chamfered edges (not
numbered) which function to provide the snaplock movement from one annular
groove to the other during movement of the tubular section 165. Flow slots 196
are preferably also employed on positioning collar 182.
The diversion flapper 184 is preferably formed of a suitably strong
material such as steel and is centrally mounted within bore 180. The diversion
flapper 184 includes a plate 200 which extends radially from a pin 202. Each
of
the outer ends 204 and 204' of pin 202 extend through a pair of slots 206 and
206' in the downhole tubular slide I70 and are rotatably mounted to the collar
164. Pin 202 is disposed at a sufficient distance from bores I60 and 161 of
the
output housing 152. A pair of gears 208 and 208' are disposed on the pin 202
a
and engage teeth 210 and 210' disposed within slots 206 and 206'. Flow slots
212 are disposed through plate 200. In operation, the tubular section 165 is
slid
within input housing 150 as previously discussed causing gears 208 and 208' to
rotate, which in turn causes plate 200 to move from, e.g., a position 220 to a
position 222 thereby providing communication from bore 159 to either bore 160
or 161.
FIGURES 12 and 12A depicts a preferred embodiment of the diversion
flapper 184 in accordance with the present invention. In this embodiment, the
diversion flapper 184 includes a plate 230 extending from a pin 232. The gin
232 is pivotably mounted to the output housing 152. A pair of lugs 234 extend
outwardly form opposing lateral edges of the plate 230 through a pair of slots
236 disposed opposing sides of the downhole tubular slide 170. Each of the
slots
236 include an angled portion 238 and two flat portions 240 and 242. Upon
movement of the slidable tubular section 165, lugs 234 slide through slots 236
to
WO 94129563 PCTIUS94106414
2~.~~~.~.s~
6
-22-
rotate the plate 230 for providing selective~'communication with either bore
160
or 161 (FIGURE 10).
It will be appreciated that an even more preferred embodiment of the
selective re-entry tool is described in detail hereinafter with reference to
FIGURES 25-28.
Preferably, the foregoing method of completing multilateral wells utilizes
a variety of tools having preferred constructions which will now be discussed
in
detail. In some instances, these preferred constructions are slightly
different
than the constructions of the analogous tools in the foregoing method
described
above and in this regard, the methodology of the foregoing method is also
slightly altered to use the preferred tool constructions. In particular, a
detailed
description will now be made for preferred constructions of a lateral
connector
receptacle, a scoophead assembly, a liner tie back tool, a parallel seal
assembly,
a scoophead running tool and a selective re-entry tool. In some instances, the
following detailed description will make reference to FIGURES 13A-C which are
cross-sectional assembly views showing the preferred constructions of each
tool
in an assembled unit downhale.
Turning now to FIGURES 13-15A-C, a preferred construction for a
lateral connector receptacle (shown generally at 250 in FIGURE 14) will now be
described. It will be appreciated that LCR 250 is functionally similar to the
packer bore receptacle 26; however, as will be discussed, LCR 250 has several
important differences and advantageous improvements. LCR 250 has at least
three primary functions including (1)~providing a means for running the lower
completion into the well; (2) providing a means for orienting the retrievable
whipstock and scoophead assemblies; and (3) providing a means for attaching
the
upper completion to the lower completion. A secondary function of LCR 250
includes the ability to maintain the orientation between respective lateral
completions in the event that such lateral completions are stacked within the
wellbore of one well.
t
WO 94!29563 PCT/US94/06414
-.. '
;,,.,_:;;
..,
-23-
Turning specifically to FIGURE 14, LCR 250 includes three primary
structural features (which may be arranged in any order). A first feature
includes a profile for engaging a running tool, a second feature includes an
orientation lug to orient either the whipstock assembly or scoophead/diverter
assembly and a third structural feature includes a latched thread and seal
bore to
anchor and seal, respectively. A combinatian of these features into a single
tool
enables LCR 250 to provide a novel service and it allows for the ability to
snack
- infinite laterals in a single well. With each lateral completed, LCR 250 is
the
connecting device for the diversion equipment (e.g., scoophead/diverter
assembly) at the Y juncture of the lateral as discussed in the aforementioned
method and as will be discussed in ;more detail below. While LCR 250 may
comprise a single or one piece tool housing, from a manufacturing standpoint,
LCR 250 preferably comprises three graduated (e.g., decreasing outer
diameters)
cylinders 252, 254 and 256 which are threaded together with premium
connections. In a preferred embodiment, the interiorddiameters of cylinders
252
and 254 are substantially equal (e.g., 4.75 inches) while the interior
diameter of
cylinder 256 is smaller (e.g., 3.675 inches). Upper cylinder 252 has an
internal
threaded entry 25g for receiving an anchor latch as will be discussed
hereinafter.
Downstream from threaded section 25$ is a smooth seal bore surface 260 for
receiving seals on the anchor latch. Top cylinder 252 also has an integral
guide
ring 272 to ease entry to the seal bore during stab-in, and an upset outer
diameter to keep the LCR 250 centralized in the wellbore.
Threaded to tap cylinder 252 is the orientation sub 254. Sub 254 has an
orienting lug 262 extending outwardly and radially into the inner diameter of
orientation sub 254. Orientation lug 262 is approximately rectangular in cross-
section and, as will be discussed hereinafter, mates with a slot in the anchor
latch. Lug 262 is mounted in a milled slot 270 set in a counter bore of the
premium end thread. This allows a non-pressure containing weldment for the
lug that does not interfere with the effectiveness of the premium connection.
WO 94J29563 PCTIUS94106414
21~2~1~
-24-
Downhole from orientation sub 254 and threaded thereto is connecting sub 256.
Connecting sub 256 includes a pair of spaced profiles 264 and 266 which are
sized and positioned to mate with an appropriate running tool which is
preferably
the HiR liner running tool manufactured and sold by Baker Oil Tools and shown
generally at 372 in FIGURE 22. Preferably, a bottom sub 268 is threadably
attached to the lower most end of connecting sub 256. Bottom sub 268 includes
internal threading 269 for connecting the LCR 250 to the lower completion
(such
as shown at 22 and 24 in FIGURE 2). Bottom sub has a smaller overall inner
and outer diameter than the preceding subs, the inner diameter preferably
being
2.992 inches. As is clear from the foregoing, preferably the several cylinders
252, 254 and 256 are oriented such that the running tool profile 264, 266 is
in
the bottom of the tool while the orienting lug is in the middle and the latch
thread and seal bore is in the top of the tool.
Turning now to FIGURE 13B and 15A-C, LCR 250 is shown attached to
orientation anchor 276. It will be appreciated that c,~rientation anchor 276
is the
preferred construction for the dummy whipstock anchor 36 shown in FIGURES
2 and 3. In FIGURE 13B, seals 278 from anchor 276 are Shawn in sealing
engagement with seal bore 260 of LCR 250. Orientation anchor 276 includes a
centralizes anchoring device 279 from which extends an outer housing 280.
Outer housing 280 supports the seals 278 and houses the splined mandrel 281 as
shown in FIGURES 15A-C. The splined mandrel has a V-shaped section which
progressively ,diverges tovyards an apex from which a longitudinal slot 284
extends.
Orientation anchor 276 is attached either to the retrievable whipstock
assembly or to the scoophead/diverter assembly as discussed above and mates
with LCR 250. In FIGURE 13B, the scoopheadldiverter assembly is shown
having orientation anchor 276 attached thereto and being mated to LCR 250. It
will be appreciated that when orientation anchor 276 is stabbed into the
borehole,
V-shaped surface 282 on spline mandrel 281 will eventually contact orientation
WO 94/29563 214 ~ l .~ ~ j P~T/lJJS94106414
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lug 262 which will ride along the progressively diverging V-shaped walls until
it
engages with and enters slot 284. When orientation lug 262 reaches the end of
slot 284, then it is clear at the surface that either the retrievable
whipstock
assembly or the scoopheadldiverter assembly has been appropriately positioned
and oriented within the borehole. LCR 250 thus acts as a fixed reference point
for use with both the whipstock and the scoophead systems and acts to orient
and
precisely locate all of the completion system and specifically a second
lateral
completed above the first lateral. It will be appreciated that in a single
secondary lateral open hole completion, there would be a requirement for two
LCR's. A first LCR would be run at the top of the primary wellbore completion
for the scoophead and diverter assembly to orient and seal into while the
second
LCR would be run above the selective re-entry tool to seal into with the final
production tubing to the surface. In a cased hole completion, only one LCR is
required, as the whipstock packer assembly would provide the orientation for
the
whipstock and scoopheadldiverter assembly.
Turning now to FIGURES 16-20, a preferred embodiment for a
scoophead/diverter assembly will now be described. The scoophead/diverter
assembly is shown generally at 290 and incudes a scoophead 292, a diverter sub
294, a pair of connecting struts 296 and 297 which interconnect scoophead 292
to diverter sub 294 and a length of production tubing 298 which communicates
between scoophead 292 and diverter sub 294. Scoophead 292 preferably
comprises a single piece of machined metal (steel) having spaced longitudinal
bores 300, 302 of different diameters. Larger bore 302 is a receptacle for a
liner tie back sleeve 350 shown in FIGURES 13A-B and eventually
communicates to the top of the lateral wellbore string; The smaller bore 300
is a
seal bore to tie the primary wellbore back to the surface. Below scoophead
292,
a joint of tubing 298 is threaded to small bore 300 preferably with a premium
connection 301. Tubing 198 passes through angled smooth bore 304 of diverter
sub 294 which causes the tubing joint 298 to deflect from the offset of the
small
WO 94129563 PC'rlC1S94I06414
~~~~~~ e~
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bore of scoophead 292 back to the center line of the scoophead; and thus the
center line of the borehole with which it is concentric. It will be
appreciated that
taking the offset through the length of a tubing joint 298 (typically 30 feet)
allows for a gradual bend which will not restrict the passage of wireline or
S through tubing tools for later remedial and stimulation work.
Diverter sub 294 also preferably comprises a single piece of machined
metal (steel) and along with the axial bore 304 includes an angled diverting
surface 306 for diverting the lateral wellbore string into the lateral
wellbore as
will be discussed hereinafter. As mentioned, scoophead 292 and diverter sub
294 are interconnected by a pair of parallel, spaced struts 296, 297 which are
bolted by bolts 308 to scoophead 292 and diverter sub 294 so as to rigidly fix
the
scoophead and diverter sub both axially and rotationally. By not requiring the
diverter sub 294 to be a pressure containing member or a link in the
production
tubing string, premium connections may be maintained from the scoophead 292
down to the anchoring point of the scoophead and di~erter sub assembly. Since
the window length (a window being shown at 310 in FIGURE 13) to the lateral
wellbore entry varies depending on the hole size and build angle of the
lateral.,
the distance between scoophead 292 and diverter sub 294 may be made
adjustable by varying the lengths of struts 296, 297. This is an important
feature
of the present invention since for correct functioning, scoophead 292 and
diverter
292 must straddle the lateral exit window from the primary welibore.
The terminal end 312 of production tubing 298 is coupled to orientation
anchor 276 for orientation, positioning and attachment to LCR 250 as shown in
FIGURE 13B. As will be discussed hereinafter with regard to FIGURES 29-33,
a novel scoophead/diverter assembly running tool S 10 is used to stab-in
assembly
290 into LCR 250. It will be appreciated that production tubing 298 is
maintained in rigid contact with diverter sub 294 via a pair of screws 314 as
best
shown in FIGURE 20.
As will be discussed hereinafter with respect to the liner tie back 350 of
WO 94/29563 ~' ~ ~ ~ ~ ~ ~ PCT/LJS94/06414
-27-
FIGURE 21, such liner tie back is locked within larger diameter bore 302 via a
pair of mating spring actuated dogs 303 within scoophead 292 and which are
best
shown in FIGURE 18. The Iock mechanism for the liner tie back sleeve
comprises the pair of circumferentially spaced actuate dogs 303 which are
normally urged into bore 302 by a spring 318 mounted to a cover plate 320 via
a
pair of screws 322. Each dog 303 is mounted in an opening 324 which extends
radially from bore 302. Gpening 324 includes three successive counter bores of
differing and increasing diameter. Dog 303 includes an outer ring 326 which is
supported by the shoulder of the first smaller diameter counter bore and plate
320 is supported on shoulder 328 at the intersection between the second and
third
counter bores. In addition to the spring actuated dogs 303, the larger
diameter
bore 302 of scoophead 292 includes a locating shoulder 330 for mating with a
complimentary surface on the liner tie back of FIGURE 2I. The interaction of
both the spring actuated dogs 303 and the shoulder 330 with the liner tie back
350 of FIGURE 21 will be discussed hereinafter.
a
The profiled surface 332 at the tog (or end) of scoophead 292 constitutes
an important feature of the present invention as it is configured so as to
direct
the production tubing for the lateral wellbore into the large bore 302 and
also
orients the parallel seal assembly 380 (to be discussed hereinafter with
regard to
FIGITRES 23 and 24) when tying back to the surface with a dual packer
completion or a single tubing completion. In a single tubing completion
utilizing
a selective re-entry tool, it is necessary to orient the parallel seal
assembly so
that the operator knows which wellbore is being entered by the position of the
selective re-entry tool. This orientation is accomplished by combining a
surface
334 which slopes downwardly towards and surrounds the larger bore 302 with
(1) a slotted inclined surface 336 extending from large bore 302 and
surrounding
small bore 300 and (2) a compound angled surface 338, 340 descending down
from either side of slotted surface 336. When running the lateral wellbore
tubing such as will be described hereinafter with regard to the parallel seal
WO 94/29563 PCTltJS94/06414 ,;
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assembly, if the nose of the lateral wellbore tubing first contacts sloped
surface
332, it is directed into large bore 302. However, if the nose of tubing
initially
lands over the small borehole 300, it is prevented from entering due to the
diameter of the tubing nose being wider than the slotted surface 336 over the
small borehole 300. Since the tubing nose cannot pass the slot 336, it slides
down the compound angle which also directs it to the Iarge borehole 302.
Similarly, when orienting the parallel seal assembly, the lateral wellbore
seals
which are longer than the primary wellbore seals, first contact scoophead
surface
332 and are then directed to the large borehole of the scoophead in exactly
the
same manner as described for the lateral wellbore tubing. Once the lateral
wellbore seals are directed into the correct borehole, the primary wellbore
seals
are limited in the amount of rotational misalignment they can have because the
parallel seal assembly can only pivot about the lateral wellbore seal axis by
the
amount of diametric clearance between the major diameter of the parallel seal
1; assembly and the inside diameter of the concentric main wellbore in which
they
are installed. The compound angled surfaces 338, 340 are configured such that
these surfaces will contain this amount of rotational misalignment, and apply
a
force to the primary wellbore seals to guide them into their respective seal
bore.
The final positioning of the parallel seal assembly in scoophead 292 will be
discussed with regard to FIGURE 13 subsequent to a detailed description of the
parallel seal assembly as set forth hereinafter.
The inside diameter of smaller seal bore 300 includes an appropriately
profiled recessed surface 343 for mating with scoophead running tool 510
discussed with regard to FIGURES 29-33 hereinafter. In addition, it will be
appreciated that adjacent raised profile 342 includes a forward or uphole
shoulder 344 which acts as locating stop to the completion tubing or parallel
seal
assembly (as shown in FIGURE 13).
As discussed, scoophead 290 acts to orient and anchor multiple tubing
strings at the Y juncture in an oil or gas well with multiple or lateral
wellbores.
,~~yw, WO 94!29563
PCTIUS94106414
,: ~.,;.
-29-
An advantage of the scoophead and related assemblies is to provide
communication to multiple reservoirs or tap different locations within the
same
reservoir, and enable
re-entry to these wellbores for remediation and stimulation. The large bore
302
of scoophead 290 functions to enable a secondary wellbore's production tubing
or liner to pass through until the top of the liner is in the scoophead as was
. shown in FIGURE 8 in connection with liner 202 positioned in the lateral
_ wellbore shown therein. Referring to FIGURE 13 and 21, a liner tie-back
<,sleeve
is shown at 350 which functions to thread onto the top of liner 202 and
thereafter
locate, latch and provide a seal receptacle to isolate the secondary
wellbore's
production fluids. In addition, liner tie-back sleeve 350 also includes a
running
profile for attachment to a suitable running tool as will be discussed in
connection with FIGURE 22.
Liner tie-back sleeve 350 is a cylindrical tool, and for ease of
manufacturing is comprised of two cylindrical parts including an upper
cylindrical tool portion 352 and a lower cylindrical tool portion 354. Parts
352
and 354 are threadably interconnected at threading 356. The parts are further
connected via a series of set screws 358. Lower cylindrical part 354
terminates
at a threaded opening 360 which is intended to threadably attach to lateral
completion liner 202. The remaining longitudinal and interior length of lower
part 354 comprises a smooth seal bore surface 362 for connecting either to
production tooling or to the parallel seal assembly 380 as will be discussed
hereinafter. It will be appreciated that in FIGURE 13A and C, the parallel
seal
assembly 380 is shown in sealing relationship to seal bore 362 of sleeve 350.
In
addition, the upper portion of lower part 354 includes internal threading 370
(preferably left-handed tapered, square latching thread) for attachment to an
appropriate mating surface on the parallel seal bore assembly as will be
discussed hereinafter.
Upper cylindrical part 352 of sleeve 350 includes a downwardly inclined
WO 94129563 PCT/US94106414 r~.-;.,
_30_
shoulder 364 located on the exterior of part 352 about midway the length of
part
352. Shoulder 364 acts as a locating means on the outer surface of sleeve 350
to
stop and position sleeve 350 along annular complimentary groove 330 of
scvophead 290 as best shown in FIGURE 13A. Adjacent to, and upstream from,
locating shoulder 364 is a locking groove 366 for interior locking with the
spring
actuated locking dogs 302 associated with scoophead 292. The locating shoulder
364 on the outer surface of part 352 indicates when the sleeve is located in
scoophead 292 and the locking groove 366 snap interlocks with the locking dogs
from the scoophead to provide resistance when pulling tension against the
sleeve
350. This resistance must be greater than the required shear out force of the
parallel seal assembly. The interior of upper part 352 includes spaced,
preselected profiles 368 and 369 for attachment to a suitable running tool.
Turning now to FIGURE 22, a portion of the liner tie-back sleeve 350 is
shown attached to a suitable running tool. In this case, the running tool is
an
HR running tool 372 which is a commercially available running tool
manufactured by Baker Oil Tools of Houston, Texas. HR running tool 372
operates in a known manner wherein the running tool is engaged and/or
disengaged to the interior of liner 350 at the respective profiles 368 and 369
via
a pair of disengageable gripping devices 374, 378. It will be appreciated that
during use, a secondary or lateral wellbore producing tubing such as shown at
202 in FIGURE 8 is threadably attached to threading 360 of tie back sleeve
350.
Next, running tool 372 is attached to profiles 368, 369 and the liner tie back
sleeve 350 lateral wellbore production tubing 202 assembly is stabbed-in
downhole such that the production tubing and tie back liner sleeves are
positioned into larger bore 302 until shoulder 364 on liner sleeve 350 abuts
annular shoulder 330 and the dogs 303 from scoophead 290 are locked to the
locking groove 366. Once sleeve 350 is in place and the running tool 372 is
removed, the latch threading 370 and seal bore 362 are exposed for the
parallel
seal assembly to plug into for isolating the secondary lateral wellbore. It
will be
WO 94/29553 ~ 1 ~ ~ ~ ~ ~ PCTILTS94/06414
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appreciated that by providing the seal point between the parallel seal
assembly
and the sleeve 350, there is an elimination of the need to effect a seal in
the
scoophead on the larger bore side thereof. Of course, in an alternative method
of use, rather than a parallel seal assembly being locked into sleeve 350,
other
production tubing or other tools may similarly be locked into liner tie back
sleeve 350 in a manner similar to the parallel seal assembly as shown in
FIGURE 13A.
Referring now to FIGURES 23 and 24 (as well as FIGURE 13A), a
parallel seal assembly shown generally at 380 will now be discussed. It will
be
appreciated that parallel seal assembly may function to seal the inside (bores
300
and 302) of scoophead 292. The parallel seal assembly 380 includes a pair of
parallel, offset tubing seals 382 and 384 which are each connected to a
centralizer 386. As will be discussed hereinafter, the parallel seal assembly
380
carries compressive loads on the primary wellbore side and has a shear out
mechanism on the secondary wellbore side. An important feature of the parallel
seal assembly is that it acts as the connection between the scoophead 292 and
either production tubing or more preferably, a selective re-entry tool of the
type
shown at 220 in FIGURE 9 or at 460 in FIGURES 13 and 25-26.
Centraliaer 386 comprises two axially aligned cylinders 388, 390 which
are bolted together by a pair of bolts 392. The two cylinders 388, 390 each
include two offset counter bores which respectively mate to define a pair of
parallel cylindrical bores or openings 39,4, 396. Each parallel cylindrical
bore
394, 396 includes a box coupling shown respectively at 398 and 400. Opposed
ends of each box coupling 398, 400 are threaded as shown respectively at 402a-
b, 304a-b. The upper threading 402a, 444a threadably attaches to tubing joints
406, 408, which in turn are connected either to a dual packer or to a
selective
re-entry tool 460 (as shown at FIGURE 13A). The lower threading 402b, 404b
is threadably connected to the parallel tubing/seal assemblies 382, 384,
respectively. Once the split housing 386 is bolted together, the couplings 398
WO 94/29563 ' pCT!(1S94106414
~1~~~~~~ ~
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and 400 connecting the seal assemblies 382, 384 to their respective tubing
subs
406, 408, are trapped within the counter boxes of the centralizer housing 386.
This limits the axial movement available to centralizer 386. Preferably, there
is
an additional space 410a-d on either end of couplings 398, 400 within the
counter bore so as to accommodate slightly different length tubings 406, 408.
The purpose of centralizer 386 is to elevate the seal assemblies 382, 384 off
the
wellbore wall during stab-in and to facilitate the automatic alignment feature
of
_ the parallel seal assembly and scoophead system as will be discussed
hereinafter.
Seal assembly 382 has a longer length than seal assembly 384 and is in a
mutually parallel relationship to seal assembly 384. Shorter seal assembly 384
comprises a length of tubing which terminates at a seal which is preferably a
known bonded seal shown at 412.Such bonded seals include elastomer bonded
to metal rings for durability. Also in a preferred embodiment, a bottom sub
414 is threadably attached to the terminal end of tube 384 and is locked
therein
using a plurality of set screws 416.
Longer seal assembly 382 also includes a sealing mechanism along an
exterior length thereof which is shown at 418 and again preferably comprises a
known bonded seal. In a preferred embodiment, a bottom sub 420 is threadably
attached at the terminal end of tubing 382 and is further locked therein using
a
plurality of set screws 422. It will be appreciated that seal 418 on larger
seal
assembly 382 is adapted for sealing engagement to the inner diameter seal bore
362 of tie back sleeve 350 (after tie back sleeve 350 has been latched into
,,
scoophead 292). Thus, tube 382 sealingly engages and communicates with the
secondary (lateral) wellbore production tubing string. Of course, the seal 412
on
smaller tubing assembly 384 seals into the small diameter bore 300 of
scoophead
292 and thus provides sealing engagement to any production tubing or other
completion tubing downhole from scoophead 292. The smaller seal assembly
384 thus acts to isolate the primary wellbore from the secondary or lateral
wellbore.
a
WO 94129563 ~ ~ PCTh(JS94106414 t
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Longer seal assembly 382 includes as an important feature thereof, a
locking and shear out mechanism for attachment to the latching thread 370 on
Iiner tie back sleeve 350. This locking mechanism includes a locating ring 424
pinned to tubing 382 by a plurality of pins 426. Downstream from locating ring
424 is a collet latch 428 which rests on a raised support 430 extending
upwardly
from tubing 382 such that the terminal end 436 of collet latch 428 is spaced
from
tubing 382 as shown at 437. In addition, the raised support 430 also provides
a
_ space 432 between the base 444 of collet latch 428 which abuts locating ring
424. The terminal portion 436 of collet latch 428 defines a plurality of
cantilever beams having a serrated edge 438 thereon. Preferably, the serrated
edge has a back angle of about 5° and a front angle of about
45°. Cantilever
beam 436 will deflect inwardly when seal assembly 382 is inserted into the
interior of liner tie back sleeve 350 and serrated edges 438 will interlock in
a
ratcheting manner to locking thread 370 as best shown in the enlarged view of
FIGURE 13C. Further downstream from collet latch~428 and spaced therefram
is a shear block 440 which captures a shear ring 442. Shear block 440 and
shear
ring 442 are attached to the exterior of seal assembly 382 using a shear block
retainer 444 and a plurality of set screws 446. Shear block 440 extends
outwardly from a shoulder 448 on tubing 382 so as to define a space 450
between shear block 440 and collet latch 428. The length of space 450 should
be smaller than the length of space 432 for collet latch 428 to load up on the
shoulder of shear ring 442 during insertion of seal assembly 382 and the
interlocking attachment between latched surface 438 and latch thread 370 of
the
liner tie back sleeve. Locating ring 424 provides resistance during stab-in so
as
to maintain the respective spacing 432 and 450. As best shown in FIGURE 13A
and C, when fully stabbed in, cantilever 436 will be urged downwardly into
abutting contact with shear block 440 such that longer parallel seal 382 will
be in
locking engagement with liner sleeve 350. Subsequently, when it is desired to
retrieve parallel seal assembly 380 from downhole, tension applied to the
WO 94129563 k~CT/US94/06414
F
r
- -
centralizes 386 will eventually shear ring 442 at a predetermined shear value.
When sheared, shear block 448 will be released and will move axially downward
over the outer surface of tubing 382. This will result in cantilever 436 being
allowed to freely deflect inwardly and ratchet out of its interlocking contact
with
latch thread 370. As a result, the parallel seal assembly 380 will be removed
from liner sleeve 350 as well as the scoophead 292.
The distance D between the terminal end of seal assembly 382 and the
- terminal end of seal 384 may be functionally important as it allows the
larger
seal assembly 382 to enter the desired larger bore 302 of scoophead 292 and
1U thereby align.the assembly. In a preferred embodiment, the distance D is
about
three feet. This alignment is accomplished by trapping the larger seal
assembly
382 in bore 302 and trapping the centralizes 386 within the wellbore. This
positively limits the rotational misalignment available to the smaller seal
assembly 384 prior to stabbing into scoophead 292. The parallel seal assembly
thus automatically aligns with as much as 120° rotational misalignment.
It will
be appreciated that the counter bores in the split housing 388 of the
centralizes
are preferably offset ~e.g. not symmetrical) so as to match the offset bore
arrangement in scoophead 292. In addition, since the selective re-entry tool
will
have a different offset centerline than the scoophead, centralizes 386 and the
associated tubing sub arrangement is configured to allow enough deflection in
the
tubing subs to adapt the selective re-entry tool to the scoophead.
While the selective re-entry tool depicted in FIGURES 10-12 is well
suited for its intended purposes, in a preferred embodiment,, a functionally
equivalent yet structurally improved selective re-entry tool is utilized. This
.
improved tool is shown generally at 460 in FIGURE 13, 25 and 26 and is
comprised of a flapper 462, a pair of rails 464 on either side of flapper 462,
a .
rectangular box 466, a fixed cylinder 468, an exiting sub 470, a double ended
collet 472, an attachment sleeve 474 and an alignment sub 476. Flapper 464
comprises a plate of the type depicted in the FIGURES 10-12 embodiment and
WO 94129563 ~ ~ PCTlUS94I~D6414
-35-
incl~xdes two sets of ears extending laterally therefrom. A first set of ears
478
are pivotally attached to alignment sub 476 and held in position via
attachment
sleeve 474. Ears 478 arc positioned at the lower or downhole end of flapper
464. At about midway along the longitudinal length of flapper 464 is the
second
set of ears 480. Ears 480 are the manipulation ears that allow the shifting of
the
selective re-entry tool along groove 488 which is provided in rectangular box
466. Rectangular box 466 is mounted on an inner mandrel 482 which is tied to
the box but has the ability to move longitudinally within tool 460 with
respect to
the exiting sub 470. Inner mandrel 482 is moved inside of collet 472. The
upstream end of inner mandrel 482 is connected to profiled sections 486, 487
for
engagement to a known shifting took.
Rectangular box 466 has at least two functions. First, box 466 guides the
coiled tubing workstring (or like device) through a small section so that it
does
not bind up or tend to coil back. Box 466 also includes the aforementioned
pair'
of symmetrical, laterally disposed guide slots 488 that~are used to manipulate
the
flapper from one side of the tool to the other side. Each guide slot 488
includes
an upper groove and a lower groove which are interconnected by a sloped
groove to form an elongated ramp. As mentioned, flapper 462 has two rails 464
that are mounted perpendicularly to the flapper. These rails also serve two
functions. First, the rails help guide the coiled tubing out of the box and
into
the alignment sub 474. Another important function of the rails is that they
take
part of the impact load of the coiled tubing by supporting the flapper in its
proper positions. Box 466 is connected to exiting sub 470. Exiting sub 470
allows the coiled tubing to exit out of a small bore 490 or 492 (as well as
return
therefrom) without getting stuck. As best shown in FIGURES 27 and 28, box
466 is mounted using mandrel 482 to cylindrical sub 468. Sub 468 includes
longitudinal bypass slots 496 as shown in FIGURE 28.
A coiled tubing workstring (or other like device) may be positioned
directly over one of the bores in the scoophead (or any other device located
WO 9429563 PCTI"t.TS94/06414
a
-36-
downhole of the selective re-entry tool) by deflecting off of flapper 462
which is
oriented to either opening 490 or 492 depending upon the position of the
internal
sleeve or mandrel 482 which is positioned in the upper portion of the
selective
re-entry tool. Flapper 462 is driven by the angled slots 488 located in box
466.
Whenever box 466 is in the uphole position as shown in FIGURE 25, flapper
462 lays to one side of the selective re-entry tool thus diverting the coiled
tL~bing
to enter the hole 492 on the opposite side. By moving the internal mandrel or
sleeve downhole, flapper 462 is caused to flap to the other side of the tool
thus
allowing the coiled tubing to be diverted to the other hole 490. Box 466 is
moved upwardly or downwardly by engaging a standard hydraulically actuated
shifting tool such as the HB-2 available from Baker Oil Tool into the shifting
sleeve profile 486, 487 located in the upper portion of the tool. An upstroke
or
downstroke is then applied depending upon the desired position of the flapper.
In order to go from "up°' the flapper position shown in FIGURE 25 to
the
"down" flapper position shown in FIGURE 26, a downstroke is made on the
shifting tool which causes the internal mandrel 482 to move downwardly through
the tool with respect to the exit sub 470, which in turn causes box 466 to
move
downwardly. As box 466 is moved downwardly, ears 480 will be urged and
driven upwardly along the sloped ramp of guide grooves 488 from the position
shown in FIGURE 25 to the upper position shown in FIGURE 26. As ears 480
are driven in this manner, flapper 462 will pivot along the pivot point
defined by
ears 478 into the position shown in FIGURE 26.
In accordance with an important feature of this invention, a double ended
collet 472 is provided which selectively engages either a groove 496 (as shown
in FIGURE 25) or a groove 498 (as shown in FIGURE 26) on inner mandrel
482. Double ended collet 472 is threadably connected to stationary sub 468 by
threading 500. Collet 472 remains stationary with respect to the movement of
inner mandrel 482. I-3towever, it will be appreciated that in order for inner
mandrel 482 to move in any direction, a collet snap-out force must be overcome
;.-:-WO 94J29~63 ~ ~ PCTIUS94106414
:~" Y
- -
in order to urge the interlocking rib or bump 502 from the collet out of the
groove 496 or 498. Thus, it is this collet snap-out force which must be
overcome in order to allow the box to change positions. It will be appreciated
that the collet may be easily interchanged for various snap-out forces by
simply
removing collet 472 and threadably replacing it with a different collet. Thus,
in
moving from the FIGURE 25 to the FIGURE 26 positions, interlocking rib 502
has snapped out and away from groave 496 allowing inner mandrel to move
_ downwardly whereupon rib 502 from collet 472 engages receiving groove 498
thereby locking the mandrel in the position shown in FIGURE 26.
Selective re-entry tool 460 is thus operated in the following manner: (1)
the hydraulic shifting tool is run to depth on a coiled tubing workstring
having
an appropriate shifting tool thereon; (2) the shifting tool hydraulically
engages
the profiles 486, 487 in the top of the selective re-entry tool; (3) a
shifting load
is then applied by the shifting tool sufficient to overcome the collet snap-
out
force and the inner moving sleeve or mandrel 482 is~then shifted in the
desired
direction {either up or down); (4) the shifting tool is then disengaged from
the
selective re-entry tool; and (5) a coiled tubing or similar workstring is run
through the selective re-entry tool whereby the flapper 462 diverts the tubing
string into a selected opening 490 and/or 492 which of course is mated to a
selected downhole conduit or other working tool such as the scoophead 292
discussed hereinabove.
Referring now to FIGURES,29-32, a novel running tool for use with the
scoophead/diverter assembly is shown generally at 510. Running tool 510
includes a mounting head S 12 attached to a running stump 514 and a housing
516. It will be appreciated that running stump and housing 516 are mutually
parallel and are dimensioned and configured so as to be received in the offset
bores 300, 302 in scoophead 292. Mounting head 512 includes an axially
elongated neck 518 having an internal box thread 520. Neck 518 diverges
outwardly along a skirt portion S22 to a lower head section 524 having a
larger
2~.~~~.1~
WO 94/9563 PCTltJS94l06414
-38-
diameter relative to neck 518, the diameter approximately matching the
diameter
of scoophead 292. The interior of mounting head 512 incudes an axial opening
526 in neck 518 which then slopes downwardly to define an angled bore 528
which exits lower stump 524 to define an axial offset exit bore 530. bower
stump 524 also includes a longitudinal flow opening 532 which runs from
shoulder 522 to an exit opening 534. It will be appreciated that exit opening
530
has a smaller diameter than exit opening 534 with exit opening 530 being
dimensionally configured to receive housing 516 and exit opening 534 being
dimensionally configured to receive larger diameter running stump 514.
Running stump 514 comprises a cylindrical tube which is received by
output bore 534 and is removably bolted to lower mounting head 524 by a bolt
536 received in a transversely oriented threaded passage 538 as best shown in
FIGURE 30. Running stump 514 also includes an opening 540 for the purpose
of fluid bypass on circulation during running. It will be appreciated that
flow
opening 532 communicates with the interior of exit bore 534 and hence with the
a
interior of running stump 514 so that fluid may pass from shoulder 522 through
flow opening 532 and thence through running stump 514 into larger diameter
bore 302 of scoophead 292.
Housing 516 includes an inner mandrel 542 which is movable with
respect to housing (or connecting mandrel) 516 and which is sealed to
connecting
mandrel 516 by a plurality of O-ring seals 544. Connecting mandrel 516 also
includes O-ring seals 546 about the outer periphery thereof for sealing
engagement with the small diameter bore 300 of scoophead 292. Connecting
mandrel 516 further includes at a lower end thereof a pair of openings 548,
each
of which receives a dog 550, 552. As will be discussed hereinafter, each dog
550, 552 is captured either between a raised surface 554 on inner mandrel 542
or a recessed surface 556 also on mandrel 542 and located adjacent to the
raised
surface 554. Directly upstream from recessed surface 556 between inner
mandrel 542 and connecting mandrel 516 is a shear ring 558 which, unless
W~ 94/29563 ~ ~. 4 2 ~ ~. ~ P~CT//~1S94106414
-39-
subjected to a preselected shear force, precludes movement between the
respective inner and connecting mandrels. Inner mandrel 542 also includes a
plurality of spaced ports 560 for eliminating any fluid lock problems during
operation of the running tool. The upstream portion of inner mandrel 542
includes a pump open or bypass sleeve 562 which is attached to inner mandrel
542 by a plurality of shear screws 564. As best shown in FIGURES 31 and 32,
bypass sleeve 562 is sealed to inner mandrel 542 by a pair of spaced O-ring
assemblies, each of which includes an O-ring 566 and an O-ring backup 568.
Sandwiched between sleeve 562 and outer mandrel 516 is a bypass port 5?0
through inner mandrel 542. Spaced from bypass port 542 downstream thereof is
another bypass port 572 which communicates with a shallow recess 574 on the
interior surface of outer mandrel 516. Sleeve 562 also includes a fluid port
576
for transferring fluid to the spacing between sleeve 562 and inner mandrel
542.
The lowermost portion of sleeve 562 terminates at a cylinder 578 which is
capable of riding along a bearing surface 580 on inner mandrel 542 until end
578
encounters shoulder 582.
The scoophead/diverter assembly running tool 510 is operated as follows:
First, tool 510 is attached to scoophead 292 in a manner shown in FIGURE 29
whereby dogs 550, 552 are locked into mating recesses 343 and small diameter
bore 300 of scoophead 292. The complete sub assembly which is run downhole
using running tool 510 is depicted in FIGURE 33. This is accomplished by
initially placing the dogs 550, 552 into the windows 548 of housing 516 and
then
inserting the inner mandrel 542 into the housing 516 until the raised surfaces
554
engage dogs 550, 552 and urge the dogs into mating recesses 343. At the same -
F
tame, running stump 514 is positioned in the larger diameter bore 302 of
scoophead 292 and the running stump is bolted to the mounting head 512. It
will be appreciated that scoophead 292 will be connected to the diverter as
well
as to the lower production tubing 298 and orientation anchor 276. Fluid is
circulated while running the running tool downhole (see FIGURE 29A). Once
7
i
s
~~5~~ PC7C/US94lU6414 ~:
-40-
landed, the seals 278 on the orientation anchor (which have been positioned
in,
for example, LCR 250) are tested by continuing to circulate and test the
pressure. Once the orientation anchor has been stabbed, the system is now
"closed" . At this point, pressure continues to build whereupon, at a
preselected
pressure build-up, the increasing pressure shears the shear screws 564 causing
bypass sleeve 566 to be urged downwardly along recess 582 until ends 578 of
bypass sleeve 562 are retained by shoulder 582 thereby opening the by-pass
valve (see FIGURE 29A). When by-pass sleeve 562 opens, fluid will again be
able to flow (that is, the system reverts to a "open system") whereby fluid
within
the inner mandrel 542 is allowed to flow through port 576 to the space between
bypass sleeve 562 and inner mandrel 542 and then through port 570 through .
depression 574 and finally out through port 572.
When it is confirmed that the assembly is properly seated and oriented in
the casing, that is, that the orientation anchor is properly oriented and
sealed in
LCR 250, running tool 510 is removed from scooph ~ d 292. This is
accomplished by circulating a ball 589 through axial opening 520 and opening
528 until the ball is seated against an angled ball seat 586 on bypass sleeve
562.
Bypass sleeve 562 will then apply a force {caused by circulating fluid
exerting a
force against the seated ball) to shoulder 582 urging the entire inner mandrel
542
downwardly whereby shear ring 558 will be sheared such that the recess 556 on
inner mandrel 542 will be disposed across from dogs 550, 552. At this point,
the dogs will retract into. recess 556,and out from recess 343 of scoophead
292
thereby allowing running tool 510 to be lifted from the scoophead and
withdrawn
from the hole (see FIGURE 29A).
The scoophead running tool of the present invention has many important
features and advantages. For example, the scoophead running tool 510 allows
torque to be transmitted along the centerline of the scoophead assembly in
spite
of being attached to one of the offset bores. This torque transition is
accomplished by connecting housing~516 between the running tool and the
WO 94/29563 PCT'/IT594/06414
., .. 21~~1~.~
-41-
scoophead at the same offset as the large bore of the scoophead. This transfer
of
torque is important so as to reliably manipulate the scoophead assembly
together
with the running stream. Another important feature of the running tool of the
present invention is that if the locking dogs 550, 552 (which carry the lead
during run-in) are not engaged properly into the scoophead profile, the
running
tool cannot be completely assembled. This is because the inner mandrel 542
will
not move under the locking dogs unless they are aligned.with their groove 343
and unless the inner mandrel is under the locking dogs, the mounting head of
the
running tool will not thread onto housing 516.
The aforementioned preferred embodiments of the several multilateral
completion tools, components and assemblies set forth in FIGURES 13A-C are
used in a downhole method for borehole completion which is quite similar to
the
method described with reference to FIGURES 1-9. since there are some minor
modifications to the overall method however (most of which have been discussed
above), the following discussion with reference to FhGURES 34A-J provides a
clear and concise description of the preferred method for multilateral
completion
in accordance with the present invention. Referring first to FIGURE 34A, a
cased borehole is shown at 550 which terminates at an open hole 552. A
drillpipe 554 has been stabbed down the cased borehole 550 into the open hole
552. Drillpipe 554 terminates at a known running tool such as the
aforementioned HR running tool 556. Attached to running tool 556 in a manner
described in detail above is lateral conpector receptacle (LCR) 250 and
threadably attached to LCR 250 on the downstream side thereof is a completion
string consisting of known elements including a workstring bumper sub 558, a
plurality of sliding sleeves 560, spaced ECP's 562, a workstring stinger 564
and
a snap-in/out indicating collet with seals 566. In FIGURE 34B, running tool
556 has been removed from LCR 250 and the lower completion has been set in a
known manner.
Next, in FIGURE 34C, the HR running tool and attached drillpipe 554
CA 02142113 2001-02-28
-42-
has been removed and a new drilipipe 568 has been stabbed in through cased
borehole
550 into open hole 552. Drillpipe 568 includes an MWD sub 570 which is
attached to
orientation whipstock anchor 276. Orientation whipstock anchor 276 is then
stabbed
into LCR 250 such that slot 284 on anchor 276 is engaged by lug 270 as
described in
detail above resulting in the orientation whipstock anchor 276 and LCR 250
being
mateably engaged. At this point, the MWD sub determines the radial orientation
of
the orientation whipstock anchor 276 and this information is sent to the
surface in a
known manner. This final engagement is shown in FIGURE 34D as is shown the
circulating sub 572 which is used to circulate fluid through the drilipipe and
thereby
provide a flow path for pulsed signals sent from a mud pulser in the MWD sub
which
contained the encoded information regarding orientation (which has been
acquired by
the MWD sub).
Thereafter, drillpipe 568, MWD sub 570 and circulating sub 572 are
disengaged from LCR 250 by tension to shear release orientation anchor 276 and
removed from the borehole. A retrievable whipstock system is then stabbed in
cased
borehole S50 and mated with orientation whipstock anchor (which has been snap
latch
engaged with (LCR 250). FIGURE 34E depicts a preferred retrievable open hole
whipstock assembly of the type described in aforementioned U.S. Patent No.
5,398,754. Such retrievable whipstock assembly includes a running tool 574
having a
protective housing or shroud 576 which engages a whipstock 578. Whipstock 578
includes an inflatable anchor 580 for anchoring to the walls of the open hole
552. Anchor 580 is attached to anchor 276 using a spline expansion joint 582.
Thereafter, running tool 574 and housing 576 is removed and, as shown in
FIGURE
34F, a lateral borehole or branch 584 is drilled in a known manner using drill
586
which is deflected by whipstock 578 in the desired orientation and direction.
As
shown in FIGURE 34G, drill 586 is removed followed by removal of the whipstock
578 using a whipstock removal tool 588.
WO 94129563 2 ~. ~ 2 ~.1 ~ ~'CTIUS94I06414
-43-
At this point, the assembly of FIGURE 33 including the scoophead
running tool 510, scoophead 292, tubing joint 298, diverter sub 294 and
orientation anchor 276 are stabbed in downhole to mate with LCR 250 as shown
in FIGURE 34H. Preferably, an Nib sub 570 is used to maintain the proper
orientation for ease of mating anchor 276 into LCR 250. As shown in FIGURE
34I, a suitable running tool such as HR running tool 556 is then used to run
in
liner tie back sleeve 350 in a manner described in detail above. Of course,
Liner
_ tie back sleeve 350 would have been threadably mated to the lateral
completion
string shown in FIGURE 34I which is composed of any desired and known
completion components including sliding sleeves 556 and ECP's 560. Finally, as
shown in FIGURE 34J, the parallel seal assembly 380 is assembled onto
selective re-entry tool 460 and run in down hole such that parallel seal
assembly
engages and seals to the bore receptacle in the small bore of scoophead 292 in
the bore receptacle in liner tie back sleeve 350. It will be appreciated that
the
multilateral completion components shown in the muhlateral completion of
FIGURE 34J are also shown in more detail in FIGURES 13A-C discussed
above. As can be seen in FIGURE 34J, coil tubing or the like may now be
easily stabbed in and using the selective re-entry tool 460, the coil tubing
may
enter either the main borehole 554 or the lateral borehole 584. Of course,
selective re-entry tool 460 may be removed and replaced with a single tubing
completion or a dual packer completion as may be desired. It will further be
appreciated that the multilateral completion shown in FIGURE 34J may be
repeated any desired number of times along other sections of borehole 550.
Thus, the several multilateral completion components described herein
including
2S the lateral connector receptacle, the scoopheadldiverter assembly, the
liner tie
back sleeve, the parallel seal assembly and the selective re-entry tool may
all be
used as modular components in completions of boreholes having any desired
number of lateral or branch borehole compledons.
In addition to the aforementioned features and advantages of the method
::
CA 02142113 2001-02-28
-44-
and devices of the present invention, still another important feature of this
invention
involves the use of a retrievable whipstock as an integral component used in
actually
completing two or more individual wellbores. Whipstocks have been used
historically as a means to drill additional sidetracks within a parent
wellbore. In some
instances, several sidetracks have been drilled and produced thru open hole.
However, it is not believed that prior to the present invention (as well as
the related
inventions disclosed in parent U.S. Patent No. 5,311,936), that there has been
disclosed a method which allows a whipstock to be run in the hole and set
above a
completion assembly, the whipstock then used to drill a lateral sidetrack and
the
whipstock then retrieved to allow the lower completion to be connected to be
connected to the upper lateral completion.
In contrast, an important feature of this invention is the use of a
"retrievable"
whipstock. The fact that the retrievable whipstock is used in this method is
important in that it:
(1) Combines the completion and drilling operations to make them highly
dependent upon each other for success. Current oilfield practices separates
the
drilling phase from the completion phase. Use of the retrievable whipstock to
drill a
lateral above a previously installed completion, then retrieve the whipstock
to
continue the completion process is an important and advantageous feature; and
is
believed to be hitherto unknown.
(2) The retrievable whipstock serves as the lateral position to insure the
lateral is placed in the desired angular direction. This is done by engaging
the
whipstock with the lower completion assembly by use of an orientation anchor
to
achieve the desired lateral direction/position. Once the lateral is drilled,
the
whipstock is then retrieved and the remainder of the completion installed with
a
certainty that the lateral can easily be found for re-entry due to the known
direction of
the whipstock face. The upper lateral completion
CA 02142113 2001-02-28
-45-
equipment can now be installed using the same space out and angular settings
as from
the whipstock.
(3) Conventional whipstock applications do not allow for connecting the
lateral completion above the whipstock to the completion below the whipstock
once it
has been removed.
(4) The whipstock and the completion system of this invention may be in
either the cased hole or the open hole situation; and the tools disclosed
herein may be
used in either application. It will be appreciated however, that the basic
completion
technique is the same for each condition (e.g., open or cased hole).
Still another important feature of this invention is the use of known
measurement-while-drilling (MWD) devices and tools for well completion
(including
multi-lateral well completion). While MWD techniques have been known for over
fifteen years and in that time, have gained wide acceptance, the use of MWD
has been
limited only to borehole drilling, particularly directional drilling. It is
not believed
that there has been any suggestion of using MWD techniques in wellbore
completions
despite the fact that MWD techniques are well known and widely used in
borehole
drilling. (It will be appreciated that parent U.S. Patent No. 5,311,936 does
disclose in
FIGURE 14D the use of more time consuming and therefore costlier wire-line
orientation sensing devices). It has now been discovered that MWD may be
advantageously used in wellbore completions and particularly multi-lateral
completions.
It will be appreciated that any commercial MWD system has the ability to
work in connection with this novel application. A preferred MWD system
comprises
a "Positive Pulse" type (i.e., mud pulse telemetry) which requires circulation
down
the tubing thru the bottom hole assembly. The required circulation may be
achieved
using the scoophead running tool and scoophead/diverter system. As fluid is
circulated, a pressure pulse is generated and conducted thru the fluid media
back to
the surface. This information is decoded and the angular orientation of the
bottom
hole assembly is determined.
CA 02142113 2001-02-28
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Rotational adjustments are then made at surface. One commercial example of a
suitable mud pulse telemetry system would be the DMWD system in commercial use
by Baker Hughes INTEQ of Houston, Texas. Another example of a suitable mud
pulse telemetry system is described in commonly assigned U.S. Patent
3,958,217.
Examples of successful applications of MWD in completions have been
described herein with regard to lateral wellbores which may be installed up to
depths
of 10,000 ft. or more, and which range from vertical to horizontal. When
running the
scoophead/diverter assembly 290, and also when running the parallel seal
assembly
380, it is desirable to align the tools at approximately the position at which
they will
engage the mating equipment. For example, when installing the
scoophead/diverter
assembly 290, the use of MWD will allow the operator to orientate the diverter
face
306 with the previously drilled lateral prior to landing the anchor 276 to
minimize the
torque that would be induced into the workstring if the tool were required to
self
align. In a horizontal application, the workstring may be drillpipe and could
be very
rigid, thereby preventing self alignment of the anchor. The use of MWD as a
means
of pre-aligning the system prior to landing offers increased reliability to
the
completion. Also, while the parallel seal assembly 380 has been tested and has
successfully self aligned with the scoophead 292 in the horizontal position
while
being as much as 120° out of phase, it is not desirable to rely solely
on the parallel
seal assembly to rotate the entire workstring during this self alignment
process, and
therefore MWD technology for this stage of the completion is also recommended
and
therefore preferred.
While preferred embodiments have been shown and described, various
modifications and substitutions may be made thereto without departing from the
spirit
and scope of the invention. Accordingly, it is to be understood that the
present
invention has been described by way of illustrations and not limitation.
