Note: Descriptions are shown in the official language in which they were submitted.
'~~ WO 94/29568 ~ ~ ~ : pCT/US94106421
MULTI~-LATERAL SELECTIVE REENTRY TOOL
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 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 we,l,l drilling and production have been
increasingly important 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 (or at
least companion) 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 of five, ten,
or even twenty in naturally fractured reservoirs.
~ i 4 21 i 4 ~ ;.. ~ ,, ~ ~~: ~ ~,
'CVO 94129568 y ~ ~ ~'. '' -~- <'Y ~'~ PC'TI~1S94I06421 ~''?
_2_
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 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
a
angle is 2-5 degrees per foot.
3. A medium turning radius is 300-1,000 feet;
build angle is 6-20 degrees per 100 feet.
4. A Tong 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
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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 vertical 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 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 tQ 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 we113 have been
completed using either slotted liner completion,
external casing packers (ECF'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)~perforat~ed 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 through
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
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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 several bends it may be difficult to
insert a liner with several external using packers.
Finally, it is possible to cement and perforate
medium and long radius wells as shown, for example, in
U.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
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because of insufficient geological knowledge or poor
directional control; and because of pressure
differentials in vertically displaced strata as will 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.
to 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
completed 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 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.S. Patent
2,797,893 discloses a method for completing lateral
3o wells using a flexible liner and deflecting tool. U.s.
Patent 2,397,070 similarly describes lateral wellbore
completion using flexible casing together ~rith a closure
shield for closing off the lateral. zn U.s. Patent No.
2,858,107, a removable whipstock assembly provides a
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means for locating (e._g., re-entry) a lateral subsequent
to completion thereof. U.S. Patent 3,330,349 discloses a
mandrel for guiding and completing multiple horizontal
wells. U.S. Patent Nos. 4,396,075; 4,415,205; 4,444,27 6
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 puncture
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.
Summary 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 assigned to the
assignee, a plurality of methods and devices were
provided for solving important and serious problems posed
by lateral (and especially multilateral) completion
including:
1. Methods and devices for sealing the junction
between a vertical and lateral well.
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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 related completion methods is presented. In
particular, a method is presented for completing multi-
lateral wells and maintaining selective re-entry into
those multi-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 sleeks provided
therebetween and a packer bore receptacle, therewithin
2~ (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
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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 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
r 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 oi'~ 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 or wireline methods
and thereby convey the equipment into the chosen
lateral.
In addition to the foregoing novel methods, the
present invention includes 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 scoophead/diverter assembly;
.' '-'~ WO 9412956 ~ ~ PCTlUS94/06421
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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 paint 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 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 far 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 scaophead/diver'ter assembly further provides dual
seal bares far 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
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bore 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
welibore 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
30 ft) allows for a gradual bend which will not restrict
the passage of wireline or 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 lengfh to the lateral
wellbore entry varies depending on the hole size and
build angle of the sidetrack, the distance between 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~ ifiportant 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
(:~~;WO 94129568 ~ ~ ~ PC'f/L1S94/06421
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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 scoap 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 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 bo~ehole 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 wellbare seals are limited
a
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.
The afarementioned 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
. .WO 94129568 PCT/US94/064~~
2i4~114
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remediation and stimulation. The large bare 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
for 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 wellbore. 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. Once 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.
z5 ~ 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 bore 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
~142~.14
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lateral. This parallel seal assembly has two seal
assemblies parallel to one another with one 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.
l0 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 centralizes
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 bores. This limits the axial
movement available to the centralizes. An important
feature of the cent'ralizer ~.s 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 liked and perform
the appropriate operation (e. g., stimulation, fracture,
WO 94!29568 . ~ PCT/US94/06421
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cleanout, shifting, etc.). In a ~xef erred 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, ramped
guide slots formed on opposed lateral surfaces of the
box. During operation, a known shifting tool will shift
the inner sleeve upwardly-or downwardly causing the bax
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 collet 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
CA 02142114 2004-05-14
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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. 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
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
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.
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According to one aspect of the present invention
there is provided a device for selective re-entry of
multi-lateral wells, the device being remotely
controlled by an actuator from a surface operator,
comprising:
a housing including a central bore, said central
bore including an input bore and a plurality of output
boresf
sliding means disposed within said central bore of
said housing, said sliding means being longitudinally
shiftable with respect to said housings
selecting means for selectively providing
mechanical communication between said input bore and
one of said plurality of output bores in response to
longitudinal movement of said sliding meansl and
engaging means for engaging said selecting means
wherein said sliding means is remotely controlled by
the surface operator.
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.
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Brief Descri~t~.on of the Drawings:
Referring now to the drawings%~,c~herein like
elements are numbered alike in the~'several FIGURES:
",. .
FIGURES 1-3 are sequential dgoss-sectional
elevational views depicting a 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 cruse-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;
FIGURE 14 is a cross-sectional elevation view of a
lateral connector receptacle or LCR in accordance with
the present invention;
FIGURES 15A, B and C are respective top, side and
bottom views of a portion of the orienting anchor sub;
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;
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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;
FIGURE 22 is a cross-sectional elevation view caf
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;
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 25 and 26;
FIGURES 28 is 'a cross-sectional elevation view
along the line 28-28 of FIGURE 27; .
FIGURE 29 is a cross-sectional elevation view of a
scoophead/diverter 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
WO 94129568 PCT/US941p6421
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the scoophead running tool of FIGURE 29 running in a
completian .assembly in accordance wittb~ the present
invention; and
FIGURES 34A-J are sequential~s~iagrammatic views
depicting a preferred method of ,chompleting multilateral
wellbores in accordance with the present invention.
Description of the Preferred Embodiment:
_ In accordance with the present invention, various
embodiments and methods and devices for completing
lateral, branch or horizontal wells which extend from a
single primary wellbore, -and more particularly for
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 the 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 well 16 is drilled and completed in a
known manner using a liner 18 which, for example,
r~=:=== WO 94129568 ~ ~ ~ f(:T/US9410642~1
-19-
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 packer
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 27 and a key slot 28. It will be
appreciated that the key slcst 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
WO 94/Z956$ . . P~T/IJS94/064Z1
21421i~
-20-
the lower completion, orienting the whipstock assembly
and scoaphead/diverter assembly and~praviding an
interface between the lower and uppe~','~'completions.
Next, a profile key sub 30 is.rbn into the lateral
well 16 to ascertain the orientation of the key slot 28.
The profilA 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
I 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 92 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 offixing 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
CA 02142114 2004-05-14
_21- _
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 entitled "Retrievable Whipstock
Packer Assembly" 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
8o 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
CA 02142114 2004-05-14
-22-
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. Pateat 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
l0 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 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 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
WO 94/29568 ~ ~ PCT/~JS94/0642~
-23-
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 110 is in place within the second
lateral well 72, the packers 103 are inflated, as
previously described, and the running tool 110 is then
removed.
In accordance with an important feature of the
present invention and referring to FIGURES 9 and 98, 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 sco~ophead 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 152 includes a
male portion 154 having threads 156 and a seal 158 for
mounting to the input housing 150. A pair of laterally
spaced parallel bores 160 and 161 are disposed axially
through the output housing 152. Bores 160 and 161
communicate with first output opening 96 and second
output opening 98. of the diverter and scoophead assembly
92.
The input housing 150 includes an input bore 159
which is connected to the single production tubing
i
WO 94129558 . . v ,' ~ ~ ~ PCT/US94/06421
~14211~
-24-
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~'...7~65 which
comprises an uphole tubular slide 166, a;coupling 168
and a downhole tubular slide 170. The uphole 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 lEi3.
It will be appreciated that the engagement grooves 174
function to receive keys -(not shown) of an actuator (not
shown) such as the HH-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 and 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 p'os'itioning 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 feature, the
positioning collar 182 is preferably generally thin in
cross-section and formed of a resilient material, e.g. a
''= WO 94/2956 ~ PCTIUS9410642~
-25-
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 190 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 170 and are rotatably mounted to
the collar 164. Pin 202 is disposed ~t a sufficient
distance from bores 160 and 161~of the output housing
~ 152. A pair of gears 208 and 208' are disposed on the
pin 202 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 mbve 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 pin 232 is pivotably mounted to the output
housing 152. A pair of lugs 234 extend outwardly form
WO 94/29568 PCTILTS9410t42i
;~:
214211
-26~
opposing lateral edges of the plate 230 through a pair
of slots 236 disposed opposing sides of th~~:;downhole
,..
4.. ~ .
tubular slide 170. Each of the slots 236 ..j~,~clude an
angled portion 238 and two flat portions.~~'0 and 242.
Upon movement of the slidable tubular section 165, lugs
234 slide through slots 236 to 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 rec,~ard, 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 desoriptidn will make reference to
FIGURES 13A-C which are cross-sectional assembly views
showing the preferred constructions of each tool in an
assembled unit downhole.
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
WO 94129568 . PCTIUS94/a6421
:: 2142.1 ~
_27_
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.
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 combination of these
features into a single tool enables LCR 250 to provide a
novel service and it allows for the ability to stack
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 interior diameters of
cylinders 252 and 254 are substantially equal (e. g.,
~ PGT/US94/06421 5
WO 94/29568 . (:~~ i. ~:~r, ~~' ~~ ;i; , y. ' yr
., ,: ,.. ~,
-28-
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 258 for receiving an anchor
latch as will be discussed hereinafter. Downstream from
threaded section 258 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 top 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 crass-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°~nd thread. This
allows a non-pressure containing weldment for the lug
that does not interfere with the effectiveness of the
premium connection. 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 HR
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
<~,1.~..~N.
:~ t ,a ~ ,y:
:~''°:~ WO 9412956 ,~ PCT/US94106421
-29-
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 orientation 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 shown 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 pragressively diverges towards an apex
from which a longitudinal slot 284 eRtends.
Orientation anchor 276 is attached either to the
retrievable whipstock assembly or to the
scoophead/diverter assembly as discussed above and mates
witr~ LCR 250. In FIGURE 13B, the scoophead/diverter
assembly is shown having orientation anchor 276 attached
thereto and being meted 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 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 scoophead/diverter
assembly has been appropriately positioned and oriented
within the borehole. LCR 250 thus acts as a fixed
21421~.~
WO 94!29568 :' ~' f'~. ~; ~ ~,;~:~. ...
PCT/US9410642~
.. ''
-30_
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 f or 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 whip~tock packer assembly would
provide the orientation for the whipstock and
scoophead/diverter 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 arid 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 bares 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
21~.2~-~~ ' . ' ~'
PCTlUS94I0642 !1
~'r: WO 94129568
.t.,;.
-31-
deflect from the offset of the small 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 through tubing
tools for later remedial and stimulation work.
Diverter sub 294 also preferably comprises a single
I piece of machined metal (steel) and along with the axial
bore 304 includes an angled diverting surface 306 for
diverting the lateral wel3bore 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 rotatio't~ally. 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 diverter 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 wellbore.
The terminal end 312 of production tubing 298 is
coupled to orientation anchor 276 for orientation,
214~ii4 ; ..
WO 94129568 ~ ~ .~ "' ~~,~~. , ' '?,; ~ '~ fCT'lt~S94/06421
-32-
positioning and attachment to LCR 250 as shown in FIGURE
13B. As will be discussed hereinafter with regard to
FIGURES 29-33, a novel scoopheadJdiverter assembly
running tool 510 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 FIGURE 21, such liner tie hack
I 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 lock 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. Opening 324 includes Lhree 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 21. 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.
The profiled surface 332 at the top (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
. , ..
9a~o6azx
.~:.~:wvo ga~z~ssg ~cmus
~:~: ,
-33-
large bore 302 and also orients the parallel seal
assembly 380 (to be discussed hereinafter with regard to
FIGURES 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 combinine~ 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 assembly, if the nose of the
lateral wellbore tubing first contact"~s 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 large
borehole 3f2. Simi'la~ly,"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
WO 94l295b8 . PC'I"/tJS94lOb421
2142ii4
i
.:r : '~ ..:~0 1 ~ . _ 3 4
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 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'~aised 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,I3j.
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. An
advantage of the scoophead and related assemblies is to
provide communication to m'ul'tiple reservoirs or tag
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,
21 ~ 1 ~ ~ pCT/US94/06421
W~ 94;29568
~ _ ,:
-35-
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
25 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 bor'~ 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 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 scoophead 290
WO 94/29568 PCT/US94106421~
214'114
-36-
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 .acauated locking dogs
4.
302 associated with scoophead 29.2:, 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 011 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 backrs~:eeve 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
,~-:~:'~ WO 94129568 ~ ~ PCT/US94/06421
i--: -.7
-37-
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 appreciated that by providing the seal paint
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 scooph'ead 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.
Centralizer 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
WO 94/29568 PCT/US9410g421
_38_
394, 396. Each parallel cylindrical bore 394, 396
includes a box coupling shown respect~;vely at 398 and
.,
400. Opposed ends of each box coupl~.ris~ 398, 400 are
threaded as shown respectively at 402a-b, 304a-b. The
upper threading 402a, 444a threadab~ly 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 and
400 connecting the seal assemblies 382, 384 to their
respective tubing subs 406, 408, are trapped within the
counter bores 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 f84.- 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 banded 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
'y;~-. WO 94129568 ~ ~ PC7C/LJS94/Ob421
_39_
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 sec~ndary (lateral)
wellbore production tubing string. Of course, the seal
412 on smaller tubing assembly 384 seals into the small
diameter bore 300 of sc~ophead 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 tie secondary or lateral wellbore.
Longer seal assembly 382 includes as an important
feature thereof, a locking and shear out mechanism for
attachment to the latching thread 370 on liner tieback
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 a~s 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
WO 94129568 . v. , PCT/~JS94106421
214114
~40-
.,.
will deflect inwardly when seal assembly 382 is inserted
into the interior of liner tie back-::'~s.7.eeve 350 and
..
serrated edges 438 will interlock v~~a ratcheting manner
to locking thread 370 as best show~i in the enlarged view
of FIGURE 13C. Further downstream from cdllet latch 428
and spaced therefrom 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 G, 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 looking engagemen~ with liner sleeve
350. Subsequently, when it is desired to retrieve
parallel,seal assembly 380 from downhole, tension
applied to the centralizer 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.
WO 94!29568 :: :''~ : PCTIUS94I06421
°41-
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 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 embddiment', 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
WO 94/29568 PCT1TJS941t16421 """
2142.14
-42-
embodiment and includes two sets of ears~extending
laterally therefrom. A f first set of salts 478 are
pivotally attached to alignment sub 47~6'~and held in
position via attachment sleeve 474. bars 478 are
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 4?0. 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 tool.
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 ~ram~: As mentivned,,flapper 462 his 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
;r~..:,. WO 94129568 ~ PCT/~JS94I0642~
.-~: : ..
-43-
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 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 tubing to enter the hole
492 on the opposite side. By movingathe 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 upstf'oke or' d'~wnstroke' 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
WO 94129568 PCTlUS94/06421 ','y
~1,<s~
2142114
_44_
upwardly along the sloped ramp of guide grooves 488 from
the position shown in FIGURE 25 to the user position
shown in FTGURE 26. As ears 480 are dri'v~n in this
manner, flapper 462 will pivot along ths.~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. However, it will be
appreciated that in order for inner mandrel 482 to move
in any direction, a collet snap-out force must be
overcome 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 farce 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 awajt ftom groove 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
PCTlUS94/06421
,.. .. _.
' WO 94/29568
>. ,..
-45-
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 512 attached to a running stump 514 and a
housing 516. It will be appreciated that running stump
and housing 516 are mutually paral.lei~ 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 522 to a lower head section 524
having a larger 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. Lower stump 524 also includes a longitudinal
flow gpening 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
WO 94129368 ~ '. IPCT/US94/06421
21421 ~. ~
-46-
..
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
f low opening 532 communicates with the interior of exit
bore 534 and hence with the 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 2~2. 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 ar 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 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
r-~-:: ~ ~ ' ~ PCT/US9410642I
c: ~ ~ ~ WO 94/29568
..
_47_
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 570
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'S16. 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. 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 time, 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 2'92 will be connected to the diverter as well
as to the lower production tubing 298 and orientation
WO 94129568 . ~ _. . PCT/ZJS94/06421
214~11~
-48-
anchor 276. Fluid is circulated while~,running the
running tool downhole ( see FIGURE 33 )~,.n'~~ Once landed, the
seals 278 on the orientation anchor,y'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 33). 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.
2c~ 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 scoophead 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
'::"::, WO 94129568
l~ PCT/US941U6421
(-
to be lifted from the scoophead and withdrawn from the
hole (see FIGURE 33).
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
scoophead at the same offset as the large bore of the
scoophead. This transfer of torque is important so as
to reliably manipulate th.e 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 load 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 wil~. 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
FIGUFcES 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 FIGURES 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
WO 94/29568 _ , .; . .;, PCT/US94106421
~ :.:%
2i42i1~
-50-
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 connector
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
348, 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 has been removed and a new
drillpipe 568 has been stabbed in through cased borehole
550 into open hole 552. Drillpipe 56'~ 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
LGR 250 being mateably engaged. At this point, the M6JD
sub~determines the radial orientation of the orientation
whipstock anchor 2'76' arid 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 drillpipe
and thereby provide a flow path for pulsed signals sent
from a mud pulser in the MyVD sub which contained the
encoded information regarding orientation (which has
been acquired by the MWD sub).
Thereafter, drillpipe 568, MWD sub 570 and
CA 02142114 2005-02-04
-51-
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 550 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.
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 MWD 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
WO 94!29568 ~ ~ PCT/US94l06421
X142114
-52-
composed of any desired and knawn 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 tt~ol X60 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
1G multilateral 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 a~9preciated 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 the lateral connector receptacle, the
scoophead/diverter 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 completions.
In addition to the aforementioned features and
advantages of the method 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
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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
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
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, than retrieve the whipstock to continue the
completion process is an important and advantageous
features and i.s 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 a.s 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
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direction of the whipstock face. The upper lateral
completion 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 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
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"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.
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
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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.
