Note: Descriptions are shown in the official language in which they were submitted.
CA 02329472 2001-O1-10
_2_
DECENTRALIZING, CENTRALIZING, LOCATING AND ORIENTING
SUBSYSTEMS AND METHODS FOR SUBTERRANEAN MULTILATERAL
WELL DRILLING AND COMPLETION
The present invention is directed, in general, to well drilling and
completion and more specifically to methods and systems for providing diverter
decentralization, centralization at a lateral junction and locating and
orienting for
downhole structures.
This application is a divisional application of application Serial
No. 2,156,984 filed August 25, 1995.
to Horizontal well drilling and production have become 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 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. Generally, projected productivity
from a
horizontal wellbore must triple that of a vertical wellbore for horizontal
drilling to
be economical. This increased production minimizes the number of platforms,
cutting investment and operational costs. Horizontal drilling makes reservoirs
in
~o urban areas, permafrost zones and deep offshore waters more accessible.
Other
applications for horizontal wellbores include periphery wells, thin reservoirs
that
would require too many vertical wellbores, and reservoirs with coning problems
in
which a horizontal wellbore could be optimally distanced from the fluid
contact.
Also, some horizontal wellbores contain additional wellbores extending
laterally from the primary vertical wellbores. These additional lateral
wellbores are
sometimes referred to as drainholes and vertical wellbores containing more
than
one lateral wellbore are referred to as multilateral wells. Multilateral wells
are
becoming increasingly important, both from the standpoint of new drilling
opera-
CA 02329472 2001-O1-10
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tions and from the increasingly important standpoint of reworking existing
well-
bores, including remedial and stimulation work.
As a result of the foregoing increased dependence on and importance
of horizontal wells, horizontal well completion, and particularly multilateral
well
completion, have been important concerns and continue to provide a host of
diffi-
cult problems to overcome. Lateral completion, particularly at the juncture
between the main and lateral wellbores, is extremely important to avoid
collapse
of the wellbore in unconsolidated or weakly consolidated formations. Thus,
open
hole completions are limited to competent rock formations; and, even then,
open
io hole completions are inadequate since there is no control or ability to
access (or
reenter the lateral) or to isolate production zones within the wellbore.
Coupled
with this need to complete lateral wellbores is the growing desire to maintain
the
lateral wellbore size as close as possible to the size of the primary vertical
wellbore for ease of drilling and completion.
The above concerns can be summarized in three main objectives:
connectivity, isolation and access. Connectivity refers to the mechanical
coupling
of casings in the main and lateral wellbores such that there are no sections
of
open hole between the two casings. This ensures that the multilateral
completion
is not subject to collapse of a section of open hole.
2o Isolation refers to the ability to seal off one or more wellbores, or any
selectable portion thereof, without impeding production from remaining
wellbores
or portions. To isolate one wellbore from another effectively, the casings in
the
wellbores must be hydraulically sealed (generally up to 5000 psi) to one
another
to allow the multilateral completion as a whole to withstand hydraulic
pressure.
Hydraulic sealing is particularly important at the juncture between main and
lateral wellbores. Without hydraulic sealing, either pressure is lost into the
void
that surrounds the casing or fluid or particulate contaminates are allowed to
enter
the casing from the surrounding void. While connectivity, isolation and access
are
important in both horizontal and vertical wells, they are particularly
important and
3o pose particularly difficult problems in multilateral well completions. As
mentioned
above, isolating one lateral wellbore from other lateral wellbores is
necessary to
CA 02329472 2001-O1-10
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prevent migration of fluids and to comply with completion practices and regula
tions regarding the separate production of different production zones. Zonal
(or
partial wellbore) isolation may also be needed if the wellbore drifts in and
out of
the target reservoir because of insufficient geological knowledge or poor
direc
tional control. When horizontal wellbores are drilled in naturally-fractured
reser
voirs, zonal isolation is seen as desirable. Initial pressure in naturally-
fractured
formations may vary from one fracture to the next, as may the hydrocarbon
gravity and likelihood of coning. Allowing the formations to produce together
permits crossflow between fractures. A single fracture with early water break
~o through may jeopardize the entire well's production.
Access refers to the ability to reenter a selected one of the wellbores to
perform completion work, additional drilling or remedial and stimulation work,
preferably without requiring a full drilling rig. In the most preferable
situation, any
one of the lateral wellbores can be entered using coiled tubing, thereby
saving
money.
There have been several prior art techniques of completing multilateral
wells using open-hole completion techniques. One involves the drilling of a
single
main wellbore and one or more lateral wellbores emanating from a base portion
thereof. The main wellbore is cased except for the base portion. The base
portion
2o and the one or more lateral wellbores are left open-hole. Although this
completion
technique is relatively inexpensive, not one of the above three main
objectives
(connectivity, isolation and access) is satisfied, as there are portions of
the well-
bores left open-hole, the open-hole wellbores cannot be selectively sealed
off,
except to a limited degree with open-hole isolation tools and access to the
lateral
wellbores can only be by way of bent subs or orientation devices. Apart from
the
three main objectives, if one of the lateral wellbores collapses or becomes
clogged, the entire well is threatened.
Another prior art completion technique calls for the drilling of one or
more open hole lateral wellbores from a main wellbore. A special casing having
a
~o number of inflatable open-hole packers and perforations between the
inflatable
packers is placed in the main wellbore. The inflatable packers serve to
separate
CA 02329472 2001-O1-10
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the lateral wellbores hydraulically from one another. This technique therefore
offers a degree of isolation, in that an entire lateral can be sealed off from
the
rest. However, portions of a lateral cannot be sealed off. Further, there is
neither
connectivity nor access. Finally, the lateral wellbores are left open-hole.
There-
fore, if a lateral wellbore collapses or becomes clogged, production from that
wellbore is compromised.
Conventionally, some multilateral completion techniques have
employed slotted liner completion. The primary purpose of inserting a slotted
liner
in a lateral wellbores is to guard against hole collapse. Additionally, a
liner
to provides a convenient path to insert various tools such as coiled tubing in
the
wellbore. Three types of liners have been used, namely: (1 ) perforated
liners,
where holes are drilled in the liner, (2) slotted liners, where slots of
various width
and length are milled along the line length, and (3) prepacked screens.
One prior art completion technique employing liners is similar to the
first-described open-hole completion technique, but requires the lateral
wellbores
to be fitted with liners. However, the liners terminate within the lateral
wellbores,
resulting in short lateral wellbore sections proximate the main wellbore that
are
left open-hole. Similarly, the base portion of the main wellbore is left open-
hole.
Although not as inexpensive as the first described open-hole technique, this
2o completion technique is still relatively inexpensive. However, none of the
above
three main objectives is satisfied, as portions of each lateral wellbore and
the
base portion of the main wellbore are left open-hole. The open-hole wellbores
cannot be selectively sealed off, except to a limited degree with open-hole
isola-
tion tools. Finally, access to the lateral wellbores can only be by way of
bent subs
or orientation devices. The sole advantage of this completion technique is
that
liners provide support as against erosion or collapse in the lateral
wellbores.
A second completion technique employing lined laterals involves two lateral
well-
bores extending from a main wellbore, one over the other, each having a liner
and each liner extending back to a casing in the main wellbore. Thus, connec-
ao tivity is achieved, as the liners are hydraulically sealed to the main
wellbore
casing. Unfortunately, the lower of the two lateral wellbores cannot be sealed
off
CA 02329472 2001-O1-10
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(isolated). Further, the lower of the two lateral wellbores cannot be accessed
subsequently. Thus, only one of the three principal objectives is met.
A third completion technique employing lined laterals is reserved for
new well completion and involves the drilling of multiple lateral wellbores
from a
main wellbore. A liner is inserted into the main wellbore. The liner is
provided with
windows therein corresponding to the position of the laterals. Thus, the main
wellbore liner must be oriented when it is inserted. Next, liners are inserted
into
the lateral wellbores. The open ends of the lateral wellbore liners extend
through
the windows of the main wellbore liner. This technique is designed for new
wells,
io because the location and orientation of the lateral wellbores must be prear-
ranged. Applying the three main objectives, connectivity is not present, since
the
lateral wellbore liners are not sealed to the main wellbore liner. Isolation
is possi-
ble, but access to the lateral wellbores for the purpose of reworking or
isolating a
lateral wellbore must be made by way of bent subs or orientation devices.
One further prior art completion technique does not involve either
open-hole or lined lateral wellbores. This technique requires the drilling of
a rela-
tively large main wellbore. Multiple lateral wellbores are drilled in parallel
through
the bottom of the main wellbore and spread in separate directions. The main
and
lateral wellbores are cased and sealed together. All three of the three main
20 objectives are met, as isolation of and access to each lateral wellbore are
provided. However, in most cases, only two or three lateral wellbores are
allowed, as the cross-sectional areas of the lateral wellbores must fit within
the
cross-sectional area of the main wellbore. This severely limits the cost
effective-
ness of the well as a whole, as the main wellbore must be of exceptionally
large
diameter and thus relatively expensive to drill.
The problem of lateral wellbore (and particularly multilateral wellbore)
completion has been recognized for many years as reflected in the patent
litera-
ture, For example, U.S. Patent No. 4,807,704 discloses a system for completing
multiple lateral wellbores using a dual packer and a deflective guide member.
~o U.S. Patent No. 2,797,893 discloses a method for completing lateral wells
using a
flexible liner and deflecting tool. U.S. Patent No. 2,397,070 similarly
describes
CA 02329472 2001-O1-10
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lateral wellbore completion using flexible casing together with a closure
shield for
closing off the lateral. In U.S. Patent No. 2,858,107, a removable whipstock
assembly provides a means for locating (e.g., accessing) a lateral subsequent
to
completion thereof. U.S. Patent No. 3,330,349 discloses a mandrel for guiding
and completing multiple horizontal wells. U.S. Patent Nos. 4,396,075;
4,415,205;
4,444,276 and 4,573,541 all relate generally to methods and devices for
multilat-
eral 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.
to Notwithstanding the above-described attempts at obtaining cost-
effective and workable lateral well completion, there continues to be a need
for
new and improved methods and devices for providing such completions, particu-
larly sealing between the juncture of vertical and lateral wells, the ability
to
access lateral wells (particularly in multilateral systems) and achieving zone
isolation between respective lateral wells in a multilateral well system.
There is also a need for gaining economy in lateral well completions.
Towards this end, it is highly advantageous to minimize the number of trips
necessary to drill and complete a lateral wellbore.
Several methods and systems for subterranean multilateral well drilling
2o and completion are possible. There are several problems, however, that
occur in
the environment of multilateral well drilling and completion that have, to
date, not
been addressed or solved.
The first regards placement of the diverter or drilling whipstock within
the main well flow conductor. Such diverters or whipstocks are characterized
by a
sharp toppoint. It is important that the toppoint rests against the sidewall
of the
well flow conductor.
Otherwise, if the toppoint protrudes a significant distance into the well
flow conductor, a milling or drilling bit employed to form the lateral bore
may
come into contact with the toppoint, thereby causing it and the underlying
diverter
30 or whipstock harm. While some prior art systems were directed to providing
CA 02329472 2001-O1-10
decentralization for the diverter or whipstock, such systems were not amenable
to
hollow whipstocks, wherein a large central bore must remain clear of
obstacles.
The second regards entry of tools into the lateral borehole via the window in
the
main well flow conductor. Often, reduced-diameter tools are employed to
reenter
lateral boreholes, such as those typically deployed from coiled-tube rigs for
rework purposes. The reduced-diameter tools tend to wander radially within the
main well flow conductor as they are lowered therethrough and pose a risk of
becoming jammed in or about the window or inadvertently engaging with the
periphery of the window, possible damaging the window. The prior art does not
io address radial centralization of reduced-diameter tools for guided entry
into
lateral wellbores.
Finally, it is important that subsystems employed to locate and orient
devices, such as bushings or diverters, not be harmed in their trip to the
appro
priate deployment point. Such subsystems commonly use spring-loaded keys
that bear against the sidewall of the main well flow conductor during their
trip
down. As with other tools, these keys may come into contact with the window in
the well flow conductor, inadvertently engaging therewith and potentially
harming
the window or the keys. The prior art does not provide a way of down hole
deploying such keys; nor does the prior art provide a subsystem having
separate
zo locating and set modes.
To address the above-discussed deficiencies of the prior art, it is a
primary object of the present invention to provide decentralization for a
diverter
within a main well flow conductor, a bushing for providing axial and radial
centralization within the main well flow conductor and a subsystem for
locating
and orienting objects within the main well flow conductor.
In the attainment of the primary object, the present invention, in one
aspect thereof, provides a decentralizer for a diverter, comprising: (1 )
first and
second substantially coaxial tubular members slidably coupled to one another
to
allow relative axial movement therebetween and coupled to the diverter, the
first
~o tubular member having a shoulder projecting radially outwardly from an
outer
surface thereof, the second tubular member having a conical ramp projecting
CA 02329472 2001-O1-10
_g_
radially outwardly from an outer surface thereof and (2) a decentralizing ring
slidably mounted on the outer surface of the first tubular member and between
the shoulder and the conical ramp. The first and second tubular members are
axially movable to move the shoulder and the conical ramp together. The
shoulder urges the decentralizing ring onto the conical ramp, which causes the
decentralizing ring to (a) expand eccentrically from the first and second
tubular
members, (b) engage a well flow conductor surrounding the first and second
tubular members and (c) decentralize the first and second tubular members
within the well flow conductor. The diverter is thereby decentralized within
the
~o well flow conductor.
Thus, the present invention provides the conical ramp to serve as a
foundation upon which the decentralizing ring is forcibly placed. Either or
both the
conical ramp and decentralizing ring may be eccentric to effect the
decentraliza
tion. Assuming, as in the embodiment to be illustrated, that the conical ramp
is
eccentric, the decentralizing ring becomes eccentric to the axis of the first
and
second tubular members as it is urged onto the ramp. As the decentralizing
ring
engages the inner wall of the main well flow conductor, the first and second
members are decentralized with respect thereto. Furthermore, the present inven
tion is fully employable as a decentralizer for a hollow diverter or
whipstock,
2o since, as will be illustrated, the decentralizer can have a hollow core.
In a preferred embodiment of this aspect of the present invention, an axis of
rota-
tion of the conical ramp is parallel to, and radially offset from, an axis of
the
second tubular member. Again, this is directed toward an embodiment that
employs an eccentric ramp, rather than an eccentric decentralizing ring. Those
of
skill in the art will recognize, however, that the axis of the conical ramp
can be
aparallel with respect to the axis of the second tubular member.
In a preferred embodiment of this aspect of the present invention, the
first and second tubular members are further coupled to a centralizer axially
distal
from the decentralizer, the centralizer and the decentralizer cooperable to
~o misalign an axis of the first and second tubular members with respect to
the well
flow conductor.
CA 02329472 2001-O1-10
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The present invention, in this embodiment, provides a centralized point
in the form of a distal centralizer and a decentralized point in the form of
the
decentralizer. The two cooperate to misalign the axis of the first and second
tubular members.
In a preferred embodiment of this aspect of the present invention, the
decentralizing ring is a split ring having a substantially conical inner
surface and a
substantially cylindrical outer surface.
As those of skill in the art are familiar, a split ring contains a separable
split at a location about a periphery thereof. As the split decentralizing
ring is
io urged onto the ramp, it must expand in diameter to traverse the ramp. The
sepa-
rable split accommodates this expansion.
In a preferred embodiment of this aspect of the present invention, the
decentralizer further comprises a second decentralizing ring axially offset
from
the decentralizing ring. The two rings cooperate to centralize the first and
second
tubular members with respect to the well flow conductor.
In a preferred embodiment of this aspect of the present invention, the
decentralizer is coupled to a packer. As mentioned above, the first and second
tubular members are further coupled to a centralizer axially distal from the
decentralizer. This distal centralizer may be embodied in the packer. If the
packer
2o is to function as the centralizer, the packer and the decentralizer are
then
cooperable to misalign an axis of the first and second tubular members with
respect to the well flow conductor. Otherwise, the packer simply provides at
least
a predetermined location for the decentralizer within the well flow conductor.
In a preferred embodiment of this aspect of the present invention, the
decentralizer further comprises a shear pin shearably coupling the first and
second tubular members as against axial movement. The shear pin must be
sheared before the shoulder may be moved toward the ramp; therefore, the
shear pin is a safety device as against premature, inadvertent deployment of
the
decentralizer.
~o In a preferred embodiment of this aspect of the present invention, acti-
vation of a packer associated with the decentralizer causes the shoulder to
move
CA 02329472 2001-O1-10
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toward the conical ramp. A packer may include a packer body assembly and a
tubular structure adapted to move relative to one another. The present
invention
is adapted to interface to this packer, the first and second tubular members
corresponding to the packer body assembly and the tubular structure thereof.
In a preferred embodiment of this aspect of the present invention, the
diverter is a whipstock, the whipstock decentralized within the well flow
conductor
to protect a toppoint of the diverter from destructive contact with a drilling
tool.
Thus, in this preferred embodiment, the decentralizer is a whipstock
protection
device. When the whipstock is set in place within a main well flow conductor
in
io preparation to drill a lateral borehole, it is possible that the toppoint
of the whip-
stock is not against the sidewall of the main well flow conductor. When a
milling
or drilling bit is lowered subsequently to form the lateral bore, it is
possible that
the bit may contact and damage the toppoint, compromising the function of the
whipstock as a whole. Therefore, it is important that the toppoint be against
the
sidewall of the main well flow conductor. The decentralizer of the present
inven-
tion can perform this function.
In a preferred embodiment of this aspect of the present invention, a
packer associated with the decentralizer is capable of retaining the
decentralizing
ring in engagement with the well flow conductor. The packer described above is
Zo provided with a means for retaining the packer in a set position. This
means may
be employed to retain the decentralizer in its set position, too.
The present invention, in another aspect thereof, provides a guide
bushing for use proximate a junction between a main well flow conductor and a
lateral wellbore, the guide bushing comprising: (1 ) a tubular member having a
predetermined inner diameter less than that of the main well flow conductor
and
an outer diameter sufficient substantially to centralize the guide bushing
within
the main well flow conductor, the tubular member having a bushing window
defined in a sidewall thereof, the bushing window having a defined height
thereof,
the guide bushing locatable proximate the junction, the bushing window
register-
~o able with a main well flow conductor window, the guide bushing centralizing
a tool
having a diameter less than the predetermined inner diameter with respect to
the
CA 02329472 2001-O1-10
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main well flow conductor, the bushing window protecting a periphery of the
main
well flow conductor window from contact with the tool and (2) an anchoring
structure coupled to the tubular member for fixing the tubular member at a
predetermined location and orientation within the main well flow conductor.
As discussed previously, reduced-diameter tools, such as those
deployed by coiled tubing, are liable to wander radially when lowered into the
main well flow conductor. Thus, the present invention introduces a
centralizing
mandrel that not only centralizes such reduced-diameter tools within and with
respect to the main well flow conductor, but also axially with respect to the
io window, thereby providing a reliable guide for such tools into the lateral
borehole.
Simultaneously, radial orientation of the tools is also achieved.
The window in the main well flow conductor that leads to the lateral
borehole may be rough or malformed. Further, the window maybe subject to
disturbance or destruction by way of contact with tools passing through the
window. A beneficial by-product of the guide bushing of the present invention
is
that the periphery of the window is protected from deleterious contact with
the
reduced-diameter tools.
In a preferred embodiment of this aspect of the present invention, the
tubular member is flanged at upper and lower portions thereof substantially to
2o centralize the tubular member within the main well flow conductor. Those of
skill
in the art will recognize that structures other than flanges can be used to
accom-
plish the same objective of centralizing the guide bushing.
In a preferred embodiment of this aspect of the present invention,
edges of the bushing window are tapered to protect the periphery of the main
well
flow conductor window from contact with the tool. The taper provides a smooth
edge to the bushing window for passage of tools and further protects the main
well flow conductor window.
In a preferred embodiment of this aspect of the present invention, a
lower edge of the bushing window is separated a predetermined axial distance
3o from a lower edge of the periphery of the main well flow conductor window
to
protect the lower edge of the periphery of the main well flow conductor window
CA 02329472 2001-O1-10
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from contact with the tool. This separation protects the lower part of the
main well
flow conductor window (which is a relatively sharp edge) from deleterious
contact
with the tool.
In a preferred embodiment of this aspect of the present invention, the
tool is suspended by coiled tubing. Those of skill in the art will recognize
that
there are other accepted ways for lowering tools into the main well flow
conductor.
The present invention, in yet another aspect thereof, provides a down
hole-deployable locating subsystem. The subsystem comprises a common
io mandrel having locating and orienting keys coupled thereto by first and
second
double-acting springs, respectively, and an actuating mandrel axially
displaceable
with respect thereto, the common mandrel, actuating mandrel and first and
second double-acting springs cooperable to yield three modes of operation: (a)
a
running mode in which the actuating mandrel is in a first axial limit position
with
respect to the common mandrel, the actuating mandrel placing the first and
second double-acting springs in a stowed position wherein the locating and
orienting keys are retracted radially inwardly with respect to the common
mandrel
to shield the locating and orienting keys from substantial contact with a
surrounding well flow conductor as the common mandrel traverses therethrough,
zo (b) a locating mode in which the actuating mandrel is in an intermediate
axial
position with respect to the common mandrel, the actuating mandrel placing the
first and second double-acting springs in a deployed position resiliently to
bias
the locating and orienting keys radially outwardly with respect to the common
mandrel to seek a locating and orienting profile in a honed bore on an inner
surface of the surrounding well flow conductor, wherein the honed bore incorpo-
rates a landing nipple therein, and (c) a set mode in which the actuating
mandrel
is in a second axial limit position with respect to the common mandrel, the
actu-
ating mandrel directly engaging and stiffly retaining the locating and
orienting
keys in engagement with the locating and orienting profile thereby to fix the
:;o common mandrel in a desired location and orientation with respect to the
window
in the casing.
CA 02329472 2001-O1-10
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Thus, this third aspect provides a locating/orienting key subsystem that
is downhole deployable. As mentioned previously, it is disadvantageous to risk
substantial contact between the locating or orienting keys and the sidewall of
the
main well flow conductor for the full trip to the locating and orienting
profile. Thus,
the present invention allows the keys to remain retracted into the mandrel
until
they are in the honed bore and therefore proximate the locating and orienting
profile, where they are automatically deployed.
In a preferred embodiment of this aspect of the present invention, the
subsystem further comprises a dog structure coupled to the common mandrel
~o and extending radially outwardly therefrom a distance sufficient to engage
the
surrounding honed bore, the honed bore capable of engaging the dog structure
and causing the dog structure to be moved radially inwardly with respect to
the
common mandrel, the dog structure displacing the actuating mandrel from the
first axial limit position into the intermediate axial position. Thus, in this
preferred
embodiment, the dog structure automatically senses the honed bore and causes
the keys to deploy.
In a preferred embodiment of this aspect of the present invention, the
subsystem further comprises an upper sleeve for urging the intermediate
mandrel
from the intermediate axial position into the second axial limit position only
when
2o the locating and orienting keys properly engage the locating and orienting
profile.
Thus, the present invention preferably prevents the subsystem from setting
until
both the locating and orienting keys are properly engaged.
In a preferred embodiment of this aspect of the present invention, the
subsystem further comprises a dog structure extending radially from the common
mandrel, the honed bore urging the dog structure into a first radially
retracted
position as the common mandrel traverses the honed bore in a first direction,
the
honed bore urging the dog structure into a second radially retracted position
as
the common mandrel traverses the honed bore in a second direction. Thus, the
dog structure preferably discriminates between initial downward travel through
~o the honed bore and subsequent upward travel therethrough.
CA 02329472 2001-O1-10
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In a preferred embodiment of this aspect of the present invention, the
subsystem further comprises a retention spring for retaining an associated dog
structure in a second radially retracted position. The dog retracts into the
second
radially retracted position against the urging of the retention spring. The
retention
spring then bears against a shoulder on the dog structure to retain it in the
second radially retracted position.
In a preferred embodiment of this aspect of the present invention, the
actuating mandrel comprises a vamped portion, the vamped portion moving to a
position radially inward of the first and second double-acting springs when
the
io actuating mandrel moves into the intermediate axial position to urge the
double-
acting spring into the deployed position.
In a preferred embodiment of this aspect of the present invention, the
subsystem further comprises a lock for securing the actuating mandrel in the
second axial limit position. Therefore, once the locating and orienting keys
are
properly engaged, the present invention preferably provides the lock to retain
the
actuating mandrel in the second axial limit position and thus retain the
subsystem
in the set mode.
In a preferred embodiment of this aspect of the present invention, a
shearable member shearably maintains an upper sleeve in a predetermined
Zo position with respect to the common mandrel, the upper sleeve capable of
shearing the shearable member to allow the subsystem to transition from the
locating mode into the set mode. The shearable member (illustrated to be in
the
form of a shear pin) also prevents inadvertent transitioning of the subsystem
from
the running mode into the locating mode.
In a preferred embodiment of this aspect of the present invention, the
subsystem further comprises a shearable member capable of maintaining the
subsystem in the set mode, the shearable member shearable to allow the sub-
system to transition from the set mode into the running mode to retrieve the
common mandrel. The shearable member (illustrated to be in the form of a shear
3o ring) can be sheared with substantial upward force to release the subsystem
for
retrieval from the main wellbore.
CA 02329472 2004-11-18
-16-
In a preferred embodiment of this aspect of the present invention, the
subsystem further comprises a plurality of locating keys and associated double-
acting
springs, the locating and orienting keys spaced regularly about a
circumference of the
common mandrel and cooperating to locate and orient the mandrel within the
surrounding honed bore.
Thus, there is more than one locating key in this preferred embodiment.
The plurality of locating keys yields a stronger and more distributed support
for the
common mandrel.
In a preferred embodiment of this aspect of the present invention,
pulling upward on the common mandrel causes the subsystem to transition from
the
set mode into the running mode.
In a preferred embodiment of this aspect of the present invention, a
helical guide on the inner surface above the honed bore merges with the
locating and
orienting profile, the helical guide traversing more than a complete periphery
above
the honed bore.
By "more than a complete periphery," "more than 360°" is meant.
This
ensures that, no matter the orientation of the orienting lug, it must engage
the helical
guide at some point along its length.
In a preferred embodiment of this aspect of the present invention, a
helical guide on the inner surface of the honed bore merges with the locating
and
orienting profile, the helical guide having a sidewall thereof at a non-normal
angle
with respect to an axis of the honed bore to prevent a boring tool from
inadvertently
engaging the helical guide.
In the embodiment to be illustrated, a sidewall of the helical guide is
sloped. This prevents the boring tool from engaging and harming the helical
guide.
In a preferred embodiment of this aspect of the present invention, the
first and second double-acting springs each contain a stepped portion, a
ramped
portion of the actuating mandrel traversing the stepped portion as the
actuating
mandrel moves from the intermediate axial position into the second axial limit
CA 02329472 2001-O1-10
-17-
position. The stepped portion is employed to extend the associated locating
and
orienting keys.
In a preferred embodiment of this aspect of the present invention, after
the locating and orienting keys traverse the honed bore past the locating and
orienting profile, the subsystem is transitioned into 'the locating mode and
the
locating and orienting keys traverse back to the locating and orienting
profile to
engage the locating and orienting keys therewith.
The present invention further contemplates methods of (1 ) decentral
izing a diverter, (2) providing centralization proximate a junction between a
main
io well flow conductor and a lateral wellbore and (3) deploying a locating
subsystem
within a well flow conductor.
The foregoing has outlined rather broadly the features and technical
advantages of the present invention so that those skilled in the art may
better
understand the detailed description of the invention that follows. Additional
features and advantages of the invention will be described hereinafter that
form
the subject of the claims of the invention. Those skilled in the art should
appreci-
ate that they may readily use the conception and the specific embodiment
disclosed as a basis for modifying or designing other structures for carrying
out
the same purposes of the present invention. Those skilled in the art should
also
2o realize that such equivalent constructions do not depart from the spirit
and scope
of the invention in its broadest form.
For a more complete understanding of the present invention, and the
advantages thereof, reference is now made to the following descriptions taken
in
conjunction with the accompanying drawings, in which:
FIGURE 1 illustrates a highly schematic, cross-sectional view through
a vertical portion of a subterranean well flow conductor in which a
decentralizer
embodying principles of the present invention is operatively disposed;
FIGURE 1A illustrates an enlarged cross-sectional view of a portion of
the subterranean well flow conductor and decentralizer of FIGURE 1 wherein the
3o decentralizer is in an initial running configuration;
CA 02329472 2001-O1-10
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FIGURE 1 B illustrates an enlarged cross-sectional view of a portion of
the subterranean well flow conductor and decentralizer of FIGURE 1 wherein the
decentralizer is in a subsequent deployed configuration;
FIGURE 2 illustrates a highly schematic, cross-sectional view through
a vertical portion of a subterranean well flow conductor in which the
decentralizer
of FIGURE 1, a guide bushing and a locating and orienting subsystem embody-
ing principles of the present invention are operatively disposed;
FIGURE 2A illustrates an enlarged cross-sectional view of an upper
portion of the subterranean well flow conductor and locating and orienting
to subsystem of FIGURE 2 wherein the locating and orienting subsystem is in an
initial running configuration;
FIGURE 2B illustrates an enlarged cross-sectional view of a central
portion of the subterranean well flow conductor and locating and orienting
subsystem of FIGURE 2 wherein the locating and orienting subsystem is in an
initial running mode;
FIGURE 2C illustrates an enlarged cross-sectional view of a lower
portion of the subterranean well flow conductor and locating and orienting
subsystem of FIGURE 2 wherein the locating and orienting subsystem is in an
initial running mode;
2o FIGURE 3 illustrates a cross-sectional view through a vertical portion of
a subterranean well flow conductor and locating and orienting subsystem of
FIGURE 2 wherein the locating and orienting subsystem is in a subsequent set
mode; and
FIGURE 3A illustrates an enlarged crosssectional view of a central
portion of the subterranean well flow conductor and locating and orienting
subsystem of FIGURE 3 wherein the locating and orienting subsystem is in a
subsequent set mode.
Referring initially to FIGURE 1, illustrated is a highly schematic, cross-
sectional view through a vertical portion of a subterranean well flow
conductor
30 100 in which a decentralizer, generally designated 110, embodying
principles of
the present invention is operatively disposed.
CA 02329472 2001-O1-10
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In the overall process of drilling and completing a lateral well, the first
step is to place a diverter (or whipstock) at a location and orientation
representing
where the lateral well is to branch from the main well. Accordingly, FIGURES
1,
1A and 1B illustrate structures put in place early on in the process.
The packer 120 comprises a main body structure 122, one of more
locating or orienting keys 124 and hydraulic seals 126. A muleshoe coupler 128
allows the decentralizes 110 to be releasably coupled to the packer 120.
A diverter 130 is coupled to the packer 120 via the decentralizes 110.
The diverter 130 is, in the illustrated embodiment, a whipstock having a
hardened
1o slanted face capable of diverting boring tools, such as milling and
drilling bits and
a drillable core, allowing the whipstock to remain in place following the
formation
of a lateral borehole in a manner previously described.
The decentralizes 110 comprises first and second decentralizing rings
112, 114 that cooperate with an eccentric ramp 115 (not detailed in FIGURE 1,
but fully detailed in FIGUREs 1 A and 1 B) to decentralize the diverter 130
with
respect to a centerline of the well flow conductor 100. In the illustrated
embodi-
ment, the exterior surface of the ramp 115 is eccentric. However, it is fully
contemplated that the interior surface of the decentralizing rings 112, 1 14
may
be eccentric. Decentralization causes the diverter 130 to move in the
direction
2o shown by an arrow 132, thereby protecting a toppoint 134 of the diverter
130
from possible harm caused by contact with a boring tool.
The decentralizes 110 further comprises first and second tubular
members 116, 118. The first tubular member 116 has a shoulder 119 associated
therewith that projects radially outwardly from the first tubular member 116.
The
shoulder 119 is adapted to engage the decentralizing rings 112, 114 to urge
the
rings 112, 114 onto the eccentric ramp 115. As is apparent from FIGURE 1, both
the first and second tubular members 116, 118 extend downwardly to the packer
120. In the illustrated embodiment, the diverter 130 moves downwardly under
the
mass of the drillstring, moving the first and second tubular members 116, 118
3o axially with respect to one another against the packer 120. This urges the
decen-
tralizing rings 112, 114 onto the eccentric ramp 115, thereby setting the
decen-
CA 02329472 2001-O1-10
-20-
tralizer 110: The packer 120 further retains the decentralizer 110 in the set
position.
Turning now to FIGURE 1 A, illustrated is an enlarged cross-sectional
view of a portion of the subterranean well flow conductor 100 and decentral-
izer 110 of FIGURE 1 wherein the decentralizer 110 is in an initial running
configuration.
Again, FIGURE 1A shows first and second decentralizing rings 112,
114, an eccentric ramp 115, first and second tubular members 116, 118 and a
shoulder 119 associated with the first tubular member 116.
io In the illustrated embodiment, an axis of rotation of the conical
ramp 115 is parallel to, and radially offset from, an axis of the second
tubular
member 118. In practice, this is accomplished by first turning the second
tubular
member 118 in a lathe and then offsetting the second tubular member 118 in the
lathe, maintaining the second tubular member's orientation. Those of skill in
the
art will doubtless recognize, however, that the axis of the conical ramp 115
can
be aparallel with respect to the axis of the second tubular member 118.
In the illustrated embodiment, the first and second decentralizing rings
112, 114 are split rings having substantially conical inner surfaces and
substan-
tially cylindrical outer surfaces. The substantially conical inner surfaces
allow the
2o decentralizing rings 112, 114 to traverse the conical ramp 115 without
undue
stress. The substantially cylindrical outer surfaces allow the decentralizing
rings
112, 114 to engage the well flow conductor 100 as designed.
As those of skill in the art are familiar, a split ring contains a separable
split at a location about a periphery thereof. As the decentralizing rings
112, 114
are urged onto the eccentric ramp 115, they must expand in diameter to
traverse
the eccentric ramp 115. The separable split accommodates this expansion.
In the illustrated embodiment, the decentralizer 110 further comprises a
shear pin 113 shearably coupling the first and second tubular members 116, 118
as against axial movement. The shear pin 113 must be sheared before the
3o shoulder 119 may be moved toward the eccentric ramp 115. Therefore, the
shear
CA 02329472 2001-O1-10
-21 -
pin 113 is a safety device as against premature, inadvertent deployment of the
decentralizer 110.
Turning now to FIGURE 1 B, illustrated is an enlarged cross-sectional
view of a portion of the subterranean well flow conductor 100 and
decentralizer
110 of FIGURE 1 wherein the decentralizer 110 is in a subsequent deployed
configuration. Thus, the first tubular member 116, under the influence of the
underlying packer (120 of FIGURE 1 ) has moved relative to the second tubular
member 118, shearing the shear pin 113. The shoulder 119 has engaged the first
and second decentralizing rings 112, 114, urging them onto the eccentric
io ramp 115 and into engagement with the well flow conductor 110. Because the
ramp 115 is illustrated as eccentric, the first and second tubular members
116,
118 are thereby decentralized with respect to a central axis, or centerline,
of the
well flow conductor 100. This, again, decentralizes the diverter (130 of
FIGURE
1 ). An interference ring 111 prevents overextension of the ramp 115 with
respect
to the shoulder 119 by transmitting only a limited amount of force from the
second tubular member 118 to the ramp 115 before sliding. In this manner, the
interference ring 111 acts as a force limiting device and prevents the
diverter 130
from being decentralized with too great a force.
From the above, it is apparent that one aspect of the present invention
2o provides a decentralizer for a diverter, comprising: (1 ) first and second
substan-
tially coaxial tubular members slidably coupled to one another to allow
relative
axial movement therebetween and coupled to the diverter, the first tubular
member having a shoulder projecting radially outwardly from an outer surface
thereof, the second tubular member having an eccentric conical ramp projecting
radially outwardly from an outer surface thereof and (2) a decentralizing ring
slidably mounted on the outer surface of the first tubular member and between
the shoulder and the conical ramp. The first and second tubular members are
axially movable to move the shoulder toward the conical ramp. The shoulder
urges the decentralizing ring onto the conical ramp, which causes the
decentral-
~o izing ring to (a) expand eccentrically from the first and second tubular
members,
(b) engage a well flow conductor surrounding the first and second tubular
CA 02329472 2001-O1-10
-22-
members and (c) decentralize the first and second tubular members within the
well flow conductor.
Turning now to FIGURE 2, illustrated is a highly schematic, cross-
sectional view through a vertical portion of a subterranean well flow
conductor
100 in which the decentralizer 110 of FIGURE 1, a guide bushing 200 and a
locating and orienting subsystem 300 embodying principles of the present inven-
tion are operatively disposed.
In the overall process of drilling and completing a lateral well, once the
lateral wellbore is formed, a liner is placed into the lateral wellbore and
cemented
io therein. Depending upon whether the liner extends into the main well flow
conductor to block the same, a portion of the liner must be removed. Once the
liner portion has been removed, the lower portion of the main well flow
conductor
is reestablished and the process continues. At this point, the present
invention,
as illustrated, calls for the placement of a guide bushing at the junction of
the
main and lateral wells primarily to centralize reduced-diameter tools radially
within the main well flow conductor proximate the junction and, secondarily,
to
protect the window to the lateral from damage by contact with the tools.
Accord
ingly, FIGURE 2 illustrates the guide bushing structure and an anchoring struc
ture therefor, the anchoring structure preferably comprising the locating and
20 orienting subsystem of the present invention.
FIGURE 2 shows the main well flow conductor 100 within a main well-
bore 101. A lateral wellbore 102 extends from the main wellbore 101 and
contains a liner 103 cemented into place. A main well flow conductor window
104
exists at the junction of the main and lateral wellbores 101, 102. It is the
integrity
of the main well flow conductor window 104 and the reliability of diversion of
tools
into the liner 103 that the guide bushing 200 of the present invention is
directed.
Accordingly, the guide bushing 200 comprises a tubular member 210
having a predetermined inner diameter 212 less than that of the main well flow
conductor 100 and an outer diameter 214 sufficient substantially to centralize
the
3o guide bushing 200 within the main well flow conductor 100. The tubular
member
210 has a bushing window 220 defined in a sidewall thereof. The bushing window
CA 02329472 2001-O1-10
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220 has a defined height and is located proximate the junction of the main and
lateral wellbores 101, 102 (i.e., across from the main well flow conductor
window
104). The bushing window 220 is therefore registered with the main well flow
conductor window 104. Since the inner diameter 212 of the guide bushing is
less
than that of the main well flow conductor 100, the guide bushing 200
centralizes
tools having a diameter less than the predetermined inner diameter 212 with
respect to the main well flow conductor 100. Further, the bushing window 220
protects a periphery of the main well flow conductor window 104 from contact
with the tool by virtue of the bushing window 200.
io In the illustrated embodiment, the tubular member 210 is flanged at
upper and lower portions thereof substantially to centralize the tubular
member
210 within the main well flow conductor 100. Those of skill in the art will
recog-
nize that structures other than flanges can be used to accomplish the same
objective of centralizing the guide bushing 200.
In the illustrated embodiment, edges 222 of the bushing window 220
are tapered to protect the periphery of the main well flow conductor window
104
from contact with the tool. The taper provides a smooth edge to the bushing
window 220 for passage of tools and further protects the main well flow
conductor
window 104.
2o In the illustrated embodiment, a lower edge of the bushing window 220
is separated a predetermined axial distance from a lower edge of the periphery
of
the main well flow conductor window 104 to protect the lower edge of the
periphery of the main well flow conductor window 104 from contact with the
tool.
This separation protects the lower part of the main well flow conductor window
104 (which is a relatively sharp edge) from deleterious contact with the tool.
The guide bushing 200 is held at a desired location and orientation
within the packer 120 within by an anchoring structure 230 comprising the
subsystem 300 of the present invention. The hollow packer 120 and the hollow
whipstock 130 cooperate to form an orienting landing nipple or honed bore in
3o which the anchoring structure 230 is located and oriented. A portion of the
orienting landing nipple is honed to a fine finish, thence the reference to
the
CA 02329472 2001-O1-10
-24-
landing nipple as a honed bore. The honed bore fits within, and therefore has
a
smaller inner diameter than the main well flow conductor 100.
In a manner to be described more particularly with reference to
FIGUREs 2A, 213, 2C, 3 and 3A, the subsystem 300 serves releasably to place
the guide bushing 200 at its predetermined location and orientation within the
honed bore. FIGURE 2 further shows a deflector 240 in place. The deflector 240
acts as a diverter in the sense that it deflects objects within and with
respect to
the wellbore. Unlike the diverter 130 of FIGURE 1, however, the deflector 240
is
preferably not a hardened whipstock, but instead is designed to deflect
inserted
~o tools and the like into the lateral wellbore 102. As with the guide bushing
200, the
deflector 240 is held in place by an anchoring structure 250, preferably
including
the locating and orienting subsystem 300 of the present invention that fits
within a
honed bore defined within the anchoring structure 230. If it is desired to
enter the
portion of the main well flow conductor 100 below the deflector 240 or allow
flow
through the conductor 100, the deflector 240 should be removed.
From the above, it is apparent that another aspect of the present
invention provides a guide bushing for use proximate a junction between a main
well flow conductor and a lateral wellbore, the guide bushing comprising: (1 )
a
tubular member having a predetermined inner diameter less than that of the
main
2o well flow conductor and an outer diameter sufficient substantially to
centralize the
guide bushing within the main well flow conductor, the tubular member having a
bushing window defined in a sidewall thereof, the bushing window having a
defined height thereof, the bushing locatable proximate the junction, the
bushing
window registerable with a main well flow conductor window, the bushing
centralizing a tool having a diameter less than the predetermined inner
diameter
with respect to the main well flow conductor, the bushing window protecting a
periphery of the main well flow conductor window from contact with the tool
and
(2) an anchoring structure coupled to the tubular member for fixing the
tubular
member at a predetermined location and orientation within the main well flow
~o conductor.
CA 02329472 2001-O1-10
-25-
Turning now concurrently to FIGUREs 2A, 2B and 2C, illustrated is an
enlarged cross-sectional view of upper, central and lower portions of the
subter-
ranean well flow conductor 100 and locating and orienting subsystem 300 of
FIGURE 2 wherein the locating and orienting subsystem 300 is in an initial
running mode.
The subsystem comprises a common mandrel 320. The common
mandrel 320 has a locating key 310 and an orienting key 360 coupled thereto by
first and second double-acting springs 330, 370, respectively. The common
mandrel 320 is slidably coupled to an actuating mandrel 350 axially
displaceable
io with respect thereto. The common mandrel 320, actuating mandrel 350 and
first
and second double-acting springs 330, 370 cooperate to yield three modes of
operation for the subsystem 300.
In a first, running mode (shown in FIGURES 2A, 2B and 2C), the
actuating mandrel 350 is in a first axial limit position (displaced upwards,
as
shown) with respect to the common mandrel 320. In this position, the actuating
mandrel 350 places the first and second double-acting springs 330, 370 in a
stowed position wherein the locating and orienting keys 310, 360 are retracted
radially inwardly with respect to the common mandrel 320 to shield the
locating
and orienting keys 310, 360 from substantial contact with the surrounding well
2o flow conductor (100 of FIGURE 2) as the common mandrel 320 traverses
therethrough.
In a second, locating mode, the actuating mandrel 350 is in an
intermediate axial position with respect to the common mandrel 320. In this
position, the actuating mandrel 350 places the first and second double-acting
springs 330, 370 in a deployed position resiliently to bias the locating and
orienting keys 310, 360 radially outwardly with respect to the common mandrel
320 to seek the locating and orienting profile on the inner surface of the
surrounding honed bore (comprising the hollow cores of the packer 120 and the
whipstock 130 of FIGURE 2). More specifically, a vamped portion 352 of the
3o actuating mandrel comes into contact with stepped portions 332, 372 or the
first
and second double-acting springs 330, 370. This contact rotates the first
second
CA 02329472 2001-O1-10
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double-acting springs 330, 370 outward into the deployed position. The keys
310,
360 are biased outward, but are not allowed actually to travel completely
outward
until they fully engage the locating and orienting profile.
As will be illustrated in FIGURE 3A, the locating and orienting profile
comprises a series of annular recesses and projections designed to engage with
corresponding recesses and projections on an outer surface 312 of the locating
key 310. At one location along the perimeter of the recesses and projections,
an
axial trench is formed. The orienting key 360, having a flat outer surface
362, is
designed to fall into the axial trench, thereby ensuring orientation of the
central
to mandrel 320 with respect to the axial trench in the landing nipple. As will
also be
illustrated, a helical guide wraps around a periphery of the landing nipple,
leading
to the axial trench. The helical guide is designed to engage the orienting key
360,
drawing it toward proper engagement with the axial trench as the central
mandrel
320 is moved axially.
If the central mandrel 320 is neither axially located nor radially oriented
properly, neither of the keys 310, 360 will extend fully radially outward in
engagement with the locating and orienting profile. If the central mandrel 320
is
located but not oriented, the locating key 310 extends and engages the
profile,
but the orienting key 360 cannot, as the projections in the profile prevent
any
2o engagement. If the orienting key 360 is extended, but the central mandrel
320 is
not located, the orienting key is in the helical guide, but the locating key
cannot
extend to engage the profile. Only when the central mandrel 320 is fully
located
and oriented can both the locating and orienting keys 310, 360 extend,
allowing
the subsystem 300 to transition to a set mode.
In the third, set mode, the actuating mandrel 350 is in a second axial
limit position (detailed in FIGURE 3A) with respect to the common mandrel 320.
This set mode is only allowed when all of the keys 310, 360 are fully extended
radially outward (meaning that the common mandrel 320 is both located and
oriented). The ramped portion 352 of the actuating mandrel can then pass the
3o stepped portions 332, 372 of the first and second double-acting springs
330, 370
(downward as shown), enabling the ramped portion of the actuating mandrel 350
CA 02329472 2001-O1-10
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directly to engage and stiffly retain the locating and orienting keys 310, 360
in
engagement with the locating and orienting profile. When directly engaged and
stiffly retained, the keys 310, 360 cannot retract radially. Therefore, the
common
mandrel 320 is fixed in the desired location and orientation with respect to
the
honed bore.
Having primarily described the interaction of the common mandrel 320,
the actuating mandrel 350, the first and second double-acting springs 330, 370
and the locating and orienting keys 310, 360, an "arming" structure for
placing the
subsystem 300 in the locating mode will be described. With particular
reference
io to FIGURE 2A, the subsystem 300 further comprises a dog structure 390 that
is
coupled to the common mandrel 320 and extends radially outwardly therefrom a
distance sufficient to engage the surrounding honed bore.
As the common mandrel 320 is lowered through the main well flow
conductor, the diameter thereof is sufficiently large to allow the dog
structure 390
to pass. However, once the common mandrel encounters the honed bore, the
diameter of the honed bore is insufficient to allow the dog structure 390 to
pass in
its radially extended configuration. Since the common mandrel 320 is being
lowered, the honed bore will engage the outer surface of the dog structure
390,
forcing the dog structure upwards, as shown, until the dog structure 390 falls
into
2o a first recess 392 and thereby assumes a first radially retracted position.
The
common mandrel 320 continues to be lowered until the dog structure emerges
from the bottom of the honed bore and again into the larger diameter main well
flow conductor. Under influence of a spring 396, the dog structure 390 again
assumes a radially outward position.
At this point, the common mandrel 320 is raised. This causes engage-
ment of the re-extended dog structure 390 with the bottom of the honed bore.
This time, however, the dog structure 390 is forced downward as shown, until
the
dog structure 390 falls into a second recess 394 and thereby assumes a second
radially retracted position. A retention spring 340 is compressed when the dog
3o structure 390 falls into the second recess 394. This compression retains
the dog
CA 02329472 2001-O1-10
-28-
structure 390 in the second recess until such time as workers on the drilling
rig
reset the dog structure 390 manually.
As the dog structure 390 is moved into the second radially retracted
position, the dog structure 390 displaces the actuating mandrel 350 from the
first
axial limit position into the intermediate axial position. Thus, the dog
structure 390
automatically senses that the common mandrel 320 is being drawn upwards
through the honed bore and causes the keys 310, 360 to deploy. The subsystem
300 is now in its locating mode.
Once the keys 310, 360 are properly engaged in the locating and
io orienting profile, it is time to transition the subsystem 300 into the set
mode.
Accordingly, the subsystem 300 further comprises an upper sleeve 380 for
urging
the intermediate mandrel 350 from the intermediate axial position into the
second
axial limit position only when the locating and orienting keys 310, 360
properly
engage the locating and orienting profile. Again, the ramped portion 352
cannot
slide under the keys 310, 360 until they are properly engaged.
To urge the intermediate mandrel 350 from the intermediate axial
position into the second axial limit position, mass placed on the upper sleeve
380
first shears a shearable member 382 (a shear pin), thereby freeing the upper
sleeve to slide axially with respect to the common mandrel. The upper sleeve
380
2o and the actuating mandrel move downwardly until the vamped portion 352 is
radially aligned with the keys 31, 360, thereby locking them in their extended
engagement.
The subsystem further comprises a lock 342 for securing the actuating
mandrel 350 in the second axial limit position. The lock 342 engages a
shoulder
344 on the inner diameter of the actuating mandrel 350.
If it is subsequently desired to retrieve the common mandrel 320,
significant upward force on the common mandrel 320 places shear stress on
shearable member 314 la shear ring). The shearable member 314 shears,
removing the vamped surface 352 from under the keys 310, 360, allowing them
3o to disengage and retract radially inwardly for the trip to the surface.
CA 02329472 2001-O1-10
-29-
Turning now to FIGURE 3, illustrated is a cross-sectional view through
a vertical portion of a subterranean well flow conductor and locating and
orienting
subsystem of FIGURE 2 wherein the locating and orienting subsystem 300 is in
the subsequent set mode. FIGURE 3 is presented primarily for the purpose of
establishing the relationship of the subsystem 300, detailed in FIGUREs 2A-2C
and a corresponding locating and orienting profile provided on the inner
surface
of a surrounding honed bore. Again, in the illustrated embodiment, the
"surrounding honed bore" is the hollow core of the packer 120. The
"surrounding
honed bore" could be the hollow core of the main well flow conductor 100 or
io some other hollow structure into which the subsystem 300 may be inserted.
Turning now to FIGURE 3A, illustrated is an enlarged cross-sectional
view of a central portion of the subterranean well flow conductor 100 and
locating
and orienting subsystem 300 of FIGURE 3 wherein the locating and orienting
subsystem 300 is in a subsequent set mode.
In the illustrated embodiment, a helical guide 410 on the inner surface
of the honed bore (in this case, the packer 120) engages the orienting key 360
associated with the common mandrel 320. The helical guide 410 traverses more
than a complete periphery of the surrounding body. By "more than a complete
periphery," "more than 360°" is meant. This ensures that, no matter the
orienta-
2o tion of the orienting lug 360, it must engage the helical guide 410 at some
point
along its length. Additionally, the helical guide 410 has a sidewall 412
thereof at a
non-normal angle with respect to an axis of the surrounding body to prevent a
boring tool from inadvertently engaging the helical guide 410. Thus, the
sidewall
412 of the helical guide 410 is sloped. This prevents the boring tool from
engag-
ing and harming the helical guide 410.
From the above, it is apparent that yet another aspect of the present
invention provides a downhole-deployable locating and orienting subsystem,
comprising a common mandrel having locating and orienting keys coupled
thereto by first and second doubleacting springs, respectively, and an
actuating
3o mandrel axially displaceable with respect thereto, the common mandrel,
actuating
mandrel and first and second double-acting springs cooperable to yield three
CA 02329472 2001-O1-10
-30-
modes of operation: (a) a running mode in which the actuating mandrel is in a
first axial limit position with respect to the common mandrel, the actuating
mandrel placing the first and second double-acting springs in a stowed
position
wherein the locating and orienting keys are retracted radially inwardly with
respect to the common mandrel to shield the locating and orienting keys from
substantial contact with a surrounding well flow conductor as the common
mandrel traverses therethrough, (b) a locating mode in which the actuating
mandrel is in an intermediate axial position with respect to the common
mandrel,
the actuating mandrel placing the first and second double-acting springs in a
~o deployed position resiliently to bias the locating and orienting keys
radially
outwardly with respect to the common mandrel to seek a locating and orienting
profile on an inner surface of a surrounding honed bore within the surrounding
well flow conductor and (c) a set mode in which the actuating mandrel is in a
second axial limit position with respect to the common mandrel, the actuating
mandrel directly engaging and stiffly retaining the locating and orienting
keys in
engagement with the locating and orienting profile thereby to fix the common
mandrel in a desired location and orientation with respect to the honed bore.
Although the present invention and its advantages have been
described in detail, those skilled in the art should understand that they can
make
2o various changes, substitutions and alterations herein without departing
from the
spirit and scope of the invention in its broadest form.
