METHOD FOR ISOLATING MULTI-LATERAL WELL COMPLETIONS WHILE MAINTAINING SELECTIVE DRAINHOLE RE-ENTRY ACCESS

PROCEDE PERMETTANT D'ISOLER LES COMPLETIONS D'UN PUITS COLLECTEUR TOUT EN MAINTENANT UN ACCES SELECTIF DE RENTREE DANS UN PUITS DE DRAINAGE

English Abstract

In a cased wellbore (10) having one or more cased and cemented drainholes
(24) extending therefrom such that the elliptical shaped opening (46) or
junction of
each drainhole (24) with the primary well (10) is sealed and cut flush with
the inside
of the primary well casing (18), an inventive method and system is disclosed
for. (a)
isolating each perforated and/or drainhole completion (108, 126) within the
primary
wellbore (10), (b) providing flow control means (162, 164) for each completion
(108,
126) to permit selective testing, stimulation, production, or abandonment, and
(c)
facilitating selective re-entry into any cased drainhole (24) for conducting
additional
drilling, completion, or remedial work.

French Abstract

Dans un puits de forage (10) tubé présentant un ou plusieurs puits de drainage (24) tubés, fixés par cimentation et s'étendant à partir du puits initial de manière à ce que l'ouverture (46) de forme elliptique ou jonction de chaque puits de drainage (24) avec le puits (10) initial soit scellée et coupée affleurante avec l'intérieur du tubage (18) du puits initial, on a prévu un procédé et système inventifs destinés: (a) à isoler chaque complétion (108, 126) perforée et/ou puits de drainage dans le puits (10) de forage initial, (b) à monter des moyens (162, 164) de régulation du débit pour chaque complétion (108, 126) afin de permettre sélectivement un essai, une stimulation, une production ou un abandon, et (c) à faciliter une rentrée sélective dans tout puits de drainage (24) tubé, afin d'effectuer un forage, une complétion ou un ouvrage de protection additionnels.

Claims

The embodiments of the present invention in which an
exclusive property or privilege is claimed are defined as
follows:
1. A subterranean well system comprising:
a primary wellbore penetrating a hydrocarbon bearing
formation;
a first deviated wellbore intersecting the primary
wellbore at a first opening and having a first wellbore
section extending into the formation;
a second deviated wellbore intersecting the primary
wellbore at a second opening and having a second wellbore
section extending into the formation in a direction
different from the first deviated wellbore;
means establishing direct communication between the
primary wellbore and the formation;
a first production liner assembly in the primary
wellbore, the first production liner assembly comprising a
first conduit having a first seal device, multiple first
packers straddling the first opening and isolating the
first deviated wellbore, a first precut liner window
between the first packers allowing re-entry into the first
deviated wellbore, a first indexed orientation profile
device facilitating alignment of the first precut liner
window with the first opening and subsequent re-entry into
the first deviated wellbore, first sealing profile devices
straddling the first precut liner window for subsequent
installation of a retrievable first openable flow control
device to selectively allow and prevent flow between the
first deviated wellbore and the first conduit:
means to align the first precut liner window with the
first opening;

31




a second production liner assembly in the primary
wellbore, the second production liner assembly comprising a
second conduit having a second packer isolating the second
deviated wellbore, a second precut liner window allowing
re-entry into the second deviated wellbore, a second
indexed orientation profile device facilitating alignment
of the second precut liner window with the second opening
and subsequent re-entry into the second deviated wellbore,
second sealing profile devices straddling the second precut
liner window for subsequent installation of a retrievable
second openable flow control device to selectively allow
and prevent flow between the second deviated wellbore and
the second conduit, and a second seal device for engagement
with the first seal device; and
means to align the second precut liner window with the
second opening;
wherein the first production liner assembly further
includes a third packer for isolating the direct
communication means, and a third openable flow control
device selectively allowing and preventing flow between the
direct communication means and the first conduit.

2. The system of claim 1, wherein the primary wellbore
may be substantially vertical, substantially horizontal or
otherwise intentionally deviated.

3. The system of claim 1 or 2, wherein the primary
wellbore and the first and second deviated wellbores
extending from the primary wellbore are cased using
respective casing strings.

4. The system of claim 3, wherein annuli formed between
the casing strings and the respective primary wellbore and

32




first and second deviated wellbores are at least partially
filled with an impermeable cement sheath.

5. The system of claim 4, wherein respective junctions
between each of the first and second deviated wellbores and
the primary wellbore are sealed and generally conformable
or flush with an interior of the primary wellbore casing
string.

6. The system of claim 4 or 5, wherein the direct
communication means between the primary wellbore and the
formation comprises perforations in the primary wellbore
casing string.

7. The system of any one of claims 1 to 6, wherein each
of the first and second indexed orientation profile devices
comprises a first pipe section with an orientation guide
key slot indexed to a respective one of the first and
second precut liner windows, thereby facilitating alignment
of each of the first and second precut liner windows with a
respective one of the first and second openings and
subsequent selective re-entry into a respective one of the
first and second deviated wellbores.

8. The system of claim 7, wherein each of the first and
second indexed orientation profile devices further
comprises a second pipe section with a polished sealing
profile providing sealing means for subsequent installation
of a respective one of the first and second openable flow
control devices to selectively allow and prevent flow
between the respective one of the first and second deviated
wellbores and a respective one of the first and second
conduits.

33



9. The system of any one of claims 1 to 8, wherein the
first, second and third packers are external casing packers
set hydraulically by inflation means.

10. The system of any one of claims 1 to 9, wherein each
of the first and second openable flow control devices has
an outside diameter smaller than an inside diameter of a
respective one of the first and second conduits and is
installed within a respective one of the first and second
production liner assemblies by seating a respective one of
the first and second openable flow control devices into a
respective one of the first and second sealing profile
devices.

11. The system of claim 10, wherein each of the first and
second openable flow control devices comprises a conduit
section having an internal axial flow passage and at least
one traverse flow passage connecting the internal flow
passage to an exterior of the conduit section, means for
selectively closing the transverse flow passage, and a
filter preventing formation particles larger than a
predetermined size from entering the internal axial flow
passage via the transverse flow passage.

12. The system of any one of claims 1 to 11, wherein at
least one of the first and second precut liner windows is
aligned with a respective one of the first and second
openings by using an imaging device to locate the
respective one of the first and second openings at a
junction of a respective one of the first and second
deviated wellbores and the primary wellbore by surveying a
wall of the primary wellbore.

34



13. The system of claim 12, wherein the imaging device is
a wireline conveyed downhole video camera tool comprised
of:
an imaging lens focused and projected in a direction;
a focused light source directed proximate to the imaging
lens direction; and
an orientation guide key indexed relative to the imaging
lens direction.

14. The system of claim 13, wherein the wall of the
primary wellbore is surveyed by engaging the orientation
guide key of the downhole video camera tool into one of the
first and second indexed orientation profile devices to
orient the imaging lens direction toward a respective one
of the first and second precut liner windows at a location
proximate to the respective one of the first and second
precut liner windows, and moving the downhole video camera
tool and a respective one of the first and second
production liner assemblies within the primary wellbore as
the downhole video camera tool provides surface video or
imagery readout to enable proper alignment of the
respective one of the first and second precut liner window
with the respective one of the first and second openings.

15. A method for selectively re-entering first and second
deviated wellbores drilled as extensions of a primary
wellbore, the first and second deviated wellbores
intersecting the primary wellbore at respective first and
second openings, the method comprising the steps of:
running a first production liner assembly into the
primary wellbore, the first production liner assembly
comprising a first conduit having a first seal device,





multiple first packers, a first precut liner window between
the first packers allowing subsequent re-entry into the
first deviated wellbore, a first indexed orientation
profile device facilitating alignment of the first precut
liner window with the first opening and subsequent re-entry
into the first deviated wellbore;
aligning the first precut liner window with the first
opening;
setting the first packers straddling the first opening
and thereby isolating the first deviated wellbore;
running a second production liner assembly into the
primary wellbore, the second production liner assembly
comprising a second conduit having a second packer, a
second precut liner window allowing subsequent re-entry
into the second deviated wellbore, a second indexed
orientation profile device facilitating alignment of the
second precut liner window with the second opening and
subsequent re-entry into the second deviated wellbore; and
a second seal device for engagement with the first seal
device;
aligning the second precut liner window with the second
opening;
setting the second packer, thereby isolating the second
deviated wellbore;
running a diverter means into the primary wellbore and
through the first production liner assembly, the diverter
means being provided with a diverter face, an orientation
guide key, and anchor means;
aligning the diverter means by engagement of the
orientation guide key with the first indexed orientation
profile device so the diverter face is in alignment with
the first precut liner window;

36




anchoring the diverter means in the first production
liner assembly;
directing a first object from the primary wellbore, through
part of the first production liner assembly to the diverter
means, and into the first deviated wellbore; and
removing the diverter means to re-establish large inside
diameter integrity of the first production liner assembly.

16. The method of claim 15, wherein the primary wellbore
may be substantially vertical, substantially horizontal or
otherwise intentionally deviated.

17. The method of claim 15 or 16, wherein the primary
wellbore and the first and second deviated wellbores
extending from the primary wellbore are cased using
respective casing strings.

18. The method of claim 17, wherein annuli formed between
the casing strings and the respective primary wellbore and
first and second deviated wellbores are at least partially
filled with an impermeable cement sheath.

19. The method of claim 18, wherein respective junctions
between each of the first and second deviated wellbores and
the primary wellbore are sealed and generally conformable
or flush with an interior of the primary wellbore casing
string.

20. The method of any one of claims 15 to 19, wherein each
of the first and second indexed orientation profile devices
comprises a first pipe section with an orientation guide
key slot indexed to a respective one of the first and
second precut liner windows, thereby facilitating alignment

37



of each of the first and second precut liner windows with a
respective one of the first and second openings and
subsequent selective re-entry into a respective one of the
first and second deviated wellbores.

21. The method of any one of claims 15 to 20, wherein the
first and second packers are external casing packers set
hydraulically by inflation means.

22. The method of any one of claims 15 to 21, wherein each
of the first and second precut liner window aligning steps
includes using an imaging device to locate the respective
one of the first and second openings at a junction of a
respective one of the first and second deviated wellbores
and the primary wellbore by surveying a wall of the primary
wellbore.

23. The method of claim 22, wherein the imaging device is
a wireline conveyed downhole video camera tool comprised
of:
an imaging lens focused and projected in a direction;
a focused light source directed proximate to the imaging
lens direction; and
an orientation guide key indexed relative to the imaging
lens direction.

24. The method of claim 23, wherein the wall of the
primary wellbore is surveyed by engaging the orientation
guide key of the downhole video camera tool into one of the
first and second indexed orientation profile devices to
orient the imaging lens direction toward a respective one
of the first and second precut liner windows at a location
proximate to the respective one of the first and second

'38




precut liner windows, and moving the downhole video camera
tool and a respective one of the first and second
production liner assemblies within the primary wellbore as
the downhole video camera tool provides surface video or
imagery readout to enable proper alignment of the
respective one of the first and second precut liner window
with the respective one of the first and second openings.

25. A method for selectively isolating multiple
completions in a primary wellbore penetrating a hydrocarbon
bearing formation, the primary wellbore having (a) first
and second deviated wellbores drilled into the formation as
extensions of the primary wellbore, wherein an inside
diameter of the primary wellbore at each of first and
second openings between the primary wellbore and the
respective first and second deviated wellbores is
approximately equal to an inside diameter of the primary
wellbore above or below a respective one of the first and
second openings, and (b) means to establish direct
communication between the primary wellbore and the
formation, the method comprising the steps of:
running a first production liner assembly into the
primary wellbore, the first production liner assembly
comprising a first conduit having a first seal device,
multiple first packers, a first precut liner window between
the first packers allowing re-entry into the first deviated
wellbore, a first indexed orientation profile device
facilitating alignment of the first precut liner window
with the first opening and subsequent re-entry into the
first deviated wellbore, first sealing profile devices
straddling the first precut liner window for subsequent
installation of a retrievable first openable flow control

39


device, a third packer, and a third openable flow control
device:
aligning the first precut liner window with the first
opening:
setting the first packers and the third packer, the first
packers straddling the first opening and isolating the
first deviated wellbore so that the first openable flow
control device can selectively allow and prevent flow
between the first deviated wellbore and the first conduit,
and the third packer isolating the direct communication
means so that the third openable flow control device can
selectively, allow and prevent flow between the direct
communication means and the first conduit;
running a second production liner assembly into the
primary wellbore, the second production liner assembly
comprising a second conduit having a second packer, a
second precut liner window allowing subsequent re-entry
into the second deviated wellbore, a second indexed
orientation profile device facilitating alignment of the
second precut liner window with the second opening and
subsequent re-entry into the second deviated wellbore,
second sealing profile devices straddling the second precut
liner window for subsequent installation of a retrievable
second openable flow control device, and a second seal
device for engagement with the first seal device;
aligning the second precut liner window with the second
opening:
setting the second packer, thereby isolating the second
deviated wellbore so that the second openable flow control
device can selectively allow and prevent flow between the
second deviated wellbore and the second conduit;
installing and/or removing at least one of the first and
second openable flow control devices; and




using a flow control operating device to selectively open
and close at least one of the first and second openable
flow control devices to facilitate selective stimulation,
testing,.production, injection, temporary shut-in, or
permanent completion abandonment.

26. The method of claim 25, wherein the primary wellbore
may be substantially vertical, substantially horizontal or
otherwise intentionally deviated.

27. The method of claim 25 or 26, wherein the primary
wellbore and the first and second deviated wellbores
extending from the primary wellbore are cased using
respective casing strings.

28. The method of claim 27, wherein annuli formed between
the casing strings and the respective primary wellbore and
first and second deviated wellbores are at least partially
filled with an impermeable cement sheath.

29. The method of claim 28, wherein respective junctions
between each of the first and second deviated wellbores and
the primary wellbore are sealed and generally conformable
or flush with an interior of the primary wellbore casing
string.

30. The method of claim 28, wherein the direct
communication means between the primary wellbore and the
formation comprises perforations in the primary wellbore
casing string.

31. The method of any one of claims 25 to 30, wherein each
of the first and second indexed orientation profile devices

41



comprises a first pipe section with an orientation guide
key slot indexed to a respective one of the first and
second precut liner windows, thereby facilitating alignment
of each of the first and second precut liner windows with a
respective one of the first and second openings and
subsequent selective re-entry into a respective one of the
first and second deviated wellbores.

32. The method of claim 31, wherein each of the first and
second indexed orientation profile devices further
comprises a second pipe section with a polished sealing
profile providing sealing means for subsequent installation
of a respective one of the first and second openable flow
control devices to selectively allow and prevent flow
between the respective one of the first and second deviated
wellbores and a respective one of the first and second
conduits.

33. The method of any one of claims 25 to 32, wherein the
first, second and third packers are external casing packers
set hydraulically by inflation means.

34. The method of any one of claims 25 to 33, wherein each
of the first and second openable flow control devices has
an outside diameter smaller than an inside diameter of a
respective one of the first and second conduits and is
installed within a respective one of the first and second
production liner assemblies by seating a respective one of
the first and second openable flow control devices into a
respective one of the first and second sealing profile
devices.

42



35. The method of claim 34, wherein each of the first and
second openable flow control devices comprises a conduit
section having an internal axial flow passage and at least
one traverse flow passage connecting the internal flow
passage to an exterior of the conduit section, means for
selectively closing the transverse flow passage, and a
filter preventing formation particles larger than a
predetermined size from entering the internal axial flow
passage via the transverse flow passage.

36. The method of any one of claims 25 to 35, wherein each
of the first and second precut liner window aligning steps
includes using an imaging device to locate the respective
one of the first and second openings at a junction of a
respective one of the first and second deviated wellbores
and the primary wellbore by surveying a wall of the primary
wellbore.

37. The method of claim 36, wherein wherein the imaging
device is a wireline conveyed downhole video camera tool
comprised of:
an imaging lens focused and projected in a direction;
a focused light source directed proximate to the imaging
lens direction; and
an orientation. guide key indexed relative to the imaging
lens direction.

38. The method of claim 37, wherein the wall of the
primary wellbore is surveyed by engaging the orientation
guide key of the downhole video camera tool into one of the
first and second indexed orientation profile devices to
orient the imaging lens direction toward a respective one
of the first and second precut liner windows at a location

43



proximate to the respective one of the first and second
precut liner windows, and moving the downhole video camera
tool and a respective one of the first and second
production liner assemblies within the primary wellbore as
the downhole video camera tool provides surface video or
imagery readout to enable proper alignment of the
respective one of the first and second precut liner window
with the respective one of the first and second openings.

44

Description

CA 02233086 1998-03-26
WO 97/12112 PCT/US96/15347
METHOD FOR ISOLATING MULTI-LATERAL WELL COMPLETIONS WHILE
MAINTAINING SELECTIVE DRAINHOLE RE-ENTRY ACCESS
FIELD OF THE INVENTION
'' The present invention relates to novel methods and devices for
simultaneously completing hydrocarbon productive zones) from a
cased vertical well containing one or more horizontal drainholes
extending from the vertical well together with completions made
directly from the vertical well (ie: perforated casing). The
resulting well configuration provides pressure isolation and
selective flow control between each drainhole and/or vertical well
completion and provides convenient access to the drainhole(s) for
re-entry at any time during the productive life cycle of the
vertical well. In situations where completion isolation and
selective flow control are not necessary, new and improved methods
and devices are presented to facilitate selective re-entry into any
drainhole using routine workover means and without any reduction
in the inside diameter of the vertical well casing subsequent to
re-entry operations. Other important features of this novel
multi-lateral completion system are described herein.
BACKGROUND OF THE INVENTION
It is not uncommon for a vertical well to encounter a
plurality of hydrocarbon bearing formations with varying degrees
of potential productivity. Due to differences in reservoir
pressure, fluid content, and petrophysical properties, downhole
commingling of production from multiple zones if often not only
detrimental to the ultimate recovery of the well, but prohibited
by government regulatory agencies.
A number of different completion methods have been used to
independently produce multiple zones encountered in a single well.
In the simplest of these completion techniques, the lowermost
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CA 02233086 1998-03-26
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productive zone is perforated and produced until the hydrocarbon
production rate becomes economically marginal. Then, the zone is
abandoned and the well is recompleted to the next shallower zone.
Upon depletion of this zone, the well is again recompleted to the
next shallower zone. Upon depletion of this zone, the well is
again recompleted and produced until all potential zones have been
produced. Upon depletion of the shallowest productive zone, the
well is plugged and abandoned. A graph showing hydrocarbon
production rate versus time for such a well would typically exhibit
a "roller coaster" profile with relatively high production rates
occurring immediately after each new zone completion.
In an effort to prolong a well's flush production period and
smooth out this "roller coaster" production profile, more complex
completion methods are employed. One such technique involves using
multiple strings of production tubing with specially spaced
multiple completion packers for isolating each completed zone. An
important drawback to this type completion design is the size of
independent production strings make it difficult to artificially
lift the produced fluids from each zone should the well cease to
flow naturally.
Multi-zone techniques facilitating the independent completion
of one or more horizontal drainholes extending from a vertical well
together with one or more "conventional" vertical well completions
have become important to the oil industry in recent years. Such
wells are commonly referred to as multi-lateral wells. Horizontal
drainhole completions typically exhibit substantially better
productivity than vertical well completions, but due to the
increased well cost coupled with the requirement of excellent
subsurface geologic definition, are not appropriate in all cases.
Horizontally drilled wells, or wells which have nearly horizontal
sections, are now used routinely to exploit productive formations
in a number of development situations. Horizontal drainholes are
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CA 02233086 1998-03-26
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often used to efficiently exploit vertically fractured formations,
thin reservoirs having matrix porosity, formations prone to coning
water, steam, or gas due to "radial flow" characteristics inherent
in vertical well completions, and formations undergoing enhanced
oil recovery operations. Drilling horizontal wells also has
application in offshore development where fewer and smaller
platforms are required due to the increased productivity of
horizontal drainholes compared to vertical completions and the
possibility of drilling multiple drainholes from one vertical well
platform slot. Drilling multiple drainholes from a new or existing
cased vertical well with completions in the same formation or in
different formations enables both the productivity and
return-on-investment in equipment infrastructure of the vertical
well to be maximized.
The majority of multi-lateral wells drilled today are rather
simply completed in the sense that the horizontal drainholes
commingle well fluids in a vertical part of the well. The
commingled fluids either flow or are artificially lifted from the
vertical part of the well by equipment located substantially above
the uppermost drainhole and productive formation(s). With this
wellbore configuration, zone isolation, flow control, pump
efficiency, and bottomhole pressure optimization is compromised.
In some cases, downhole pumps are actually placed in the horizontal
sections of the wells which partially remedies some of these
problems, but typically leads to increased mechanical problems.
When zone and/or drainhole isolation and flow control means are not
incorporated in the well design, the entire well's production may
be jeopardized if a production problem such as early water
breakthrough occurs in one of the vertical well or drainhole
completions.
In recent years, several more sophisticated multi-lateral
drilling and completion techniques have been developed in an
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CA 02233086 1998-03-26
WO 97/12112 PCT/LTS96/15347
attempt to solve a host of difficult problems. It is well
documented that the ideal multi-lateral system would overcome the
shortcomings of the prior art and provide the following benefits:
(1) infrastructure related to a cased vertical well should be used
to efficiently deplete all economically productive zones with a .,
series of vertical well completions and horizontal drainhole
completions, (2) existing vertical wellbores with large diameter
production casing should be re-enterable as the parent well for
subsequent multi-lateral drilling and completion, (3) relatively
simple design execution should be both cost effective and
mechanically reliable, (4) should be applicable to short radius
(ie: 60' turning radius) as well as medium radius (ie: 300' turning
radius) drainholes used in high temperature enhanced oil recovery
operations, (5) should not involve milling of ~~hard-to-drill" steel
tubular goods to exit the cased vertical well for drainhole
extension, (6) curve sections should be isolated from the
horizontal target sections in drainholes to avoid hole collapse
problems and/or premature gas or steam breakthrough, (7) light
weight and flexible zone isolation and/or sand control liners
should be installed in the horizontal target intervals of
drainholes as well conditions dictate, (8) the size of the liner
within each drainhole should be approximately equal to the final
size of the production casing or liner string within the parent
vertical wellbore, (9) the junction between the cased vertical well
and each cased lateral well should be effectively sealed, (10) each
vertical and/or horizontal well completion should be isolated
within the vertical wellbore, (11) openable flow control devices
should be employed to enable each completion to be selectively
tested, stimulated, produced, or shut-in, (12) each drainhole
should be accessible for re-entry to facilitate additional
completion work, drilling deeper, drainhole interval testing with
zone isolation, sand control, cleanout, stimulation, and/or other
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CA 02233086 1998-03-26
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remedial work, and (13) the inside diameter of the final production
casing or liner string in the vertical wellbore should be large
enough to enable a downhole pump may be placed in a sump located
below all productive horizons to optimize pressure drawdown during
production operations and increase artificial lift efficiency. To
V
date, a prior art multi-lateral drilling and completion system has
not been developed that delivers all of the benefits described
above.
U.S. patents of general interest in the field of horizontal
well drilling and completion include:
2,397,070; 2,452,920; 2,858,107; 3,330,349;
3,887,021; 3,908,759; 4,396,075; 4,402,551;
4,415,205; 4,444,276; 4,573,541; 4,714;117;
4,742,871; 4,800,966; 4,807,704; 4,869,323;
4,880,059; 4,915,172; 4,928,763; 4,949,788;
5,040,601; 5,113,938; 5,289,876; 5,301,760;
5,311,936; 5,318,121; 5,318,122; 5,322,127;
5,325,924; 5,330,007; 5,337,808; 5,353,876;
5,375,661; 5,388,648; 5,398,754; 5,411,082;
5,423,387; and 5,427,177.
Of particular interest to this application is U.S. Patent No.
5,301,760. According to this patent, a vertical well is drilled
through one or more horizontal well target formations. The
borehole may be enlarged adjacent to each proposed "kick-off point"
prior to running and cementing production casing. An orientable
retrievable whipstock/packer assembly (WPA) is used to initiate
milling a window through a "more drillable" joint in the vertical
w well casing string in the direction of the proposed horizontal well
target. A horizontal drainhole is then drilled as an extension of
the vertical well. The drainhole is then completed with a cemented
liner extending at least through the curve portion of the drainhole
and into the vertical well. The protruding portion of the liner
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CA 02233086 1998-03-26
WO 97/12112 PCT/US96/15347
and cement in the vertical well is then removed using a full gauge
(fitted to the vertical well casing inside diameter) burning
shoe/fishing tool assembly. The resulting drainhole entrance point
has an elliptical configuration with a sharp apex at the top of the
liner and at the bottom of the liner at the junction of the lateral
well with the vertical well due to the high angle (almost vertical)
ofthe drainhole liner as it meets the vertical well. Furthermore,
the "smooth" junction of the vertical well casing and the drainhole
liner is effectively sealed by a highly resilient, impermeable
cement sheath completely filling the annulus of the drainhole and
the liner at the junction. Subsequent to "coring" through and
removing the protruding portion of drainhole liner and cement in
the vertical well, the WPA is removed from the well, thus
re-establishing the full gauge integrity of the vertical well to
enable large diameter downhole tools to be lowered below the
drainhole entrance point. Additional drainholes may be drilled as
extensions from the vertical parent well in a similar fashion.
Another U.S. patent of particular interest to this application
is 5,289,876. According to this patent, one or more drainholes are
drilled and completed using a method such as that described in U.S.
Patent No. 5,301,760 in junction with a novel method for preventing
drainhole collapse, isolating lateral intervals drilled
out-of-the-target zone, and providing sand control for laterals
drilled through unconsolidated sands or incompetent formations.
A light weight, flexible, "drillable" liner assembly is used to
facilitate gravel packing with high temperature resistant curable
resin coated sand. Subsequent to pumping the gravel pack, the
"drillable" drainhole liner together with a veneer of cured resin --
coated sand adjacent to the target horizon is removed using a coil
tubing conveyed mud motor and pilot mill. A liner with an inside
diameter slightly largerthan the outside diameter of the pilot mill
is placed adjacent to the lateral intervals drilled
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out-of-the-target zone to isolate these intervals. The method
disclosed in this patent is applicable to short and medium radius
horizontal wells used in high temperature enhanced oil recovery
operations.
Multi-lateral wells drilled and completed using the method
disclosed in U.S. Patent No. 5,289,876 in conjunction with the
techniques described in U.S. Patent No. 5,301,760 provide nine of
the thirteen beneficial attributes previously described for the
ideal multi-lateral system, namely: (1) , (2) , (3) , (4) , (5) , (6) ,
(7), (9), and (13). A need presently exists for a reliable and
cost effective drilling and completion system for multi-lateral
wells that addresses all thirteen previously described benefits.
Accordingly, it is an object of the present invention to enhance
the utility of the methods disclosed in U.S. Patent Nos. 5,289,876
and 5,301,760 by allowing: (a) each vertical and/or horizontal
well completion to be isolated within the vertical wellbore, (b)
openable flow control devices to be employed to enable each
completion to be selectively tested, stimulated, produced, or
shut-a.n, (c) each drainhole to be selectively accessible for
re-entry to facilitate additional completion work, drilling deeper,
drainhole interval testing with zone isolation, sand control,
cleanout, stimulation, and other remedial work either before or
after completion isolation and flow control means are installed,
and (d) the size of the liner within each drainhole to be
approximately equal to the final size of the production casing or
liner string within the parent vertical wellbore.
- SUMMARY OF THE INVENTION
To substantially alleviate the deficiencies of the prior art
and to provide the benefits discussed hereinabove, the present
invention is incorporated and broadly described herein in two
embodiments related to multi-lateral wells. Prior to application
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of the inventive techniques and apparatus, the following drilling
and completion steps have been performed in accordance with the
methods disclosed in U.S. Patent No. 5,301,760: (1) configuring a
new or pre-existing, substantially vertical, cased well
(hereinafter sometimes referred to as primary well) penetrating one
or multiple hydrocarbon bearing formations with one or more lateral
wells (ie: upper and lower drainholes) drilled as extensions of the
primary well with each lateral being equipped with a cemented liner
through at least the curve portion of the lateral and into the
cased primary well, (2) re-establishing the full bore integrity of
the cased primary well after running and cementing the drainhole
liners) such that the elliptical shaped junction between each
drainhole and the primary well is sealed, and (3) perforating the
casing in the primary well at a drainhole target horizon and/or
adjacent to other potentially productive zones (ie: lowermost
zone ) .
The first embodiment relates to providing re-entry means into
a drainhole drilled and completed as an extension of a primary well
before any completion isolation or flow control means are installed
within the primary well. The inventive method and apparatus
comprise the steps of: (1) running a work string conveyed
retrievable whipstock/packer assembly (WPA) into the primary well
to a depth corresponding with the approximate location of the
drainhole to be re-entered and comprising an external casing packer
(ECP) located at its lower end, a drillable locator ring above the
ECP, a lower whipstock member with a built-in openable window gate
device, an upper whipstock member with a diverter face, and a bore
passing entirely through the WPA, (2) aligning the diverter face '
to the approximate azimuth direction of the longest center-line
axis of the drainhole opening using gyroscopic orientation means,
(3) using wireline conveyed logging means to open the WPA's window
gate.device and image the inner wall of the primary well, (4)
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moving the WPA and logging means simultaneously to locate the exact
location of the lowermost apex of the elliptical shaped drainhole
opening at the junction of the drainhole and primary well, (5)
anchoring the WPA in the primary well casing and retrieving the
setting tool, (6) installing a self-orienting "drillable" shaped
plug in the bore of the WPA adjacent to the diverter face, (7)
conducting said re-entry operation to facilitate additional
completion work, drilling deeper, drainhole interval testing with
zone isolation, sand control, cleanout, stimulation, and/or other
remedial work, and (8) removing the WPA to re-establish the full
bore integrity of the cased. primary well.
The second embodiment is an inventive technique comprising the
steps of: (1) running a lower production liner assembly (PLA) into
the primary well using a work string and liner setting tool
consisting of: (a) an external casing packer (ECP) located below
a perforated casing completion, (b) an openable flow control valve
(ie: port collar) with a sand control sleeve encasement (FCD)
located adjacent to said perforations, (c) an ECP located above
said perforations, but below a lower drainhole entrance point, (d)
a precut window located adjacent to said lower drainhole entrance
point, (e) an internal seal bore/latch down profile collar located
slightly below said precut liner window with a built-in liner
orientation guide slot indexed 180° opposed to the longest
center-line axis of said precut liner window, (f) an internal seal
bore profile collar located slightly above said liner window, (g)
an ECP located above both said liner window and said profile
collar, and (h) a flared liner seal bore receptacle connected to
the work string conveyed liner setting tool with left-hand threads,
(2) aligning the bottom of the precut liner window in said lower
PLA with the exact bottom of the junction of the primary wellbore
and~the lower cemented drainhole liner in both depth and azimuth
direction, (3) inflating the ECPs to permanently anchor the lower
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PLA within the cased primary well such that the precut liner window
is in alignment with the lower drainhole entrance point to
facilitate subsequent re-entry by engaging a preconfigured guide
key extending from a WPA into the orientation guide slot built into
a internal seal bore/latch down profile collar located slightly
below said precut liner window, (4) running an upper PLA into the
primary well using a work string and liner setting tool consisting
of: (a) seal assembly mandrel to sting into the seal bore at the
top of the lower PLA to provide both vertical and rotational travel
for said upper PLA during alignment step (5), (b) a precut window
located adjacent to said upper drainhole entrance point, (c) an
internal seal bore/latch down profile collar located slightly below
said precut liner window with a built-in liner orientation guide
slot indexed 180° opposed to the longest center-line axis of said
precut liner window, (d) an internal seal bore profile collar
located slightly above said liner window, (e) an ECP located above
both said liner window and said profile collar, and (f) a flared
liner seal bore receptacle connected to the work string conveyed
liner setting tool with left-hand threads, (5) aligning the bottom
of the precut liner window in said upper PLA with the exact bottom
of the junction of the primary wellbore and the upper cemented
drainhole liner in both depth and azimuth direction, (6) inflating
the ECP to permanently anchor the upper PLA within the cased
primary well such that the precut liner window is in alignment with
the upper drainhole entrance point to facilitate subsequent
re-entry by engaging a preconfigured guide key extending from a WPA
into the orientation guide slot built into the internal seal
bore/latch down profile collar, (7) installing retrievable,
openable, FCD sleeves adjacent to each precut liner window using
the seal bore/latch down profile collars located below each precut '
window liner to seal and latch the bottom of the FCDs and the seal
bore profile collars located above each precut window to seal the
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top of the FCDs, (8) opening and closing the FCDs to facilitate
selective stimulation, testing, production, injection, temporary
shut-in, or permanent abandonment of each completion, (9) removing
a retrievable FDC sleeve located adjacent to a drainhole desired
to be re-entered, (10) aligning a retrievable WPA to the proper
depth and azimuth direction to facilitate re-entry into said
drainhole by engaging an orientation guide key apparatus built into
a lower whipstock member at an azimuth 180° opposed to the
whipstock face into the indexed orientation guide slot of the
internal seal bore/latch down profile collar of the PLA, (11)
anchoring said WPA in the primary well production liner and
retrieving the setting tool, (12) conducting said re-entry
operation to facilitate additional completion work, drilling
deeper, drainhole interval testing with zone isolation, sand
control, cleanout, stimulation, and/or other remedial work, (13)
removing said retrievable WPA and re-installing said FCD sleeve,
(14) operating FCDs to optimize production during the life cycle
of the vertical parent well, and (15) installing an artificial lift
system with a downhole pump located in the large diameter cased
sump located below all producing horizons and/or drainholes to
maximize pump efficiency and to enhance gravity drainage, thus
improving the well's ultimate hydrocarbon recovery.
The aligning steps (i.e., steps (2) and (5)) of the inventive
technique described in the second embodiment preferably involves
a novel downhole video camera tool conveyed on electric wireline
that has a focused projection indexed to the base of the precut
liner window and is directed perpendicular to the longest
center-line axis of said precut liner window to image the inner
wall of the primary well casing as the video camera tool and PLA
is slowly moved within the primary well casing to align said precut
liner window with the opening made by the junction of the drainhole
liner with the primary well casing.
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., CA 02233086 2005-04-27
Although the present invention is particularly suited to
completions involving horizontal drainholes drilled as extensions
from substantially vertical primary wells, those skilled in the art
will recognize that the invention also has application in
completion situations involving one or more wellbores which extend
in directions other than horizontal and which are drilled as
extensions from a primary well which is substantially horizontal
or otherwise intentionally deviated, rather than vertical.
These and other objects, features, and advantages of this
invention will become more fully apparent to those skilled in the
art as this description proceeds, reference being made to the
accompanying drawings and appended claims.
BRT_E~ DESCRIPTION OF THE DRAWINGS
The drawings incorporated herein serve to illustrate the
principals and embodiments o~ this invention. Like elements
» illustrated in multiple figures are numbered consistently in each
figure. Now referring to the drawings:
FIG. 1 is a cross-sectional elevational view of a
multi-lateral well in an intermediate stage of completion which is
suitably equipped and configured for subsequent implementation of
this invention;
FIG. 2 is a cross-sectional side view of FIG. 1, taken
substantially along line 2 - 2 thereof and taken prior to
implementation of this invention;
FIGS. 3 - 8 are cross-sectional elevational views depicting
subsequent stages of the first embodiment relating to re-entering
a drainhole extending from a multi-lateral well using a novel
whipstock/pack~r assembly and routine workover means; and
FIGS. 9 - 15 are. sequential cross-sectional elevational views
depicting the method of the second embodiment for completing a
multi-lateral well using a novel production liner assembly to
provide for completion isolation, selective flow control, and
convenient drainhole re-entry access.
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DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
Referring to FIG. 1, a multi-lateral well 10, at a stage of
completion, prior to the application of the present invention,
includes a substantially vertical borehole 14 drilled into the
earth which penetrates a subterranean hydrocarbon bearing formation
12. Typically, the borehole 14 is logged or otherwise surveyed to
provide reliable information about the top and bottom, porosity,
fluid content, and other petrophysical properties of the formations
encountered. A multi-lateral well plan is designed incorporating
two horizontal drainhole completions 22, 24, together with one
vertical well completion 26. Vertical wellbore 14 is~enlarged to
a larger borehole size 16 using an underreamer or other suitable
drilling tool adjacent to each horizontal drainhole "kick-off
point". A relatively large diameter (ie: 9-5/8" O.D.) production
casing string 18 is cemented in the borehole 14, 16 by an
impermeable cement sheath 38 to prevent communication between
hydrocarbon bearing formation 12 and other permeable formations
penetrated by borehole 14, 16 in the annulus between the borehole
14, 16 and the casing string 18. Casing string 18 may include
joints of casing 20 made of a more drillable material than steel
(ie: carbon, glass, and epoxy composite material) positioned a.n
the vertical portion of well 10 adjacent to each drainhole kick-off
point to facilitate subsequent window cutting operations. Fibrous
material or other cement additives may be included in the cement
38 to improve resiliency properties of the cement and make the
cement less brittle.
As explained in applicant's U.S. Patent No. 5,301,760 issued
April 12, 1994, entitled COMPLETING HORIZONTAL DRAIN HOLES FROM A
VERTICAL WELL, a lower lateral borehole 32 has been drilled into
the formation 12 using a retrievable whipstock/packer assembly (not
shown) oriented and anchored within production casing 18 to
initiate cutting an elliptically shaped window in the production
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casing with an apex 52 at the top and an apex 56 at the bottom.
Subsequent to drilling at least the curve portion of the lower
drainhole completion 24, a production liner string 36 is run at
least partially in borehole 32 and cemented into place to provide
a cement sheath 42 isolating the horizontal target section within
formation 12 penetrated by borehole 32 from any overlying water
bearing formations, incompetent formations, or non-target sections
within formation 12 that may be prone to gas or steam coning. The
upper end of the lower lateral liner string 36 and some cement
initially extends into the vertical portion of well 10. This
protruding portion of liner string 36 and cement within the
vertical portion of well 10 is removed using a full gauge burning
shoe/wash pipe/fishing tool assembly (not shown) sized only
slightly less than the inside diameter of production casing string
18, to leave a relatively smooth entry opening at the junction of
the lower lateral completion 24 and the vertical portion of well
10. The resulting lower drainhole opening or liner window 46 has
an elliptical shape with an apex 60 at the top and an apex 64 at
the bottom of the window 46 due to the high angle of the lower
lateral liner as it meets with the vertical portion of well 10
(schematic of FIG. 1 is not drawn to scale or in realistic
proportion). The lower lateral liner string 36 located adjacent
to window 46 preferably includes one or more joints of liner made
of a more drillable material than steel (ie: carbon, glass, and
epoxy composite material) to facilitate the removal of said
protruding portion of liner extending into the vertical portion of
well 10.
Using a drilling and completion method similar to that ,
described for the lower drainhole completion 24, an upper drainhole
completion 22 may be drilled and completed. The upper drainhole
completion 22 is comprised of a lateral borehole 30, a lateral
liner pipe string 34 located within borehole 30, a cement sheath
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40 at least partially filling the annulus between borehole 30 and
liner 34, an elliptically shaped drainhole opening or liner window
44 with an upper apex 58 and a lower apex 62, and an elliptically
shaped production casing window with an upper apex 50 and a lower
apex 54.
In addition to configuring upper lateral completion 22 and
lower lateral completion 24 pursuant to the methods described
hereinabove, a vertical well completion 26 is configured with
perforation flow passages 28 through production casing string 18
and into hydrocarbon bearing formation 12, thus establishing
communication between formation 12 and the interior of production
casing 18. In certain situations involving unconsolidated
formations, it may be necessary to hydraulically jet wash the
perforation flow passages 28 to create a void space adjacent to
each perforation and employ a 'behind the pipe" sand control
procedure (ie: curable resin coated gravel pack or plastic
formation sand consolidation treatment) prior to finishing the
completion of the multi-lateral well 10 using the present
invention. It will be evident that the lateral completions and the
vertical well completion may target the same hydrocarbon bearing
formation 12 or different hydrocarbon bearing formations. In
addition, the invention has application in situations involving
only one drainhole completion as well as multiple lateral
completions extending from the vertical portion of well 10. It
will also be evident that more than one vertical completion may be
configured from the vertical portion of well 10.
Turning now to FIG. 2, a cross-sectional side view of FIG. 1,
taken substantially along line 2 - 2 thereof and taken prior to
implementation of this invention, shows the elliptical
' 30 configuration of the upper liner window 44 at the junction between
the upper drainhole completion 22 and the vertical portion of well
10. The annulus between the liner window 44 defined by its upper
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apex 58 and its lower apex 62 and the elliptical shaped production
casing window defined by its upper apex 50 and lower apex 54 has
been effectively sealed with an impermeable cement sheath 40. To
improve the effectiveness of this hydraulic seal, fibrous material
or other cement additives may be included in the cement 40 to _
improve resiliency properties of the cement and make the cement
less brittle. In addition, lateral liner 34 is preferably
centralized within borehole 30 prior to placement of cement sheath
40 to ensure cement sheath 40 completely surrounds liner pipe
string 34 adjacent to window 44. In addition to placing a
plurality of centralizers (not shown) on liner pipe string 34 to
support liner 34 off the bottom of the curved borehole 30, a
plurality of reinforcing members comprised of a suitable material
(ie: lengths of the same type wire as used in wire casing
scratchers) may be attached to liner 34 near window 44 to further
facilitate the competency of the cement sheath 40 to seal the
junction between the upper lateral completion 22 and the vertical
portion of well 10.
Referring to FIG. 3, a disclosure of the first embodiment
begins wherein a whipstock/packer assembly 166 is run into the
vertical portion of well 10 using work string 68 and setting tool
assembly 168. Whipstock/packer assembly 166 comprises an external
casing packer 170 at its lower end for anchoring the
whipstock/packer assembly 166 after proper alignment, a spacer sub
with a "drillable" locator ring 172, a lower whipstock member 174,
with a mechanically activated sliding window gate device 176, and
a wedge shaped upper whipstock member 178 which is connected to
lower whipstock member 174 by short hinge pins 180 to enable upper
member 178 to pivot against lower member 174 in a direction
opposite lower lateral completion 24 after packer 170 has been set
and setting mandrel 182 has been removed. Whipstock/packer
assembly 166 has a bore 184 extending from the whipstock face 186
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to the end of the assembly at packer 170. Bore 184 has a smaller
inside diameter seal profile 188 at the end of packer 170 to seat
a weighted packer setting ball (not shown) after it has traveled
through work string 68, setting mandrel 182, and whipstock/packer
assembly 166. Subsequent to aligning whipstock/packer assembly 166
to facilitate re-entry into lateral completion 24, a packer setting
ball (not shown) is dropped and seated in seal bore profile 188,
then pressure is applied to hydraulically inflate anchoring packer
170 against the inside wall of casing string 18. Setting tool
mandrel 182 extends through bore 184 in upper whipstock member 178
and into the top of lower member 174 and is connected to lower
whipstock member 174 with left hand threads 190 to facilitate a
clockwise rotational release after packer 170 is set. Upper
whipstock member 178 has a orientation guide slot 192 extending
from bore 184 into the inside wall of member 178 to facilitate
setting a ~~drillable" shaped whipstock plug (not shown) to at least
partially cover the opening in whipstock face 186 at the uppermost
end of bore 184 after setting tool mandrel 182 is removed from
whipstock/packer assembly 166. Subsequent to running
whipstock/packer assembly 166 into the vertical part of well 10 to
a depth sufficient to position whipstock face 186 approximately
adjacent to lateral liner window 46, a mechanically activated
orientation guide key 196 built into a gyroscopic orientation
device 194 conveyed on electric line cable 98 is engaged in an
orientation key slot 198 built into setting tool assembly 168. Key
slot 198 is indexed to whipstock face 186 prior to running
whipstock/packer assembly 166 into well 10. Whipstock face 186 is
then oriented in the approximate azimuth direction of the longest
center-line axis of lateral liner window 46 by repetitive surveying
- 30 with gyroscopic device 194 and incremental rotational movement of
work string 68. Gyroscopic orientation device 194 is removed from
well 10 after whipstock face 186 is positioned in approximate
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alignment with liner window 46.
As shown in FIG. 4, gyroscopic orientation device 194 has been
removed from well 10. An electric line 98 conveyed downhole video
camera tool 100 with a mechanically activated orientation guide key
104 positioned at its lower end is run down through the work string _
68, setting tool assembly 168, upper whipstock member 178, and into
the top of lower whipstock member 174. Orientation guide key 104
is engaged into an orientation key slot 200 built into whipstock
window gate device 176. Subsequent to latching the camera tool
guide key 104 into sliding gate device 176, the focused projection
camera lens 106 will be directed perpendicular to the longest
center-line axis of lateral liner window 46 and in the same
direction as the azimuth orientation of whipstock face 186. With
camera tool 100 latched into gate device 176, gate device 176 is
free to open with downward movement of the camera tool 100 and
electric line 98. When gate device 176 is in maximum open
position, whipstock window 202 is fully exposed and focused camera
lens 106 is positioned directly adjacent to whipstock window 202
to enable camera tool 100 to image the inner wall of production
casing string 18 near the lower lateral window 46. The video
camera tool 100 with a focused light source 105 and the
whipstock/packer assembly 166 is slowly moved together within the
production casing string 18 by movement of work string 68 to locate
the exact position of the lower apex 64 of the elliptically shaped
lower lateral window 46. Camera tool 100 transmits real time video
images of the downhole environment to a monitor at the surface (not
shown) via electric line cable 98. Subsequent to surveying the
wellbore environment around lateral window 46, the camera "target
cross hairs" are aligned with lower apex 64, thus positioning
whipstock face 186 in the exact location in both depth and azimuth
direction to facilitate subsequent re-entry into lower drainhole
completion 24. Whipstock window 202 is then sealed by closing
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sliding window gate device 176 with upward movement of camera tool
100 via electric line 98. Camera tool 100 is released from gate
device 176 by shearing camera tool guide key 104 with further
upward strain of electric line 98.
In FIG. 5, downhole video camera tool 100 has been removed
from well 10 without moving work string 68 or whipstock/packer
assembly 166. A weighted packer setting ball 150 is then dropped
in work string 68 and is seated in seal bore profile 188. Pressure
is applied from the surface through work string 68 and
whipstock/packer assembly 166 against ball 150 to hydraulically
inflate packer 170, thus anchoring whipstock/packer assembly 166
against casing string 18 in proper configuration to subsequent
facilitate re-entry operations into lateral completion 24.
Turning now to FIG. 6, work string 68 and setting tool
assembly 168 are rotated clockwise to release the diverter setting
mandrel 182 (not shown) from whipstock/packer assembly 166 at
left-hand threads 190. As the setting mandrel 182 is removed from
bore 184, upper whipstock member 178 pivots against lower whipstock
member 174 until top of upper member 178 rests on the inside wall
of production casing string 18. The work string 68 and setting
tool assembly 168 (not shown) are removed from well 10 to enable
re-entry tools to be run through the vertical portion of well 10
and into lateral completion 24.
Referring to FIG. 7, a wireline conveyed "drillable" shaped
whipstock plug 204 with a orientation guide key 206 has been
installed in bore 184 of upper whipstock member 178. Plug 204 is
automatically oriented within bore 184 using spiral path means (not
_ shown) to the orientation guide key slot 192 built into bore 184
of upper whipstock member 178. Plug 204 is a wedge shaped device
with a wedge configuration closely matching the wedge profile of
whipstock face 186. Plug 204 is used to further facilitate the
diversion of re-entry tools (not shown) from the vertical part of
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well 10 into lateral completion 24.
Referring now to FIG. 8, re-entry operations have been
completed and whipstock/packer assembly 166 will be removed from
well 10 in order to re-establish the large inside diameter
integrity of the vertical portion of well 10 so large diameter r
tools may be placed in the cased sump 48 located below all
completion intervals. A burning shoe/wash pipe/internal taper tap
fishing tool assembly 152 is run on work string 68 to the top of
whipstock/packer assembly 166. A mechanical or hydraulically
activated jarring tool 160 is installed between work string 68 and
fishing tool assembly 152 to provide means to impart a jarring
action on whipstock/packer assembly 166 if necessary to facilitate
removal of same. Fishing tool assembly 152 comprises a
conventional full bore burning shoe 154 (ie: Type D Rotary Shoe
which cuts on the bottom and on the inside of the shoe) at the
bottom which is closely fitted to the inside diameter of production
casing string 18, sufficient length of washpipe 156 to enable the
upper portion of whipstock/packer assembly 166 (from the packer 170
to the top of upper whipstock member 178) to be swallowed as
fishing tool assembly 152 is rotated and lowered over
whipstock/packer assembly 166, and an internal taper tap tool 158
connected to the top of fishing tool assembly 152 and sufficiently
spaced within washpipe 156 such that the bottom of taper tap tool
will firmly engage bore 184 inside whipstock/packer assembly 166
as fishing tool assembly 152 rotates down to the top of packer 170.
The locator ring on spacer sub 172 provides an indication to the
driller that the burning shoe is immediately above the packoff
elements of packer 170. After burning shoe 154 drills up a portion
of locator ring on sub 172, taper tap tool 158 will torque up as
it engages whipstock/packer assembly 166 through bore 184. The
hole is then circulated to remove all debris released as a result
of the burning shoe rotation. Shear pins (not shown) which deflate
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packer 170 are then broken by applying tensional force to work
string 68, jars 160, and fishing tool assembly 152, thus releasing
packer 170. Jarring tool 160 may be used to apply additional
jarring force to shear deflation pin in packer 170 and otherwise
free whipstock/packer assembly 166 from production casing string
18. Subsequent to removing whipstock/packer assembly 166, the
configuration of multi-lateral well 10 has been re-established to
a condition similar to the depiction of FIG. 1. The
whipstock/packer assembly 166 may then be redressed or otherwise
reconditioned for use in another re-entry operation.
Referring to FIGS. 9 and 10, a disclosure of the second
embodiment begins wherein a lower production liner assembly 66 is
run into production casing string 18 located within the vertical
portion of well 10 on the bottom of work string 68 connected to a
liner setting tool 70 with left hand threads 72 to facilitate a
clockwise rotational release. Lower liner assembly 66 comprises
a central conduit or production liner 74 with an inside diameter
substantially the same as the inside diameter of drainhole liner
pipe string 34, 36, a hydraulically inflatable external casing
packer 76 located below vertical well completion 26, an openable
flow control device 78 (ie: mechanically or hydraulically
activated port collar) with a sand control/filter sleeve encasement
80, a hydraulically inflatable external casing packer 82 located
above vertical well completion 26, a precut production liner window
84 to be positioned adjacent to the lower lateral window 46 such
that the upper extent 86 of liner window 84 is located above the
upper apex 60 of lateral window 46 and the lower extend 88 of liner
window 84 is located below the lower apex 64 of lateral window 46,
an internal seal bore/latch down collar 90 located slightly below
the base of precut liner window 84 with a liner orientation guide
slot profile indexed exactly 180° opposed to the longest
center-line axis of precut liner window 84, an internal seal bore
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collar 92 located slightly above the top of precut liner window 84,
a hydraulically inflatable external casing packer 94 located above
the lower lateral completion 24 and upper seal bore collar 92, and
a flared liner seal bore receptacle 96 connected to the work string
68 and setting tool 70. Subsequent to running the lower production
liner assembly 66 to the approximate depth soas to position the -
precut liner window 84 adjacent to the lower lateral window 46, an
electric line 98 conveyed downhole video camera tool 100 with a
centralizer 102 and an orientation guide key 104 positioned at its
lower end is run down through the work string 68 and liner assembly
66. Subsequent to latching the camera tool guide key 104 into the
liner orientation guide slot located in collar 90, the focused
projection camera lens 106 will be directed perpendicular to the
longest center-line axis of the precut liner window 84 in the same
direction as the precut liner window 84 to image the inner wall of
the production casing string 18 near the lower lateral window 46.
The video camera tool 100 with a focused light source 105 and the
lower production liner assembly 66 is slowly moved within the
production casing string 18 by movement of work string 68 to locate
the exact position of the lower apex 64 of the elliptically shaped
lower lateral window 46. Camera tool 100 transmits real time video
images of the downhole environment to a monitor at the surface (not
shown) via electric line cable 98. Subsequent to surveying the
wellbore environment around lateral window 46, the camera "target
cross hairs" are
aligned with lower apex 64, thus positioning the precut liner
window 84 in the exact location in both depth and azimuth direction
to facilitate subsequent re-entry into lower drainhole completion ,
24. The downhole video camera tool 100 is then removed from well
10 without moving the work string 68 or lower production liner
assembly 66. The three external casing packers 76, 82, 94 are then
inflated preferably with nitrogen using a coil tubing conveyed
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isolation tool (not shown) to permanently anchor the lower
production liner assembly 66 in proper alignment within well casing
18. Subsequent to setting packers 76, 82, 94, the work string 68
' and setting tool 70 (not shown in FIG. 4) are rotated clockwise to
release the setting tool from the lower liner assembly 66. The
work string and setting tool are then removed from well 10.
Referring now to FIG. 11, an upper production liner assembly
108 is run into the production casing string 18 located within the
vertical portion of well 10 on the bottom of a work string 68
connected to a liner setting tool 70 with left hand threads 72 to
facilitate a clockwise rotational release. Upper liner assembly
108 comprises a central conduit or production liner 74, a seal
assembly mandrel 110 to sting into the flared seal bore receptacle
96 located at the upper end of the lower liner assembly 66 to
provide both vertical and rotational travel for the upper liner
assembly 108 during a subsequent upper liner assembly alignment
step, a precut production liner window 112 to be positioned
adjacent to the upper lateral window 44 such that the upper extent
114 of precut liner window 112 is located above the upper apex 58
of lateral window 44 and the lower extend 116 of precut liner
window 112 is located below the lower apex 62 of lateral window 44,
an internal seal bore/latch down collar 118 located slightly below
the base of precut liner window 112 with a liner orientation guide
slot profile indexed exactly 180° opposed to the longest
center-line axis of precut liner window 112, an internal seal bore
collar 120 located slightly above the top of precut liner window
112, a hydraulically inflatable external casing packer 122 located
above the upper lateral completion 22 and upper seal bore collar
120, and a flared liner seal bore receptacle 124 connected to the
work string 68 and setting tool 70. Subsequent to running the
upper production liner assembly 108 into production well casing 18
and stinging seal assembly mandrel 110 into seal bore receptacle
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96 so as to position the precut liner window 112 approximately
adj acent to the upper lateral window 44 , the same alignment and
setting procedure used to align and set the lower production liner
assembly 66 described hereinabove is used to align and set the
upper production liner assembly 108. During the alignment step for _
the upper liner assembly 108, the seal assembly mandrel 110 should
be of sufficient length to enable it to remain within the seal bore
receptacle 96 to ensure the upper lateral completion 22 is
effectively isolated from the lower lateral completion 24 after
inflation of external casing packer 122. Subsequent to setting
packer 122, the work string 68 and setting tool 70 are rotated
clockwise to release the setting tool 70 from the upper liner
assembly 108 at the left hand threads 72.
It will be appreciated that the relative positions of tools
contained in the production liner assemblies 66, 108 may be
adjusted to accommodate different well configurations, however it
is anticipated that systems will be developed in order to
standardize production liner assemblies to fit various ~common~
well geometry defined by production casing/lateral liner size and
lateral well deviation angles at the junction between the vertical
well and the lateral well.
As illustrated in FIG. 12, the work string and setting tool
(not shown) have been removed from well 10. Diverter assembly 126
is run into the vertical portion of well 10 and into upper
production liner assembly 108 and lower production liner assembly
66 using work string 68 and diverter assembly setting mandrel 128.
Diverter assembly 126 comprises an external casing packer 130 at
its lower end for anchoring the diverter assembly 126 after proper
alignment, a spacer sub with a "drillable" locator ring 132, a
lower whipstock member 134 with a spring activated orientation
guide key 136, and a wedge shaped upper whipstock member 138 which
is connected to lower whipstock member 134 by short hinge pins 140
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to enable upper member 138 to pivot against lower member 134 in a
direction opposite lower lateral completion 24 after packer 130 has
been set and setting mandrel 128 has been removed. Diverter
' assembly 126 has a bore 142 extending from the whipstock face 144
to the end of the assembly at packer 130. Bore 142 has a smaller
inside diameter seal profile 146 at the end of packer 130 to seat
a weighted packer setting ball (not shown) after a.t has traveled
through work string 68, setting mandrel 128, and diverter assembly
126. Subsequent to aligning diverter assembly 126 to facilitate
re-entry of lateral completion 24, a packer setting ball (not
shown) is dropped and seated in seal bore profile 146, then
pressure is applied to hydraulically inflate anchoring packer 130.
Diverter setting mandrel 128 extends through bore 142 in upper
whipstock member 138 and into the top of lower member 134 and is
connected to lower whipstock member 134 with left hand threads 148
to facilitate a clockwise rotational release after packer 130 is
set. Diverter assembly 126 is positioned within lower production
liner assembly 66 such that spring activated orientation guide key
136 engages liner orientation guide slot in seal bore/latch down
profile collar 90 of the lower production liner assembly 66. With
guide key 136 engaged in guide slot 90, whipstock face 144 will be
aligned in both azimuth direction and depth to facilitate re-entry
into lateral completion 24 through precut liner window 84 and lower
lateral window 46 by diverting downhole tools (not shown) off
whipstock face 144 and into lower lateral completion 24.
Referring to FIG. 13, weighted packer setting ball 150 is
dropped through the work string (not shown) and seated in seal bore
profile 146. Pressure is applied against ball 150 to hydraulically
inflate packer 130. The work string is rotated clockwise to
release the diverter setting mandrel (not shown) from the diverter
assembly 126. As the setting mandrel is removed from bore 142,
upper whipstock member 138 pivots against lower whipstock member
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134 until top of upper member 138 rests on the inside wall of lower
production liner assembly 66. The work string and setting mandrel
are removed from well 10 to enable re-entry tools to be run through
the vertical portion of well 10 and into lateral completion 24.
Referring now to FIG. 14, re-entry operations have been _
completed and diverter assembly 126 will be removed from well 10
in order to re-establish the large inside diameter integrity of the
vertical portion of well 10 so large diameter tools may be placed
in the cased sump 48 located below all completion intervals . A
burning shoe/wash pipe/internal taper tap fishing tool assembly 152
is run on work string 68 to, the top of diverter assembly 126. A
mechanical or hydraulically activated jarring tool 160 is installed
between work string 68 and fishing tool assembly 152 to provide
means to impart a jarring action on diverter assembly 126 if
necessary to facilitate removal of same. Fishing tool assembly 152
comprises a conventional full bore burning shoe 154 (ie: Type D
Rotary Shoe which cuts on the bottom and on the inside of the shoe)
at the bottom which is closely fitted to the inside diameter of the
production liner assemblies 66, 108, sufficient length of washpipe
156 to enable the upper portion of diverter assembly 126 (from the
packer 130 to the top of upper whipstock member 138) to be
swallowed as fishing tool assembly 152 is rotated and lowered over
diverter assembly 126, and an internal taper tap tool 158 connected
to the top of fishing tool assembly 152 and sufficiently spaced
within washpipe 156 such that the bottom of taper tap tool will
firmly engage bore 142 inside diverter assembly 126 as fishing tool
assembly 152 rotates down to the top of packer 130. The locator
ring on spacer sub 132 provides an indication to the driller that
the burning shoe is immediately above the packoff elements of
packer 130. After burning shoe 154 drills up a portion of the
locator ring on sub 132, taper tap tool 158 will torque up as it
engages diverter assembly 126 through bore 142. The hole is then
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circulated to remove all debris released as a result of the burning
shoe rotation. Shear pins (not shown) which deflate packer 130 are
then broken by applying tensional force to work string 68, jars
160, and fishing tool assembly 152, thus releasing packer 130.
Jarring tool 160 may be used to apply additional jarring force to
shear deflation pin in packer 130 and otherwise free diverter
assembly from production liner assembly 66.
As shown in FIG. 15, the diverter assembly has been removed
from the well by pulling the work string, jars, and fishing tool
assembly out of the vertical portion of well 10. The diverter
assembly may then be redressed or otherwise reconditioned for use
in another re-entry operation.
A lower retrievable flow control device 162 with sand control
encasement sleeve, lower seal/latch down mandrel, and upper seal
mandrel is then conveyed on a work string with a clockwise rotation
setting tool (not shown) to the lower precut liner window 84. The
lower seal/latch down mandrel of the lower flow control device 162
is then latched and seated into internal seal bore/latch down
profile collar 90. The upper seal mandrel in flow control device
162 will then be seated in internal seal bore collar 92 due to the
preconfigured spacing of collar 92 relative to collar 90. The work
string is then rotated clockwise to release flow control device 162
and removed from well 10.
An upper retrievable flow control device 164 with sand control
encasement sleeve, lower seal/latch down mandrel, and upper seal
mandrel is then conveyed on a work string with a clockwise rotation
setting tool (not shown) to the upper precut liner window 112. The
lower seal/latch down mandrel of the upper flow control device 164
is then latched and seated into internal seal bore/latch down
profile collar 118. The upper seal mandrel in flow control device
164 will then be seated in internal seal bore collar 120 due to the
preconfigured spacing of collar 120 relative to collar 118. The
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work string is then rotated clockwise to release flow control
device 164 and removed from well 10.
A tool (not shown) to manipulate the flow control devices 78,
162, 164 is then run into the vertical portion of well 10 to
facilitate selective testing, stimulation, production, or shut-in
of the different isolated completions 22, 24, 26. The tool may be
run on either production tubing, coil tubing, electric wireline,
or non-electric wireline, depending on the type of flow control
devices installed. As a result of relatively inexpensive workover
operations, flow control devices 78, 162, 164 may be selectively
opened and closed at any time during the productive life cycle of
multi-lateral well 10. The completions 22, 24, 26 may be produced
separately or commingled as conditions dictate due to the flow
control means and completion isolation means disclosed herein.
Should it become necessary to re-enter a lateral completion 22, 24
to facilitate additional completion work, drilling deeper,
drainhole interval testing with zone isolation, sand control,
cleanout, stimulation, and other remedial work, the appropriate
retrievable flow control device 162, 164 is first removed using a
taper tap or other suitable fishing tool (not shown) followed by
the process described above to set and retrieve a preconfigured
diverter assembly.
The multi-lateral completion system described herein provides
a significant amount of flexibility related to hydrocarbon
exploitation. For example (not shown), two tubing strings may be
run into the vertical portion of well 10 with one string extending
into production liner assembly 66, 108. A packer installed on the
longer tubing string at a point below the precut upper liner window ,
112 would then seal the annulus between the tubing string and the
production liner conduit 74. One or both of the lower completions
24, 26 could then be produced up the longer tubing string while the
upper completion 22 is produced up the shorter tubing string
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contained entirely within vertical well casing 18.
In the alternative (not shown), a single production tubing
string with a downhole pump provided at its lower end may extend
' through the inside of well casing 18 and production liner assembly
66, 108 to the large diameter cased sump 48 located below all
completions 22, 24, 26. The downhole pump and its associated
artificial lift equipment would then be used to artificially lift
produced liquids as they gravity drain to the cased sump 48. Since
most downhole pumps utilized in the oil industry today are designed
to pump incompressible fluids only, pump efficiencies would be
enhanced because any gas associated with the produced liquids would
be free to vent out the annulus between the production tubing and
production liner/casing as the liquids spill down to the pump.
With the pump located below the producing horizons, reservoir
pressure drawdown during production operations will be maximized
yielding improved hydrocarbon recovery compared with downhole pumps
located above the producing horizons) and/or above the lateral
kick-of f point ( s ) . Since the downhole pump does not have to be
positioned in a lateral wellbore to achieve maximum drawdown,
mechanical risk is minimized and operating efficiency is enhanced.
It should be noted that the downhole video camera toll 100
used as a locating device to facilitate the alignment steps
described hereinabove and illustrated in FIGS. 4,9 and 11 could be
replaced with any survey toll or probing device capable of directly
or indirectly locating the lower apex 62, 64 of the generally
elliptically shaped lateral window 44, 46 without deviating from
the spirit of the invention.
Thus, the present invention is well adapted to overcome the
shortcomings of the prior art, carry out the objects of the.
invention, and attain the benefits mentioned hereinabove as well
as those inherent therein. Although this invention has been
disclosed and described in its preferred forms with a certain
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degree of particularity, it is understood that the present
disclosure of the preferred forms is only by way of example and
that numerous changes in the details of construction and operation
and in combination and arrangement of parts may be resorted to
without departing from the spirit and scope of the invention as _
hereinafter claimed.
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Representative Drawing