U.S. patent number RE38,642 [Application Number 09/871,813] was granted by the patent office on 2004-11-02 for downhole equipment, tools and assembly procedures for the drilling, tie-in and completion of vertical cased oil wells connected to liner-equipped multiple drainholes.
This patent grant is currently assigned to Halliburton Energy Services, Inc.. Invention is credited to Michel Gondouin.
United States Patent |
RE38,642 |
Gondouin |
November 2, 2004 |
**Please see images for:
( Certificate of Correction ) ** |
Downhole equipment, tools and assembly procedures for the drilling,
tie-in and completion of vertical cased oil wells connected to
liner-equipped multiple drainholes
Abstract
Single horizontal wells drilled through heterogeneous reservoirs
are capable of greater oil productivity than vertical wells, often
with lower produced GOR and WOR. Multiple drainholes tied-in to a
vertical cased well are even more beneficial. Completion of such
drainholes in many sandy reservoirs must use cemented liners. Well
configurations comprising multiple drainholes liners, each of them
tied-in to a vertical casing by pressure-tight connections require
novel technologies making use of some novel downhole equipment,
tools and procedures for drilling, tie-in and completion of such
wells. These may be for newly-drilled wells or may be obtained by
re-entry into an existing vertical cased well. Specific equipment,
including novel casing joints, whipstocks, intermediate liners and
tubing completion assembly components applicable to new wells are
described herein. Equipment comprising novel casing inserts and
patches applicable to re-entry wells, and the corresponding tubing
completion assembly components for a variety of well exploitation
modes are also described, together with the required tools and
procedures. The liners of the drainholes are such that known well
logging and cleaning tools may be used throughout the well's life.
The various tubing completion assemblies can all be run-in and
installed in a single trip. They allow either commingled flow from
all drainholes or selective injection into some drainholes while
others are under production. They are adapted to a variety of
reservoir pressure conditions and of oil types, including heavy oil
produced by sequential "huff and puff" steam injection.
Inventors: |
Gondouin; Michel (San Rafael,
CA) |
Assignee: |
Halliburton Energy Services,
Inc. (Dallas, TX)
|
Family
ID: |
25215487 |
Appl.
No.: |
09/871,813 |
Filed: |
June 4, 2001 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
Issue Date |
|
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861457 |
May 22, 1997 |
Re37867 |
|
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Reissue of: |
814585 |
Dec 30, 1991 |
05462120 |
Oct 31, 1995 |
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Current U.S.
Class: |
166/380;
166/117.6; 166/242.1; 166/313; 166/50; 175/61 |
Current CPC
Class: |
E21B
7/061 (20130101); E21B 41/0035 (20130101); E21B
41/0042 (20130101); E21B 43/305 (20130101); E21B
43/14 (20130101); E21B 43/24 (20130101); E21B
43/10 (20130101) |
Current International
Class: |
E21B
7/04 (20060101); E21B 7/06 (20060101); E21B
43/00 (20060101); E21B 43/24 (20060101); E21B
43/30 (20060101); E21B 41/00 (20060101); E21B
43/14 (20060101); E21B 43/16 (20060101); E21B
007/10 (); E21B 043/00 () |
Field of
Search: |
;166/313,117.5,117.6,50,380 ;175/61,77-82 |
References Cited
[Referenced By]
U.S. Patent Documents
Foreign Patent Documents
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2282835 |
|
Apr 1995 |
|
GB |
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2295840 |
|
Jun 1996 |
|
GB |
|
787 611 |
|
Dec 1980 |
|
SU |
|
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Exhibit B: Defendants' Defendants' Original Answer, Jul. 29, 1996.
.
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Exhibit H: Defendants' Amended Motion for Summary Judgment on All
Claims in Plaintiffs First Amended Original Petition, Sep. 12,
1997. .
Exhibit I: Plaintiffs Second Amended Original Petition, Sep. 25,
1997. .
Exhibit J: Plaintiffs Response to Defendants' Amended Motion for
Summary Judgment on All Claims in Plaintiffs First Amended Original
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Exhibit K: Stipulation Between NRG and Halliburton Regarding
Exchange of "Confidential" and "Highly Confidential" Information.
.
Exhibit L: Defendants' Reply Memorandum in Support of Motion for
Summary Judgment on All Claims Based on Defendants' Independent
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3, 1997. .
Exhibit M: Plaintiffs Third Amended Original Petition, Mar. 3,
1998. .
Exhibit N: Supplemental Agreed Protective Order Between Baker
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Halliburton Company and Sperry-Sun Drilling Services, Inc., Mar.
30, 1998. .
Cooper, G.A., and M. Gondouin, "Improved Steam Stimulation of Heat
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Project No. CT 90 A-046-TW (submitted Nov. 1991)..
|
Primary Examiner: Dang; Hoang
Parent Case Text
FIELD OF THE INVENTION
.Iadd.This is a continuation of reissue application Ser. No.
08/861,457 filed on May 22, 1997, which has issued as U.S. Pat. No.
RE37,867. Application Ser. No. 09/824,738, filed on Apr. 4, 2001,
is also a continuation of reissue application Ser. No. 08/861,457.
Application Ser. No. 09/944,115, filed on Sep. 4, 2001, is also a
continuation of reissue application Ser. No. 08/861,457.
Application Ser. No. 09/956,806, filed on Sep. 21, 2001, is also a
continuation of reissue application Ser. No. 08/861,457. All of the
above applications are reissue applications of original U.S. Pat.
No. 5,462,120, application Ser. No. 07/814,585, filed Dec. 30,
1991. .Iaddend.
Claims
I claim: .[.
1. Apparatus for completing a multi-branch cased well for oil
recovery by sequential cyclic steam injection methods and for
petroleum production from non-uniformly-pressured heterogeneous
reservoirs through medium curvature, liner-equipped, horizontal
drainholes; said apparatus includes downhole equipment, tools and
devices for making casing/liner and liner tubing sealed connections
and individual liner/drainhole flow connections, comprising: a) a
special steel casing joint equipped with a hard metal multi-channel
whipstock permanently affixed to and sealed in said casing joint by
means of an upper guide plate presenting at least two small
feed-through vertical holes, one of which terminated at both ends
by threaded connections, and two larger vertical holes, each
leading to a slanted cylindrical curved channel partly filled with
a cement plug and each said channel leading to an elliptical window
machined in a direction slanted downwards at a pre-selected
kick-off angle into the wall of said casing joint and plugged by a
drillable plate conforming with the outer surface of said casing
joint, b) a retrievable wedge-type top whipstock tool whose base
presents at least two alignment pins or prongs fitting into said
guide plate small holes, in which they are held by releasable
latches, said top whipstock's outer lateral surface presenting at
least one latching recess for its removal using an overshot tool,
c) an overshot tool equipped with releasable hooks to pull out,
re-orient and reset said top whipstock, in the same trip, d) a
steel liner inserted in a drainhole drilled through each said
whipstock channel, said liner hung with devices resisting liner
weight and thermal expansion forces applied to said liner from
above as well as from below and said liner permanently sealed into
said channel by a pressure-sealing device including a
heat-resistant seal, in addition to thermal cement, e) a tubing
completion assembly conveying production fluids from a drainhole to
the surface and steam from the surface to a drainhole; wherein said
tubing completion assembly is terminated, at its lower end, by a
heat-resistant, pressure-tight, multiple-breakable-sealed
connecting device wherein two pairs of vertical tubular connector
prongs, equipped with releasable high-temperature-sealing devices,
respectively fit into the two larger holes and into the two smaller
holes in the guide plate of said special casing joint, to
respectively convey production fluids from a drainhole to said
tubing assembly and steam from a known three-way valve to the other
drainhole, f) a hydraulically-operated slot-cutting tool for
selectively perforating said drainhole liner to establish a flow
connection between a surrounding oil reservoir and said liner in
its uncemented lower part..]. .[.
2. Apparatus for completing a multi-branch cased well for oil
recovery by sequential cyclic steam injection methods and for
petroleum production from non-uniformly-pressured heterogeneous
reservoirs through medium curvature, liner equipped, horizontal
drainholes; said apparatus includes downhole equipment, tools and
devices for making casing/liner and liner/tubing sealed connections
and individual liner/drainhole flow connections, comprising: a) a
special steel cylindrical casing joint presenting an elliptical
side window machined at a prescribed small downwards kick-off angle
and covered by a drillable metal plate shaped to conform with the
outer surface of said casing joint which is also equipped with a
drillable orientation device comprising a vertical key or groove,
b) a drillable support and packer affixed in said casing joint by
slips below said window, c) a retrievable single-channel whipstock
tool set within said packer in accordance with a matching
orientation device; said whipstock presents at least one guiding
groove on its slanted surface and at least one latching recess on
its cylindrical surface, d) a short intermediate steel liner of a
diameter slightly smaller than said window's short axis, allowing
its insertion into a kicked-off hole, through the window and
wherein the upper end of said intermediate liner is equipped with a
pressure-sealing gasketed drillable collar shaped to conform both
with the inner surface of the casing joint along the edge of the
window and with said guiding groove in the whipstock, so that said
gasketed end, when pressed against the the inner surface of the
casing joint, provides a permanent high-temperature seal in
addition to thermal cement around said intermediate liner, e) an
overshot tool, equipped internally with at least one spring-loaded
hook to latch into the whipstock's latching recess or key and pull
it out; said tool also presents at its lower end some milling
cutters, for surfacing the liner's drillable collar and for
drilling-out the packer slips and support, and said tool includes a
latching device, for pulling-out the drilled-out packer, f) a
selectively perforated drainhole steel liner inserted in a
drainhole drilled through such intermediate liner, hung from above
as well as from below and cemented in the lower part of said
intermediate liner, and having the annular space between
intermediate liner and drainhole liner sealed with an inflatable
packer, g) a tubing completion assembly conveying production fluids
from a drainhole to the surface and steam from the surface to a
drainhole, wherein said tubing completion is terminated at its
lower end by a heat-resistant, pressure-tight,
multiple-breakable-sealed connecting device wherein several
articulated connector steel tubes are each inserted into the upper
part of the intermediate liner of a drainhole, and the annular
space between the inner surface of said intermediate liner and said
connector tube is sealed by an inflatable thermal packer, h) a
hydraulically-operated slot-cutting tool for selectively
perforating the uncemented lower part of each drainhole liner..].
.[.
3. Apparatus for completing a multi-branch cased well for oil
recovery by sequential cyclic steam injection methods and for
petroleum production from non-uniformly-pressured heterogeneous
reservoirs through medium curvature, liner-equipped, horizontal
drainholes; said apparatus includes downhole equipment, tool and
devices for making multiple casing/liner and liner/tubing sealed
connections and individual liner/drainhole flow connections,
comprising: a) at least one special casing joint in the casing
string of a vertical hole, opposite a reamed interval straddling
the kick-off points of one or more drainholes, said joint
presenting one or more elliptical windows oriented downwards and
facing pre-selected kick-off directions at various depths, b) a
telescopic steel liner stub closed at its lower end by a drillable
metal plate plugging each window, and machined at both ends to
conform respectively with the outer surface of the casing window
for the lower end and with the inner surface of the casing window
for the upper end, c) two drillable metal guide cages supporting
said stub, inclined at the kick-off angle, with one of the two
guide cages affixed inside the casing joint by drillable fasteners
while the other, freely inserted into the stub, is mobile and can
slide within said fixed guide over an interval equal to a fraction
of the stub length, d) a drillable gasketed collar affixed to the
stub's upper end to prevent said telescopic stub's upper end from
popping out through the window into the reamed cavity when the stub
is extended by increasing the hydraulic pressure in the casing with
respect to that of the annulus during cementation of the casing
string and of each extended stub, with a cement slurry displaced
behind the casing and wherein said gasketed collar presents at
least one guiding key or groove sliding along a bar of the fixed
guide cage, to prevent any rotation of the stub around its axis, e)
a steel liner inserted in a drainhole drilled through such a liner
stub, permanently hung by a dual hanger's opposing slips into said
stub and sealed with a high-temperature pressure-sealing device, in
addition to thermal cement, f) a tubing completion assembly,
conveying production fluids from a drainhole to the surface and
steam from the surface to a drainhole, having at its lower end a
heat-resistant, pressure-tight, multiple-breakable-sealed
connecting device wherein telescopic connector steel tubes inclined
at the kick-off angle are facing each window, with the tube's lower
end equipped with a high-temperature sealing device insertable into
the upper part of the window's stub and set when said connector
tube is in its extended position, whereas the upper end of said
tube is equipped with a movable sliding seal remaining within a
cylindrical cavity of said tubing completion assembly, g) a
hydraulically-operated slot-cutting tool for selectively
perforating the uncemented lower part of each drainhole liner..].
.[.
4. The apparatus for completing a multi-branch cased well of claims
1, 2 or 3 wherein the hydraulically-operated slot-cutting tool
comprises: a) a cylindrical tool body inserted into said drainhole
liner wherein a plurality of cutting wheels, each one mounted on a
perpendicular axis to that of said body, at the end of an
hydraulically-operated articulated arm, are periodically pressed
into the inner surface of said liner wall, which they penetrate, by
large forces applied only when the arms are extended by the
displacement of a spring-loaded hydraulic piston sliding in a
pressurized liquid-filled cylinder, b) a source of periodic
hydraulic fluid pressure at the surface, c) a coiled tubing of
smaller diameter than that of said drainhole liner, connecting said
cylindrical body to said pressure source and providing a mechanical
link to the surface, to insert and pull-out the tool body through
the liner, thus causing each cutting wheel to cut a slot into the
liner wall, substantially parallel to the axis of said liner, while
the arms are kept in their extended position, but leaving the liner
wall intact when the arms are brought into their retracted position
along the tool body..]. .[.
5. The apparatus for completing a multi-branch cased well of claim
3, wherein the tubing completion assembly comprises a
multiple-breakable-sealed connecting device presenting at least two
slightly inclined fixed branches, each one terminated by a
connector tube assembly equipped at its end-with a known sealing
device, taken from a list comprising: thermal packings, O rings and
metal/metal seals, to provide a breakable pressure-seal against the
inner surfaces of said casing/liners's connecting device; said
connector tube assembly comprises: a) a cylindrical body with its
upper end connected to a tubing and forming with said tubing an
angle equal to that formed by the casing/liner connecting device
and the casing, and said upper end equipped with anchoring means to
fasten it to the inner surface of the casing, b) a connector steel
tube sliding through said cylindrical body under the
surface-controlled pressure of a hydraulic fluid which also
compresses a spring against an arrestor ring, to provide a
spring-loaded, high-temperature end seal of said connector tube
when in its extended position, c) a wireline-releasable mechanical
latch maintaining said spring under compression after the hydraulic
pressure has been released. d) means for latching a suitable
retrieval wireline tool to the tail end of said connector tube to
retract it and to latch it into said body in its retracted
position, in the event that the whole tubing completion assembly
has to be pulled out for inspection or repairs, e) a packing-type,
high-temperature lateral seal in the annulus between said
cylindrical body and the tube within said connector tube assembly,
providing a breakable pressure-sealed flow connection between said
liner and said tubing. f) a packing-type, heat-resistant seal
around said connector tube, above said end seal, providing an
additional pressure-seal against the inner surface of the
casing/liner connecting device in which the connector tube is
inserted..]. .[.
6. The apparatus for completing a multi-branch cased well according
to claims 1, 2 or 3 further comprising a downhole pump and means
for preventing pump cavitation and gas lock in the tubing
completion assemblies, when they convey gassy or boiling production
fluids to the surface; said means comprising: 1) a vertical sump,
closed at its top by a conventional multi-string tubings/casing
packer and connected to said multiple drainholes, and wherein the
absolute flowing pressure of said produced fluids, at the point of
highest elevation in the flow path from the drainholes to said
sump, may drop below the bubble point absolute pressure of said
fluids, a situation resulting in gases being evolved or coming out
of solution to form a gas pocket which interrupts the flow of
liquids from said drainholes into the sump pump, 2) a
wireline-retrievable gas-purging device suitable for latching into
the short string of the multi-string packer located at the top of
the sump, wherein said device is taken from a downhole equipment
list comprising: a) a normally closed subsurface valve whose
opening is controlled by a fluid level sensor at the top of said
oil sump to periodically purge into the compartment above said
packer any gas phase accumulating above a pre-determined fluid
level depth, b) a wireline-retrievable plug in said packer,
comprising a permselective membrane permeable to diffusing gas but
impervious to liquid flow, for continuously purging of said gas
phase, under a gas pressure gradient, c) a venturi in the
pump-discharged liquid production stream flowing through a string
adjacent to said plug in said multi-string packer, at its exit into
an enlarged flow cross section above said packer, which is equipped
with a gas flow connection between the side of said venturi and the
upper face of said membrane, to create said gas pressure
gradient..]. .[.
7. A method for drilling and completing a multi-branch cased well
for oil recovery by sequential cyclic steam injection methods and
for petroleum production from non-uniformly pressured heterogeneous
reservoirs through medium-curvature, liner-equipped, horizontal
drainholes, wherein casing/liner connections are
permanently-sealed, wherein liner/tubing are connected by
breakable-seals, and comprises the following steps: a) drilling a
pair of short deviated boreholes through the bottom of said
vertical well casing, b) inserting in said pair of drainholes two
short intermediate steel liners using a work string ended with an
inverted Y nipple joint, two articulated nipple joints, each one
equipped with a rubber cementing seal cup, and holding said
intermediate liner with a releasable latch, c) stab-in cementing of
said two short intermediate liners using said work string as
cementing string, with sufficient overlap of a special
high-temperature resin cement in the casing to provide a permanent
gas-tight thermal tie-in of the casing with each intermediate
liner, d) drilling successively each drainhole through each
intermediate liner, e) running a coiled-tubing steel liner through
each said intermediate liner into said drilled drainhole, affixing
it to the intermediate liner with a dual hanger's opposing slips
and with a high-temperature pressure-sealing device prior to
cementing its upper end to the intermediate liner's lower end, with
a known thermal cement, f) connecting the upper part of each
intermediate liner to the lower end of a tubing assembly equipped
with a heat-resistant pressure-tight, multiple-breakable-sealed
connecting device, g) selectively perforating the uncemented lower
part of said coiled tubing liner "in situ" using a
hydraulically-operated slot-cutting tool at the end of a
smaller-diameter coiled-tubing run-in from the surface and inserted
through said tubing assembly and intermediate liner into said
drainhole liner..]. .Iadd.
8. In a method of tying-in a first tubular member to a second
tubular member in a wellbore extending into a subterranean
formation, the method comprising the steps of: (a) positioning the
second tubular member in the wellbore; (b) forming an opening in
the wall of the second tubular member, the opening being formed
either prior to or after positioning of the second tubular member
in the wellbore; (c) forming a subsurface cavity external to the
second tubular member in the subterranean formation wherein the
step of forming comprises under-reaming the subterranean formation
to enlarge the wellbore; (d) positioning the first tubular member
to extend from the interior of the second tubular member, through
the opening, and into the subsurface cavity; and (e) inserting
settable material into the subsurface cavity at the intersection
between the first and second tubular members and allowing the
settable material to set thereby sealing the intersection.
.Iaddend..Iadd.
9. The method of claim 8, wherein the step of positioning the
second tubular member in the wellbore comprises positioning a
casing patch having a preformed opening in the wall thereof in the
area of the enlarged wellbore. .Iaddend..Iadd.
10. The method of claim 8, wherein the first tubular member has an
end shaped so as to cooperate with the inner edge of the opening.
.Iaddend..Iadd.
11. The method of claim 8, wherein the first tubular member
includes a flanged element larger than the opening, the method
further comprising the step of positioning the flanged element in
contact with the inner surfaces of the second tubular member at the
edge of the opening. .Iaddend..Iadd.
12. The method of claim 11 further comprising the steps of urging
the flanged element against the second tubular member.
.Iaddend..Iadd.
13. The method of claim 8, wherein the inner diameter of the first
tubular member is of sufficient diameter to allow the passage of
well tools. .Iaddend..Iadd.
14. The method of claim 8 further comprising the step of injecting
gas into at least one of the first and second tubular members, to
promote production of oil from the wellbore. .Iaddend..Iadd.
15. The method of claim 14 wherein the gas is steam.
.Iaddend..Iadd.
16. The method of claim 8 further comprising the step of removing
any material in the second tubular member to reopen the second
tubular member to its full bore at the intersection of the first
and second tubular members. .Iaddend..Iadd.
17. A method of forming the intersection between a primary borehole
and a secondary borehole comprising the steps of: under-reaming a
portion of the primary borehole at the location of the secondary
borehole to be formed; installing a joint assembly in the primary
borehole at the location of the secondary borehole to be formed;
forming an opening in the joint assembly at the location of the
secondary borehole to be formed, the opening being formed either
prior to or after the joint assembly is installed; extending a
tubular member through the opening and into the under-reamed
portion of the primary borehole; drilling the secondary borehole
through the extended tubular member; and applying a settable
material into the under-reamed portion of the primary borehole and
about the joint assembly and the tubular member at the under-reamed
portion. .Iaddend..Iadd.
18. The method of claim 17, wherein the secondary borehole is
drilled through the extended tubular member after the settable
material has hardened. .Iaddend..Iadd.
19. The method of claim 17, wherein the joint assembly has a
preformed opening in the wall thereof. .Iaddend..Iadd.
20. The method of claim 17, wherein the tubular member has an end
shaped so as to cooperate with the inner edge of the opening.
.Iaddend..Iadd.
21. The method of claim 17, wherein the tubular member includes a
flanged element larger than the opening, and the method further
comprising the step of positioning the flanged element in contact
with the inner surfaces of the joint assembly at the edge of the
opening. .Iaddend..Iadd.
22. The method of claim 21 further comprising the steps of urging
the flanged element against the joint assembly. .Iaddend..Iadd.
23. The method of claim 17, wherein the inner diameter of the
tubular member is of sufficient diameter to allow the passage of
well tools. .Iaddend..Iadd.
24. The method of claim 17 further comprising the step of injecting
steam into at least one of the primary and secondary boreholes, to
promote the production of oil from the wellbore.
.Iaddend..Iadd.
25. The method of claim 17 further comprising the step of removing
any material in the joint assembly to open the joint assembly to
its full bore at the intersection of the primary and secondary
boreholes. .Iaddend..Iadd.
26. A method of forming the intersection between a primary, cased
borehole and a secondary borehole comprising the steps of: removing
a portion of the casing adjacent the location of the secondary
borehole to be formed; subsequently under-reaming the primary
borehole at the removed portion of the casing; subsequently
installing a joint assembly at the location of the secondary
borehole to be formed, the joint assembly including a window formed
either prior to or after the joint assembly is installed;
subsequently extending a tubular member through the window and into
the under-reamed portion of the primary borehole; drilling the
secondary borehole through the window and the tubular member; and
applying a settable material into the under-reamed portion and
about the tubular member and the joint assembly proximate the
tubular member. .Iaddend..Iadd.
27. The method of claim 26, wherein the window in the joint
assembly is preformed and positioned at the under-reamed portion of
the primary borehole. .Iaddend..Iadd.
28. The method of claim 26, wherein the tubular member has an end
shaped so as to cooperate with the inner edge of the window.
.Iaddend..Iadd.
29. The method of claim 26, wherein the tubular member includes a
flanged element larger than the window, the method further
comprising the step of positioning the flanged element in contact
with the inner surface of the joint assembly at the edge of the
window. .Iaddend..Iadd.
30. The method of claim 26, wherein the inner diameter of the
tubular member is of sufficient diameter to allow the passage of
well tools. .Iaddend..Iadd.
31. The method of claim 26 further comprising the step of injecting
steam into at least one of the primary and secondary boreholes, to
promote production of oil from the wellbore. .Iaddend..Iadd.
32. The method of claim 26 further comprising the step of removing
any material in the joint assembly to reopen the joint assembly to
its full bore at the intersection of the primary and secondary
boreholes. .Iaddend..Iadd.
33. A method of forming a second borehole from first well bore
comprising the steps of: enlarging a section of the first well bore
at the subterranean location where the second borehole is to be
formed; providing a joint assembly changeable from a first position
wherein the joint assembly is in a retracted position and is of a
size and shape to pass through the well bore, to a second position
wherein at least a portion of the joint assembly expands and
extends into the enlarged section of the well bore; running the
joint assembly through the well bore to the enlarged section of the
well bore while maintaining the joint assembly in the first
position; causing the joint assembly to expand to the second
position; drilling a second borehole along a path defined by the
joint assembly when in the second position; and applying a settable
material into the enlarged section of the well bore and about the
joint assembly. .Iaddend..Iadd.
34. The method of claim 33, wherein the first well bore is cased,
and the joint assembly is of the size and shape that it will pass
through the cased well bore, when in the first position.
.Iaddend..Iadd.
35. The method of claim 34, wherein the joint assembly is hung from
the casing above the enlarged section of the well bore.
.Iaddend..Iadd.
36. The method of claim 33 further comprising the step of
installing liners through the joint assembly. .Iaddend..Iadd.
37. A method of forming the intersection between a primary borehole
and a secondary borehole comprising the steps of: under-reaming a
portion of the primary borehole at the location of the secondary
borehole to be formed; installing an expandable bladder within the
under-reamed portion of the primary borehole; installing a guide
member within the bladder at the location of the secondary borehole
to be formed; and extending the bladder outwardly from the primary
borehole and into the under-reamed portion. .Iaddend..Iadd.
38. The method of claim 37, wherein the step of extending the
bladder includes applying settable material into the bladder.
.Iaddend..Iadd.
39. The method of claim 37 further comprising the step of drilling
the secondary borehole along a path defined by the guide member.
.Iaddend..Iadd.
40. The method of claim 37, wherein the guide member is a tubular
member. .Iaddend..Iadd.
41. The method of claim 37, wherein the guide member and the
bladder are each part of a joint assembly run into the primary
borehole. .Iaddend..Iadd.
42. The method of claim 41, wherein the guide member and the
bladder are run into the well in a retracted position and are both
subsequently extended into the under-reamed portion of the primary
borehole. .Iaddend..Iadd.
43. The method of claim 37, wherein the joint assembly includes a
casing joint and wherein the bladder is formed over the casing
joint. .Iaddend..Iadd.
44. The method of claim 43, wherein the guide member, when in the
retracted position, is inside the casing joint. .Iaddend..Iadd.
45. The method of claim 43, wherein during the extending step the
bladder at the under-reamed portion extends outwardly beyond the
outer diameter of the casing joint. .Iaddend..Iadd.
46. The method of claim 38, wherein during the applying a settable
material step, settable material is applied about at least a
portion of the guide member. .Iaddend..Iadd.
47. A method of forming the intersection between a primary borehole
and a secondary borehole to be formed from the primary borehole
comprising the steps of: under-reaming a portion of the primary
borehole at the location of the secondary borehole to be formed;
installing an expandable bladder within the under-reamed portion of
the primary borehole; installing an expandable guide member within
the bladder at the location of the secondary borehole to be formed;
extending the expandable guide member and the bladder outwardly
into the under-reamed portion; and applying a settable material
into the bladder to urge the bladder against the walls of the
under-reamed portion of the primary borehole. .Iaddend..Iadd.
48. The method of claim 47 further comprising the step of drilling
the secondary borehole along a path defined by the extended guide
member. .Iaddend..Iadd.
49. The method of claim 47, wherein the guide member and the
bladder are each part of a casing joint run into the primary
borehole. .Iaddend..Iadd.
50. The method of claim 47, wherein the guide member and the
bladder are run into the well in a retracted position and are
subsequently extended into the under-reamed portion of the primary
borehole. .Iaddend..Iadd.
51. A method of forming a second borehole from a first borehole
having casing along at least a portion of its length comprising the
steps of: under-reaming a portion of the first borehole; running a
joint assembly, when in a retracted position, through the casing in
the first borehole and installing the assembly at the under-reamed
portion of the first borehole, the joint assembly including a
deformable wall; deforming the deformable wall of the joint
assembly outwardly into the under-reamed portion of the first
borehole; applying settable material into the under-reamed portion
to support the deformable wall within the under-reamed portion; and
drilling a second borehole along a path defined by the joint
assembly after the deformable wall is held in position by the
settable material. .Iaddend..Iadd.
52. A method of forming the intersection between a primary borehole
and a secondary borehole comprising the steps of: under-reaming a
portion of the primary borehole at the location of the secondary
borehole to be formed; installing a joint assembly in the primary
borehole at the location of the secondary borehole to be formed;
forming an opening in the joint assembly at the location of the
secondary borehole to be formed, the opening being formed either
prior to or after the joint assembly is installed; extending a
tubular member through the opening and into the under-reamed
portion of the primary borehole, wherein the tubular member has an
end shaped so as to cooperate with the inner edge of the opening;
and drilling the secondary borehole through the extended tubular
member. .Iaddend..Iadd.
53. The method of claim 52 further including the step of applying a
settable material into the under-reamed portion of the primary
borehole and about the joint assembly and the tubular member at the
under-reamed portion. .Iaddend..Iadd.
54. The method of claim 53, wherein the secondary borehole is
drilled through the extended tubular member after the settable
material has hardened. .Iaddend..Iadd.
55. The method of claim 52, wherein the joint assembly has a
preformed opening in the wall thereof. .Iaddend..Iadd.
56. The method of claim 52, wherein the inner diameter of the
tubular member is of sufficient diameter to allow the passage of
well tools. .Iaddend..Iadd.
57. The method of claim 52 further comprising the step of injecting
steam into at least one of the primary and secondary boreholes, to
promote the production of oil from the wellbore.
.Iaddend..Iadd.
58. The method of claim 52 further comprising the step of removing
any material in the joint assembly to open the joint assembly to
its full bore at the intersection of the primary and secondary
boreholes. .Iaddend..Iadd.
59. A method of forming the intersection between a primary borehole
and a secondary borehole comprising the steps of: under-reaming a
portion of the primary borehole at the location of the secondary
borehole to be formed; installing a joint assembly in the primary
borehole at the location of the secondary borehole to be formed;
forming an opening in the joint assembly at the location of the
secondary borehole to be formed, the opening being formed either
prior to or after the joint assembly is installed; extending a
tubular member through the opening and into the under-reamed
portion of the primary borehole, wherein the tubular member
includes a flanged element larger than the opening; positioning the
flanged element in contact with the inner surfaces of the joint
assembly at the edge of the opening; and drilling the secondary
borehole through the extended tubular member. .Iaddend..Iadd.
60. The method of claim 59 further including the step of applying a
settable material into the under-reamed portion of the primary
borehole and about the joint assembly and the tubular member at the
under-reamed portion. .Iaddend..Iadd.
61. The method of claim 60, wherein the secondary borehole is
drilled through the extended tubular member after the settable
material has hardened. .Iaddend..Iadd.
62. The method of claim 59, wherein the joint assembly has a
preformed opening in the wall thereof. .Iaddend..Iadd.
63. The method of claim 59 further comprising the steps of urging
the flanged element against the joint assembly. .Iaddend..Iadd.
64. The method of claim 59, wherein the inner diameter of the
tubular member is of sufficient diameter to allow the passage of
well tools. .Iaddend..Iadd.
65. The method of claim 59 further comprising the step of injecting
steam into at least one of the primary and secondary boreholes, to
promote the production of oil from the wellbore.
.Iaddend..Iadd.
66. The method of claim 59 further comprising the step of removing
any material in the joint assembly to open the joint assembly to
its full bore at the intersection of the primary and secondary
boreholes. .Iaddend..Iadd.
67. A method of forming the intersection between a primary borehole
and a secondary borehole comprising the steps of: under-reaming a
portion of the primary borehole at the location of the secondary
borehole to be formed; installing a joint assembly in the primary
borehole at the location of the secondary borehole to be formed;
forming an opening in the joint assembly at the location of the
secondary borehole to be formed, the opening being formed either
prior to or after the joint assembly is installed; extending a
tubular member through the opening and into the under-reamed
portion of the primary borehole; drilling the secondary borehole
through the extended tubular member; and removing any material in
the joint assembly to open the joint assembly to its full bore at
the intersection of the primary and secondary boreholes.
.Iaddend..Iadd.
68. The method of claim 67 further including the step of applying a
settable material into the under-reamed portion of the primary
borehole and about the joint assembly and the tubular member at the
under-reamed portion. .Iaddend..Iadd.
69. The method of claim 68, wherein the secondary borehole is
drilled through the extended tubular member after the settable
material has hardened. .Iaddend..Iadd.
70. The method of claim 67, wherein the joint assembly has a
preformed opening in the wall thereof. .Iaddend..Iadd.
71. The method of claim 67, wherein the tubular member has an end
shaped so as to cooperate with the inner edge of the opening.
.Iaddend..Iadd.
72. The method of claim 67, wherein the tubular member includes a
flanged element larger than the opening, and the method further
comprising the step of positioning the flanged element in contact
with the inner surfaces of the joint assembly at the edge of the
opening. .Iaddend..Iadd.
73. The method of claim 72 further comprising the steps of urging
the flanged element against the joint assembly. .Iaddend..Iadd.
74. The method of claim 67, wherein the inner diameter of the
tubular member is of sufficient diameter to allow the passage of
well tools. .Iaddend..Iadd.
75. The method of claim 67 further comprising the step of injecting
steam into at least one of the primary and secondary boreholes, to
promote the production of oil from the wellbore.
.Iaddend..Iadd.
76. A method of forming the intersection between a primary, cased
borehole and a secondary borehole comprising the steps of: removing
a portion of the casing adjacent the location of the secondary
borehole to be formed; subsequently under-reaming the primary
borehole at the removed portion of the casing; subsequently
installing a joint assembly at the location of the secondary
borehole to be formed, the joint assembly including a window formed
either prior to or after the joint assembly is installed;
subsequently extending a tubular member through the window and into
the under-reamed portion of the primary borehole, wherein the
tubular member has an end shaped so as to cooperate with the inner
edge of the window; and drilling the secondary borehole through the
window and the tubular member. .Iaddend..Iadd.
77. The method of claim 76 further comprising the step of applying
a settable material into the under-reamed portion and about the
tubular member and the joint assembly proximate the tubular member.
.Iaddend..Iadd.
78. The method of claim 76, wherein the window in the joint
assembly is preformed and positioned at the under-reamed portion of
the primary borehole. .Iaddend..Iadd.
79. The method of claim 76, wherein the inner diameter of the
tubular member is of sufficient diameter to allow the passage of
well tools. .Iaddend..Iadd.
80. The method of claim 76 further comprising the step of injecting
steam into at least one of the primary and secondary boreholes, to
promote production of oil from the wellbore. .Iaddend..Iadd.
81. The method of claim 76 further comprising the step of removing
any material in the joint assembly to reopen the joint assembly to
its full bore at the intersection of the primary and secondary
boreholes. .Iaddend..Iadd.
82. A method of forming the intersection between a primary, cased
borehole and a secondary borehole comprising the steps of: removing
a portion of the casing adjacent the location of the secondary
borehole to be formed; subsequently under-reaming the primary
borehole at the removed portion of the casing; subsequently
installing a joint assembly at the location of the secondary
borehole to be formed, the joint assembly including a window formed
either prior to or after the joint assembly is installed;
subsequently extending a tubular member through the window and into
the under-reamed portion of the primary borehole, wherein the
tubular member includes a flanged element larger than the window;
positioning the flanged element in contact with the inner surface
of the joint assembly at the edge of the window; and drilling the
secondary borehole through the window and the tubular member.
.Iaddend..Iadd.
83. The method of claim 82 further comprising the step of applying
a settable material into the under-reamed portion and about the
tubular member and the joint assembly proximate the tubular member.
.Iaddend..Iadd.
84. The method of claim 82, wherein the window in the joint
assembly is preformed and positioned at the under-reamed portion of
the primary borehole. .Iaddend..Iadd.
85. The method of claim 82, wherein the inner diameter of the
tubular member is of sufficient diameter to allow the passage of
well tools. .Iaddend..Iadd.
86. The method of claim 82 further comprising the step of injecting
steam into at least one of the primary and secondary boreholes, to
promote production of oil from the wellbore. .Iaddend..Iadd.
87. The method of claim 82 further comprising the step of removing
any material in the joint assembly to reopen the joint assembly to
its full bore at the intersection of the primary and secondary
boreholes. .Iaddend..Iadd.
88. A method of forming the intersection between a primary, cased
borehole and a secondary borehole comprising the steps of: removing
a portion of the casing adjacent the location of the secondary
borehole to be formed; subsequently under-reaming the primary
borehole at the removed portion of the casing; subsequently
installing a joint assembly at the location of the secondary
borehole to be formed, the joint assembly including a window formed
either prior to or after the joint assembly is installed;
subsequently extending a tubular member through the window and into
the under-reamed portion of the primary borehole; drilling the
secondary borehole through the window and the tubular member; and
removing any material in the joint assembly to reopen the joint
assembly to its full bore at the intersection of the primary and
secondary boreholes. .Iaddend..Iadd.
89. The method of claim 88 further comprising the step of applying
a settable material into the under-reamed portion and about the
tubular member and the joint assembly proximate the tubular member.
.Iaddend..Iadd.
90. The method of claim 88, wherein the window in the joint
assembly is preformed and positioned at the under-reamed portion of
the primary borehole. .Iaddend..Iadd.
91. The method of claim 88, wherein the tubular member has an end
shaped so as to cooperate with the inner edge of the window.
.Iaddend..Iadd.
92. The method of claim 88, wherein the tubular member includes a
flanged element larger than the window, the method further
comprising the step of positioning the flanged element in contact
with the inner surface of the joint assembly at the edge of the
window. .Iaddend..Iadd.
93. The method of claim 88, wherein the inner diameter of the
tubular member is of sufficient diameter to allow the passage of
well tools. .Iaddend..Iadd.
94. The method of claim 88 further comprising the step of injecting
steam into at least one of the primary and secondary boreholes, to
promote production of oil from the wellbore. .Iaddend..Iadd.
95. A method of forming a second borehole from first well bore
comprising the steps of: enlarging a section of the first well bore
at the subterranean location where the second borehole is to be
formed; providing a joint assembly changeable from a first position
wherein the joint assembly is in a retracted position and is of a
size and shape to pass through the well bore, to a second position
wherein at least a portion of the joint assembly expands and
extends into the enlarged section of the well bore; running the
joint assembly through the well bore to the enlarged section of the
well bore while maintaining the joint assembly in the first
position; causing the joint assembly to expand to the second
position; drilling a second borehole along a path defined by the
joint assembly when in the second position; and applying a settable
material into the enlarged section of the well bore and about the
joint assembly. .Iaddend..Iadd.
96. The method of claim 95, wherein the first well bore is cased,
and the joint assembly is of the size and shape that it will pass
through the cased well bore, when in the first position.
.Iaddend..Iadd.
97. The method of claim 96, wherein the joint assembly is hung from
the casing above the enlarged section of the well bore.
.Iaddend..Iadd.
98. The method of claim 95 further comprising the step of
installing liners through the joint assembly. .Iaddend..Iadd.
99. A method of forming a second borehole from first well bore
comprising the steps of: enlarging a section of the first well bore
at the subterranean location where the second borehole is to be
formed; providing a joint assembly changeable from a first position
wherein the joint assembly is in a retracted position and is of a
size and shape to pass through the well bore, to a second position
wherein at least a portion of the joint assembly expands and
extends into the enlarged section of the well bore; running the
joint assembly through the well bore to the enlarged section of the
well bore while maintaining the joint assembly in the first
position; causing the joint assembly to expand to the second
position; drilling a second borehole along a path defined by the
joint assembly when in the second position; and installing liners
through the joint assembly. .Iaddend..Iadd.
100. The method of claim 99 further comprising the step of applying
a settable material into the enlarged section of the well bore and
about the joint assembly. .Iaddend..Iadd.
101. The method of claim 99, wherein the first well bore is cased,
and the joint assembly is of the size and shape that it will pass
through the cased well bore, when in the first position.
.Iaddend..Iadd.
102. The method of claim 101, wherein the joint assembly is hung
from the casing above the enlarged section of the well bore.
.Iaddend.
Description
Horizontal wells have been used extensively in heterogeneous
reservoirs to intersect fractures and/or to reduce the detrimental
effects of gas coning and water coning. It has been shown that such
wells are capable of higher oil production rates than vertical
wells drilled in the same reservoir. In most cases, the higher
productivity more than offsets the higher cost of drilling and
completion of the horizontal well. Theory predicts that the use of
multiple horizontal drainholes correspondingly multiplies the total
well productivity. Indeed many vertical cased wells connected to
twin or multiple horizontal drainholes of medium (500-200 ft) and
short (150-40 ft) radius of curvature have been successfully used
in compact oil reservoirs, such as the Austin Chalk, in which open
hole completion of the drainholes is applicable.
In many clastic reservoirs, however, the strength of unconsolidated
sands or of friable sandstones may be insufficient to keep
horizontal drainholes open. In such a case, the horizontal and
deviated parts of each drainhole must be kept open with a tubular
liner which is tied to the vertical casing using conventional
equipment and known assembly procedures. This has been done in many
different clastic reservoirs, containing light or heavy oil, for
horizontal wells consisting of a single liner-equipped
drainhole.
A patented U.S. Pat. No. 4,787,465 drilling and completion
technique for multiple drainholes of ultra-short (ca. 10 ft) radius
of curvature has also been used in such sandy reservoirs, but the
liners of the short multiple drainholes are not tied-in to the
vertical casing and their inner diameter and curvature radius are
too small to allow the use of conventional logging and cleaning
tools.
SUMMARY OF THE INVENTION
The present invention addresses the problem of drilling,
cementation and tie-in by pressure-tight connections to a casing of
twin or multiple drainholes of medium to short radius of curvature
(typically 500 ft to 40 ft) equipped with liners of sufficient
diameter to allow the passage of available well logging,
perforating, cementing and cleaning tools, for subsequent well
maintenance and repairs.
The next step is to provide the means to bring up the reservoir
fluids and/or to inject fluids from the surface into the reservoir
through the drainhole liners. Depending upon the mode of
exploitation of the well and field conditions, a great variety of
tubing completion assemblies may be used for these purposes. The
simplest, which allows only commingled flow from or into all
drainholes simultaneously, does not even requires any additional
equipment if vertical flow is through the casing, but it provides
minimum operational flexibility and no safety controls. For these
reasons, additional equipment (at least a properly sized production
tubing or a kill string for safety, for instance, and often a
hanger or a packer) will be used in the field. The tubing
completion assembly which provides the greatest operational
flexibility and safety is that which provides a direct connection
of each drainhole separately to a tubing, thus leaving the
casing/tubing annulus available for other uses. This is the type of
tubing completion assembly which is included in the present
invention. It also provides the means of implementing in this type
of heterogeneous reservoirs the heavy oil recovery process and the
injected steam quality conservation process described respectively
in U.S. Pat. No. 4,706,751 and U.S. Pat. No. 5,085,275 using some
of the equipment described in U.S. Pat. No. 5,052,482. The present
invention, however, does not preclude the use of the already known
simpler completion designs, whenever they are sufficient for the
application considered. Known elements of downhole equipment (valve
nipple joints, safety joints, retrievable plugs, etc. . . ) may
also be added, as needed, to the novel tubing completion assembly
to perform specific additional tasks.
Some of the reservoirs under consideration, especially those
containing heavy oil, require artificial lift to bring the
production stream to the surface. The present invention includes
equipment providing the means of pumping produced fluids and of
injecting steam and/or other gases in such wells equipped with
multiple drainholes completed with liners. Sand production being
frequent in such reservoirs, the drainholes may be gravel packed or
equipped with screens or subjected to known sand consolidation
techniques.
The desired well and drainholes configuration may be obtained
either with entirely new wells or by re-entry into an existing
vertical cased well, in which case the required equipment and
procedures are somewhat different.
In all cases it is intended to obtain leak-proof connections
between the drainhole liners and the vertical casing and between
the drainhole liners and the tubings used either for production,
injection and pumping. The desirability of a system which can be
installed in as few steps as possible and which can easily be
disassembled during future work-over operations has led to develop
downhole equipment and procedures, which conform with proven oil
field safety practices.
Due to the complex nature of oil reservoirs, especially those
made-up of clastic rocks deposited in agitated water
(Fluvio-Deltaic environment, turbidite currents or near shore
sedimentation) or those resulting from eolien transport (Dunes),
the presence of various sediment heterogeneities and fractures,
together with other reservoir engineering considerations regarding
water/oil and gas/oil contacts locations, reservoir fluid pressure
and solution GOR of the produced oil, will dictate various well and
drainhole configurations.
Although the most frequently applicable is that of twin drainholes
with their respective horizontal sections oriented at 180 degrees
from each other, the equipment, tools and procedures which will be
described are not restricted to that single configuration. It will
become apparent to those skilled in the art that similar equipment
and procedures may be adapted to all other multiple drainhole
configurations without departing from the spirit of this
invention.
Ranked in increasing degrees of complexity, the cases of drilling,
tie-in and completion of new wells include:
1) side by side drainholes kicked-off from the bottom of a vertical
cased well, using a twin whipstock,
2) side by side drainholes connected by intermediate liners to the
bottom of a vertical well,
3) side by side drainholes obtained from a deviated cased well,
4) stacked drainholes kicked-off one above the other from a new
vertical cased well. Two different tie-in methods and equipment
types will be described, one using telescopic liner stubs and
telescopic connector tubes to tie-in and complete the well, the
other using intermediate cemented liners and articulated connector
tubes.
5) use of a single pump for both drainholes, located above the
kick-off points,
6) conveyance of low GOR production streams from each drainhole
through a syphon to a single pump located near the base of an oil
sump well below the kick-off points,
7) pumping of each drainhole with a pump located at or near the
start of the horizontal segment,
8) simultaneous injection of steam and/or gases into one drainhole
while producing oil and water from the other drainhole, as taught
in in U.S. Pat. Nos. 4,706,751 and in application No. 512,317, now
U.S. Pat. No. 5,085,275.
For re-entry into an existing vertical cased well, modified
equipment and procedures will be described, corresponding to cases
similar to cases 1, 2, 4, 6, 7 and 8 above.
BRIEF DESCRIPTION OF DRAWINGS
FIG. 1 is a vertical cross section of the special casing joint with
twin whipstocks used in Case 1.
FIG. 1a is a perspective drawing showing the base of the
retrievable top whipstock of Case 1.
FIG. 1b is a vertical cross section showing the drainhole tie-in to
the casing.
FIG. 1c is a vertical cross section showing the tubing
completion.
FIG. .[.1ld.]. .Iadd.1d .Iaddend.is a vertical cross section of an
overshot-type tool used in case 1.
FIG. 2 and 2a are vertical cross sections showing schematically the
successive phases of the operations required in Case 2.
FIG. 2b is a vertical cross section of the spherical seal union
joint used in Case 2 and in subsequent cases.
FIG. 2c is a schematic vertical cross section of a hydraulically
operated tool for punching multiple slots into thin gauge
liners.
FIG. 2d is a schematic vertical cross section of the tubing
completion assembly used in Case 2.
.[.FIG. 3 is a vertical cross section of a special casing joint
equipped with a drillable packer and retrievable whipstock for
drilling and completion of the side-tracked hole of Case 3..].
FIG. 3a is a vertical cross section of an intermediate liner.
FIG. 3b is a vertical cross section of the deviated cased well and
side-tracked hole of Case 3.
FIG. 3c is a vertical cross-section of the overshot-type tool used
in Case 3.
FIG. 4 is a vertical cross section showing the special casing joint
with its stub extended and cemented in the reamed cavity of Case
4.
FIG. 4a is a vertical cross section showing connection to the stubs
by means of articulated connector tubes.
FIG. 4b is a schematic flow diagram showing the connection to the
stubs by means of telescopic connector tubes.
FIG. 4c and 4d are vertical cross sections showing telescopic
connector tubes respectively in the retracted and in the extended
positions.
FIG. 4e is a schematic vertical cross section showing the tubing
completion assembly for two pairs of stacked drainholes in Case
4.
FIG. 5a, 5b and 5c are schematic vertical cross sections of a well
and twin drainholes, showing different possible pump locations.
.[.FIG. 6 is a schematic vertical cross section of a well and two
drainholes, showing the various fluid levels in the
reservoir..].
FIG. 6a is a schematic diagram showing the operation of the
periodic gas purging system.
FIG. 6b is a cross section of the permselective plug and venturi
used for continuous gas purging.
FIG. 7 is a vertical cross section of the tubing completion
assembly used for dual pumps in Case 7.
FIG. 8 and 8a are vertical cross sections of the tubing completion
assembly used for Case 8, with the well tie-in configuration of
Case 1.
FIG. 9 and 9a are vertical cross sections of the special casing
insert of Case 1a and 3a respectively.
FIG. 10 is a vertical cross section of the special casing patch
with telescopic stubs used in Case 4a.
FIG. 11 is a schematic vertical cross section of the novel casing
patch used for side-tracking and cementing intermediate liners in
case 4a (second embodiment).
FIG. 12 is a schematic vertical cross section of the tubing
completion assembly including two articulated connector tubes for
Case 8a when an oil sump is used.
FIG. 13 is a schematic vertical cross section of the upper part of
the tubing completion assembly for "huff and puff" steam injection
of Cases 8 or 8a when dual pumps and a 4 string hanger are
used.
DETAILED DESCRIPTION OF THE INVENTION
CASE 1 (TWIN WHIPSTOCK)
In Case 1 a vertical well is drilled to a depth slightly greater
than that of the common kick-off depth of the drainholes. The
casing string is made-up by including a special joint immediately
above the conventional casing shoe and float collar. This casing
joint shown on FIG. 1 includes two elliptical windows (1) machined
at the desired kick-off angle, typically about 2 degrees oriented
downward from the vertical.
These windows are plugged up with a drillable material (an Aluminum
plate (2), for instance) machined to conform with the cylindrical
surfaces of the casing. A twin whipstock (3), of hardened metal, is
securely fastened to the casing joint, for instance by welding. It
provides a curved guiding path from a guide plate above to each of
the two plugged windows. For added strength, a portion of that
curved guide may be partly filled with cement (4) or other
drillable material. The guide plate (5), on top of the whipstock,
presents four vertical cylindrical holes, two of them (6) of a
diameter larger than that of the drainholes and two of them
smaller. One of the smaller holes (7) in the guide plate (5) is
threaded and extends to the whipstock base, to provide a flow path
to the float collar and shoe below it. During cementing operations,
the work string will be stabbed into the threaded connection to
inject the cement slurry into the float collar and shoe and from
there into the annular space behind the casing. The other small
cylindrical hole has a smooth bore. Its function is to receive one
of the alignment pins (8) used to positions and latch a retrievable
whipstock top which provides a continuation of the guiding path
from one of the two large holes to the casing side. The combination
of the permanent twin whipstock with its retrievable top provides a
guide to the drainhole drilling bit through the machined window. A
perspective view of the retrievable top whipstock showing its two
alignment pins (8) is presented on FIG. 1a.
When the first drainhole has been drilled to its total measured
depth, the same whipstock (top and bottom parts) guides the liner
into the drainhole. The liner, in the horizontal part, may be a
slotted liner equipped with screens for gravel packing or it may be
cemented and later selectively perforated. In all cases, however,
the curved part of the liner is cemented using known procedures.
The tail end of the liner is centered and hung into the open large
vertical hole in the bottom whipstock (FIG. 1b), by means of a
known hydraulically-set hanger (9) equipped with dual sets of slips
and pressure-setting seals. It is terminated by the female part of
a polished bore receptacle (10), which connects the liner to the
work string used to run-in and cement the liner. When the cement
has set, the work string is disconnected, a recess in the top
whipstock is latched into hooks in an overshot tool, pulled up and
rotated by 180 degrees for presentation and insertion of the two
alignment pins (or prongs) respectively into each alternate small
hole in the permanent whipstock. The overshot tool is then released
and pulled out.
Drilling of the cement and plug in the second window now begins the
drilling and liner cementing operations for the second drainhole,
using the same procedures. With the liner hung and sealed in the
second large vertical hole in the permanent whipstock, the work
string is disconnected from the second polished bore receptacle.
The top whipstock is latched with an overshot tool and pulled out
of the well. This completes the drainholes drilling and tie-in
operations.
Completion of the well (see FIG. 1c) is achieved by making up and
running-in a tubing string consisting of dual tubing prongs (11)
equipped with chevron seals (12) and connected to the lower ends of
an inverted Y nipple joint (13). The chevron seals constitute the
male mating parts of the two polished bore receptacles (10)
previously installed. The upper branch of the inverted Y nipple
joint (13) is connected to a conventional tubing hanger (14) which
may be set hydraulically or by wireline. The tubing string (15) is
oriented so as to stab the tubing prongs into the female parts of
the two polished bore receptacles. After leak-testing of the sealed
connections, the tubing hanger is set and the wellhead is nippled
up using conventional equipment and procedures.
If the well is not naturally flowing, artificial lift equipment may
also be included in the tubing string, such as gas lift valves,
diverter valves, a pump seat nipple, etc. . . in the manner which
is familiar to those skilled in the art of oil well completion.
CASE 2 (TWIN DEVIATED HOLES)
In Case 2, from a vertical cased well drilled and cemented by
conventional techniques, the casing shoe is drilled out and two
short (ca. 50 ft long) smaller diameter twin deviated holes are
drilled through the bottom of the vertical well. This uses, for
instance, a bit (16) driven by a downhole motor (17) connected to a
bent sub (18), in the type of downhole assembly commonly used for
drilling horizontal wells (see FIG. 2).
With deviation angles of only a few degrees from the vertical, the
separation between the two holes is only of a few feet at the
bottom and of a few inches at the top. Consequently, it may be
advantageous in some formations, to start the drilling operation by
first under-reaming a single large-diameter short hole below the
casing shoe, from which the twin small-diameter drainholes are then
started, with opposite orientations. Several other available
techniques are also familiar to those skilled in the art of
drilling oil wells and may be used to achieve the same result.
Two short (ca. 60 ft long) intermediate liners (19), (20) are run
in and sealed one in each of the deviated holes. The cementing
operation uses Furan or other known heat-hardened resin/cement
slurries as seal. It may be performed in a single trip by making-up
and running-in at the end of the work string an assembly including,
as shown in FIG. 2a:
an inverted Y tubing nipple (13),
two spherical seal articulated union joints (21), one at each end
of the two branches of the inverted Y nipple,
two liner releasing tools (22) equipped with a tail pipe, one for
each intermediate liner string. Each tailpipe (23) is fitted with a
cup-type packer (24), which closes the annular space between liner
and tailpipe during cement injection and displacement behind the
liner, but opens during the reverse circulation of mud, for
cleaning after the liners have been released from their respective
latching tool. The cementing string with its two tailpipes is then
pulled out.
FIG. 2b shows in detail the spring-loaded spherical seal
articulated joint (21).
After this cementing operation, the vertical casing is thus tied-in
and sealed to each intermediate liner over an overlap interval of
about 10 ft. Entry to one of the liners is closed by a temporary
plug set by wireline and drilling of a drainhole proceeds through
the other intermediate liner, using a bit driven by a conventional
downhole motor and bent sub assembly.
After reaching total measured depth, a smaller diameter liner is
run-in, hung into the lower part of the intermediate liner and
cemented at least from the intermediate liner to the start of the
horizontal segment of the drainhole. An alternate method is to use
a coiled tubing as drill string and to abandon the bit and motor in
the hole, prior to cementing it as a liner. Gravel packing and/or
sand consolidation techniques may be used. The lower part of the
liner may be slotted and equipped with screens. Otherwise, this
part of the liner may be cemented and selectively perforated using
known perforating guns.
In view of the relatively small diameter of the liner (typically
less than 2.5 in.), a thin-gauged coiled tubing is preferred as
liner.
The annular space behind the liner may be gravel packed first by
displacement of a sand slurry, in direct circulation, followed by a
reverse circulation of the sand slurry. After cementing the upper
part of the coiled tubing liner, its lower part is mechanically
slotted by running through it, on a smaller diameter coiled tubing,
a hydraulically actuated punching tool in which multiple
articulated edge-cutting wheels (25) or punches are periodically
pressed against the inner surface of the liner to punch slots into
the coiled tubing liner, thus opening flow paths to the gravel
packed annulus. FIG. 2c shows a schematic view of the hydraulic
punching tool. Sand consolidation by injection of a suitable
thermo-setting resin as a mist in a hot gas or steam or as a
suspension or foam in a liquid may then be applied to the gravel
pack and cross-linked to stabilize it, with minimum permeability
reduction.
After removal of the temporary plug in the second intermediate
liner, the same procedures are used to drill, gravel pack, cement,
and selectively perforate the second drainhole, thus completing all
drilling and tie-in operations for both drainholes.
Well completion is achieved by make-up, run-in and set of the
production tubing string assembly, shown on FIG. 2d. It consists of
a tubing connected to:
a conventional hanger (14), an inverted Y nipple joint (13) with
each of its two lower branches equipped with a spherical seal union
joint (21) and a connector tube (26) equipped, near its end, with a
conventional packer (27) of the type which can be set hydraulically
or by wireline.
The tubing is oriented so that the tail end of each connector tube
penetrates into the upper part of one of the cemented intermediate
liners while rotating slightly around the articulation formed by
its union joint. A spreader spring, (28) linked to the upper part
of each articulated tube facilitates its insertion into the
corresponding drainhole liner.
Each of the packers is then set, to tie-in each articulated
connector tube to its corresponding intermediate liner. After
leak-testing, the tubing hanger is then set and the well head
nippled up. Again, suitable known artificial lift equipment
components may have been included in the tubing string, if it is
expected that the well will not be flowing at an economic rate
without gas-lift or pumping.
CASE 3 (DEVIATED CASED WELL)
.Iadd.Case 3 includes a special casing joint equipped with a
drillable packer and retrievable whipstock for drilling and
completion of a side-tracked hole. .Iaddend.In Case 3, a vertical
well is drilled, with its lower 50 ft deviated at the angle
required to kick-off a horizontal drainhole and oriented in the
direction selected for the drainholes. A special casing string is
made-up, run-in and cemented by known techniques into the vertical
and deviated portions of the hole. It consits of a shoe, a float
collar and a special casing joint.[.(FIG. 3).]. .Iadd., see FIGS.
3a-3c, .Iaddend.located at a depth slightly above that of the start
of the hole deviation. This casing joint presents an elliptical
window machined into the casing with a downward orientation of a
few degrees from the vertical. .[.The.]. .Iadd.As previously shown
in FIG. 1, the .Iaddend.window (1) is again plugged off with a
drillable plate (2) made, for instance, of a soft metal and shaped
to generally conform with the casing surfaces. The plug is firmly
attached to the casing by means of drillable fasteners .[.(29).]. .
Its orientation is also indicated by a vertical drillable key or
groove (30) in the casing joint inner surface at or near its lower
end.
After displacing the cement slurry behind the casing, the string is
rotated to orient the plugged window in the direction opposite to
that of the deviated portion of the hole. This is done by marking
the window direction on all the uphole joints of the casing, up to
the rig floor. After the cement has set, a whipstock drillable
packer (31) is run-in and set below the special casing joint at a
predetermined depth. A retrievable whipstock (32) is then oriented
towards the plugged window, using the casing joint's orientation
key or groove, fitted in a matching groove or key in the
whipstock's outer cylindrical surface. The oriented whipstock
presents a curved guiding surface which matches the depth, width
and orientation of the window, so that a side-tracked hole (33) of
diameter smaller than the casing ID may be kicked-off by drilling
the window plug. The hollowed curve of the whipstock also presents
a central alignment groove (34) corresponding to the lowest point
of the elliptical window (1). The base of the whipstock is
preferably equipped with a rubber cup for catching excess cement
during later operations.
After drilling out the plug and drilling a side-tracked hole
through the window, to a depth of about 60 ft, an intermediate
liner is run-in through the window and cemented by known
techniques. The upper end of the liner has been machined as shown
on FIG. 3a so as to conform with the inner edge of the window (1)
and its edge is equipped with an elliptical collar (35) made of
drillable metal, which conforms with the inner surface of the
casing at the window's edge. The outer surface of the collar is
covered with a rubber gasket or plastic sealing material (36) and
the lowest part of the collar presents a key (37) which matches the
central alignment groove (34) in the retrievable whipstock, so that
the intermediate liner end may be oriented and guided to provide a
closely fitting contact between the drillable elliptical collar and
the casing window's edge. The intermediate liner is equipped with a
cementing shoe and latched to a liner releasing tool equipped with
a tailpipe and a cup-type packer for cementing by the same
technique as in Case 2. After displacement of the cement slurry
behind the liner, a ball or plug is dropped to close the shoe and
casing mud pressure is increased to firmly apply the drillable
collar against the inner surface of the casing, while reverse
circulation is established through the tailpipe to remove any
excess cement.
After the cement has set and the cementing string has been pulled
out, the outer saw-tooth grooves .[.(38).]. of the whipstock are
latched into an overshot tool equipped with a milling edge to drill
out the elliptical collar (35) and the whipstock is pulled out. The
supporting whipstock packer (31) is also drilled out and pulled out
with the overshot milling tool, which also is equipped at its lower
end with a suitable packer-latching device. These operations leave
full openings in both the deviated casing and the side-tracked
intermediate liner. Both of them provide a relatively large
deviated casing and a slightly smaller liner to be used as the
respective starting points of two drainholes, in the same way as in
Case 2, but the drainhole diameters and that of their respective
liners may be greater than that of Cases 1 or 2.
Liner gravel packing, cementation and liner hanging respectively in
the deviated casing and in the side-tracked intermediate liner may
be done either as in Case 1 or as in Case 2, depending upon the
drainhole diameter.
Well completion is done as in Case 2, except that the tie-in of the
articulated connector tubes may be obtained either with packers, as
in Case 2 or with polished bore receptacles, and seals as in Case
1.
CASE 4 (STACKED DRAINHOLES)
In Case 4 the drainholes are stacked, one above the other, so that
the full diameter of the casing is available as a starting point
for each drainhole. Here again, a special casing joint (or joints)
now presenting two elliptical windows at two different depths and
oriented with opposite bearings, is included in the casing string
during make-up to provide the starting points of the
drainholes.
In a first embodiment (FIG. 4), the drillable plugs closing the
windows during run-in are located at the ends of telescopic liner
stubs (39) oriented downward at the kick-off angle (typically 2
degrees). Each plugged stub is later hydraulically extended into an
under-reamed portion (40) of the vertical hole filled with cement
slurry during the casing cementation, to serve as guide for a bit
driven by a downhole motor connected to a bent sub in a
conventional drilling assembly. Each of these two stubs is
supported during run-in and guided during its outwards extension by
two tubular guides or cages made of drillable metal. One of them
(41) is fixed, it is attached to the casing by drillable metal
fasteners. The other (42) is mobile and slides within the fixed
cage (41) over only half of the stub extension, while providing a
cantilevered sliding internal support to the extended stub. The
upper end of the stub is terminated by a drillable collar (35) and
gasket (37) as in Case 3.
For 7 in. OD liner stubs at a 2 degree angle in a 95/8 in. OD
casing the elliptical casing window would be 200.6 in. by 7 in. For
a 30 in. ID reamed cavity, the total stub extension length is about
286.6 in. and the stub maximum length is about 487.2 in. This is
because both ends of the stub are machined to conform with the
elliptical window, leaving in the middle a length of about 86 in.
of tubular segment. This length is sufficient to provide tie-in
both with the cemented drainhole liner and also with a connector
tube linked to the tubing. With the vertical casing and extended
stubs cemented, drilling of the extension guides and other
internals leaves two 7 in. OD stubs as pockets from which to start
drilling the drainholes, using the usual bent sub and downhole
motor assembly including the navigation system for angle build up
and directional control. The first step is to drill out the stub's
end plug. After reaching total measured depth, a liner assembly is
made-up and run-in through the stub. Gravel packing and cementing
of the uphole liner proceed as in Case 1. The upper end of the
liner is centered and hung into the lower part of the stub. It is
also terminated by the female part of a polished bore receptacle.
The work string is disconnected from the polished bore receptacle
and pulled out. The same operations are repeated for the second
drainhole, leaving the well ready for tubing completion.
The tubing completion assembly, shown on FIG. 4a, again includes a
tubing hanger (14), an inverted Y nipple joint (13), two spherical
seal union joints (21), each terminated by a connector tube stinger
equipped with chevron seals (12). A bow spring (28) between the two
stingers facilitates their entry into the stubs where they are
mated with their respective polished bore receptacle (10). After
leak testing of the connections, the tubing hanger is set and the
well head nippled up, as in Case 3. The bow spring may be
compressed during run-in and released by a suitable wireline tool
when reaching the proper insertion depth for the connector tubes.
This provision is especially useful when simultaneously connecting
more than two connector tubes. In another embodiment, shown on FIG.
4b, connection of the tubing to the drainholes is by means of
telescopic connector tubes (43). These are located in cylindrical
cavities (44), connected to the two vertical lower branches of the
inverted Y nipple joint (13) at the kick-off angle. The lower end
of each connector tube (43) is equipped with chevron seals (12),
supplemented in some cases by an end to end spherical metal/metal
seal (45). A spring (47) triggered from the surface by hydraulic or
wireline means strongly applies the extended connector tube's
spherical end against a corresponding spherical cavity forming the
bottom of the polished bore receptacle (10) to provide this
metal/metal seal. In FIG. 4c, the connector tube is locked into its
extended position, but may be retracted inside the cylinder body by
shearing off the latch pins (46) with a wireline tool as shown in
FIG. 4d, when it is necessary to disconnect and pull out the tubing
for a well work-over. The upper end of the body (44) is equipped
with dogs which bite into the inner surface of the casing when the
telescopic connector tube is fully extended and pressed against the
bottom of the polished bore receptacle. It will be apparent to
those skilled in the art that this is only one of many possible
ways of achieving both a spring-loaded metal/metal seal and
anchoring in the extended position of the telescopic tube while
providing means for its eventual retraction and pull out. The
invention is not limited to the example described herein.
In yet another embodiment, the casing includes two special joints
of the type used in Case 3, located one above the other, separated
by an interval sufficient for setting a packer and the two plugged
windows oriented in opposite directions. Again, as in Case 3, a
drillable whipstock packer is set below one of the windows. The
retrievable whipstock is latched into the packer and drilling of
the window and side-tracked hole proceeds. A short intermediate
liner, as in Case 3, is run-in through the window and cemented. The
procedure, repeated for both windows, leaves two side-tracked
intermediate liners from which the drainholes are drilled, and
their liners are hung and cemented. After drilling out the
drillable elliptical collar of each cemented intermediate liner,
the entire casing space is available for installing the tubing
completion assembly.
The previous embodiments which leave full access to the stacked
drainholes also allow to drill, gravel-pack, and tie-in any number
of drainholes, equipped with cemented liners, one above the other,
by using as many stubs or intermediate liners as there are
drainholes.
The commingled production from all drainholes may be discharged
into an oil sump formed by the casing below a production packer and
pumped to the surface through a single production tubing. The pump
location in the tubing may be above the packer, or below it in a
tailpipe tubing extension. With such a simple tubing completion
assembly, the access into each of the drainholes of logging or
cleaning tools is obtained by means of a suitable kick-over tool of
known design.
The tubing completion assembly may also be the same as in Cases 2
and 3, which provide a continuous path from the surface to each of
two twin drainholes, and greater operational flexibility.
The types of tubing completion assemblies including telescopic
connector tubes or articulated connector tubes, described above for
two stacked drainholes, are also applicable to more than two
stacked drainholes. If the drainholes are grouped by pairs,
connected to a single production tubing, the number of parallel
tubes in the casing at any depth is reduced to only three, as shown
on FIG. 4e. These are:
the two tubings connected to the lower branches of the inverted Y
nipple joint (13), for a given pair of drainholes,
the production tubing extension (48) leading to the other drainhole
pairs below the first one.
This number may be increased to four if the hydraulic or jet pump
is located below the top pair of drainholes and if the tubing
carrying the power fluid to the pump is parallel with the
production tubing, but the number of possible stacked drainholes,
which is only limited by the casing length, may be much
greater.
CASE 5 (ARTIFICIAL LIFT)
In all previous cases, it was assumed that reservoir pressure and
produced gas expansion are sufficient to convey the production
stream to the surface, or at least up the curved portion of each
drainhole (up to 500 ft high) without excessive reduction of the
total pressure draw down, so that a single artificial lift system
providing suction at the base of the production tubing can be used
for both drainholes. This may be a conventional gas-lift valve
supplied with compressed gas through the casing/tubing annulus.
Conversely, the production stream may be conveyed to the surface
through the annulus while lift gas is supplied through the tubing.
In that event, a packer must be added to the tubing hanger, a
diverter valve must be included in the tubing above the packer to
convey the production stream to the annulus and a plug must be
located in the tubing between the open diverter valve and the
bottom gas-lift valve.
Similarly, the commingled production stream from both drainholes
may be pumped to the surface through the tubing or through the
annulus using known types of pumps. These can be mechanically
actuated by sucking rods, by rotating rods (progressive cavity
pumps) or they can be actuated hydraulically. Jet pumps may also be
used as well as electrically driven submersible pumps. Pump
selection criteria and the importance of an optimum depth of the
pump in the well are well known from those skilled in the art. The
pump may be anchored either in the tubing or in the annulus,
depending upon reservoir and well conditions, including the need to
handle gas or sand production.
It is one of the main advantages of connecting two or more
drainholes to a single vertical well to allow the possibilty of
using a single pump (49) as in FIG. 5a for all the drainholes, thus
reducing capital and operating costs of pumping the production
stream.
It will be shown later that this possibility is, however, limited
in the case of some under-pressured reservoirs. Well completion
equipment and novel assembly procedures have been developed to
extend the possibility of using a single pump by locating it, as in
FIG. 5b, below the drainholes kick-off points. Finally, special
equipment and methods are described for the installation and use of
a pump in each drainhole, if necessary, as in FIG. 5c.
These considerations on artificial lift are equally applicable to
new wells and to the re-entry into an existing casing, to vertical
as well as to deviated cased wells.
CASE 6 (FLOW THROUGH A SYPHON)
In under-pressured reservoirs containing low GOR oil, reservoir
energy may be insufficient to convey the production stream up to a
pump or gas lift valve located above the kick-off points of the
drainholes. The difference in elevation between such a pump and the
fluids entry points in the horizontal part of the drainholes is
greater than the drainholes radius of curvature, which may be up to
500 ft. In addition, there are significant friction pressure drops
through the horizontal and curved portions of small-diameter
liners, which may reduce the calculated net flowing fluid head at
the pump .[.(49).]. inlet to a value below the required minimum
NPSH of the pump. This indicates that cavitation is likely to occur
in the pump, with highly detrimental erosion effects and a reduced
flowrate. To alleviate this problem, flow from each drainhole may
be directed to an oil sump (50), with the pump taking suction at or
near the bottom of the sump. .Iadd.See FIG. 6b. .Iaddend.The top of
the sump is closed by a packer (51) a short distance above the
highest kick-off point. It constitutes the apex of a kind of syphon
(see FIG. .[.6.]. .Iadd.6b.Iaddend.) for each drainhole. For very
low GOR oil, frequently present in under-pressured mature
reservoirs, the flowing pressure at that point may still be well
above the bubble point of the production stream, so that the risk
of cavitation and break-up of the de-celerating liquid stream at
that point is much less than it would be in a pump at the same
location. The flowing pressure at the apex, plus the liquid head in
the sump, provide a pump suction pressure exceeding the minimum
NPSH required, thus eliminating the risk of cavitation in the
bottom pump.
Instead of a pump, an intermittent flow gas lift system may also be
used for the same purpose. In this known system, a gas piston lifts
an oil slug up the tubing after the standing valve at the bottom
has closed. This is equivalent to a beam pump, but more tolerant of
sand production.
The drilling and tie-in equipment and procedures are the same as in
Cases 1, 2, and 4, except that a sump is drilled and cased
vertically below the lowest kick-off point. In Cases 1 and 4, that
sump may be created by placing the special casing joint well above
the casing shoe.
For the Case 1 configuration, the casing joint shown previously on
FIG. 1 is modified as follows:
1) The threaded small hole (7) in the bottom twin whipstock of Case
1 is extended below with a tailpipe which is used first to bring
the cement slurry to the shoe, during casing cementation. The
bottom part of the tail pipe also includes a pump latching nipple
joint.
The threaded small hole is also extended above with the female part
of a polished bore receptacle to later receive a tubing stinger
equipped with chevron seals, so as to extend the tailpipe upwards
by a production tubing through a sealing connection.
2) The smooth bore second small hole is drilled through the bottom
whipstock, to provide a flow path for the produced fluids into the
oil sump below it. It may be supplemented with other small holes to
provide a sufficiently large cross section for the low velocity
liquid flow in the downward leg of the syphon.
The polished bore receptacles terminating the cemented drainhole
liners may be omitted, the large vertical holes providing a natural
guide for inserting logging or cleaning tools into the liners.
In addition, the tubing completion assembly is modified to consist
of:
a) a production tubing,
b) a dual string production packer, with a retrievable plug in its
short string. The main purpose of that string is to provide
eventual access to the sump for inserting logging or cleaning tools
into the drainholes below the packer. A secondary purpose of the
short string is to provide a pump by-pass flow path which may be
periodically opened to let any gas accumulation below the packer
escape upwards by buoyancy, while re-filling the sump with
de-gassed liquid from above the packer to maintain continuity of
the liquid stream through the syphon. Periodic gas purging
operations may be automatically controlled from the surface. For
that purpose, the retrievable plug in the short string is in fact a
conventional wireline retrievable subsurface safety valve (FIG.
6a), in a normally closed position but operated by known hydraulic
or electrical means whenever the presence of a small gas cap is
detected below the packer. Detection means may be direct, using
known liquid level sensors or indirect, by continuous monitoring of
the pump efficiency. Continuous gas purging may otherwise be
obtained by using a wireline plug including a permselective
membrane (52), which allows continuous diffusional gas migration
upwards, under a gas pressure gradient across the membrane, created
by a retrievable venturi (53), located at the exit of the
production tubing into the larger cross section of the casing
annular space. The membrane also prevents liquid flow downwards
(see FIG. 6b). In this system, the energy supplied to the pump
serves three purposes:
1) to bring the gas-free liquid stream from the pump to a point
above the packer, and
2) to operate a sort of gas ejector pump to re-mix the produced gas
with the liquid stream in the casing/tubing annulus, above the
packer.
3) to lift the mixed liquid and gas stream up the casing/tubing
annulus to the separator.
Suitable permselective plug materials include, but are not limited
to: charcoal, agglomerated carbon black, compressed powdered
mineral adsorbents, asbestos felt, etc. . .
The long string, in the dual string packer, extends below the
packer with a stinger equipped with chevron seals which is stabbed
into the polished bore receptacle threaded into the top of the
small hole (7) of the modified novel casing joint, thus providing a
connection from the production tubing to the tailpipe, in which a
pump is set.
A rod string or a power fluid tubing string is then inserted from
the surface within the production tubing and connected to the
pump.
In this configuration, the flow from both drainholes is discharged
into the sump below the packer and flows downwards through one or
several holes in the whipstock, to reach the pump inlet at the
bottom of the tailpipe, to be discharged, at a higher pressure,
into the production tubing and from it to the casing annulus
leading to the surface.
In cases where the cased well effluent flows into a very low
pressure separator, the packer may be omitted if the production
tubing extends to the surface, so that any gas coming out of
solution at the apex of the syphon freely accumulates in the
casing/tubing annulus, forming a low pressure gas cap extending up
to the casing head. Gas purging of the casing to maintain the gas
cap at the required low pressure is then accomplished through a
conventional gas re-mixing valve at the surface, upstream of the
low pressure separator inlet.
In the configuration of Case 2, after drilling and tie-in of the
twin drainholes, a third hole is drilled vertically and its liner
is cemented to provide the oil sump. The tubing completion assembly
now consists only of a production tubing, a dual string packer with
its short string again closed with a retrievable gas-purging plug
and the production tubing and pump extending below the packer for
insertion into the sump.
In the configuration of Case 4, the casing now extends below the
special joint (or joints) to form the oil sump. The tubing
completion assembly is the same as above: a production tubing, a
dual string packer with its short string temporarily plugged off
and the production tubing extending below the packer, with a bottom
pump.
CASE 7 (DUAL PUMPING)
In low pressure reservoirs containing relatively high GOR oil, the
risk of cavitation at the apex of the syphon may be too great, so
that the use of a syphon is no longer possible. In some very
heterogeneous reservoirs, it is also possible that the productivity
indices of the two drainholes are widely different. In those cases,
it is preferable to equip each drainhole with its own pump sized to
maximize total oil production. The same is true if one of the
drainholes is more prone to gas coning or water coning than the
other.
Progressive cavity pumps driven by rotating rods and hydraulic or
jet pumps driven by power fluid operate satisfactorily in highly
deviated wells. A pump anchor nipple joint is included in the liner
string, at the selected depth in the curved portion of each
drainhole. The production tubing diameter must be increased to
provide space inside it for the power fluid tubing strings or for
the rotating rod strings. Another alternative is to insert the
power fluid tubing or the rotating rod string into the drainhole
liner through a side entry in each of the lower branches of the
inverted Y nipple joint. In that case (see FIG. 7), a short conduit
(54) leads from the top of the tubing hanger (or packer) to the
side entry point to facilitate the insertion of the power fluid
tubing or rod string from the annulus space into the drainhole
liner. This requires corresponding modifications of the Y nipple
joint (13) and of the tubing hanger (14), or packer (51).
CASE 8 ("HUFF AND PUFF" MODE OF OPERATION)
In heavy oil reservoirs, it is advantageous to operate the twin
drainholes in sequential "huff and puff" steam injection, in which
one drainhole is under injection while the other is under
production. For surface-generated steam, the production tubing may
be replaced by an insulated steam tubing. A downhole three-way
retrievable valve of the type described and claimed in U.S. Pat.
No. 5,052,482 is required in each lower tubing branch below the
inverted Y nipple joint. This is done (FIG. 8 and 8a) by adding a
valve nipple joint (55) in each branch with its control hydraulic
line (56), strapped on the outer surface of the insulated steam
tubing (57). In its axial full opening position, the valve conveys
steam from the tubing to the corresponding drainhole. In its side
opening position, the valve discharges the production stream from
the drainhole liner into the casing annulus space. From there, the
produced fluid may be pumped to the surface or gas-lifted.
The same well completion type is also applicable to reservoirs
subjected to "huff and puff" injection of solvent gases, such as
CO2, which are known to also reduce oil viscosity, but to a lesser
degree than steam injection. In such cases, artificial lift of the
produced fluids may be unnecessary.
If the reservoir pressure and/or produced GOR are sufficient to
bring the oil up to the kick-off point of each drainhole, the pump
is hung in the annulus casing/steam tubing, above the kick-off
points.
If, however, the heavy oil reservoir is also under-pressured, as,
for instance in California's Midway Sunset field, the pump may be
located at the bottom of an oil sump as in Case 6 or it may be
located within each drainhole liner as in Case 7. The tubing
completion will be modified accordingly, as will be shown later.
The type of pump used in that case must allow easy disconnection
from its seat, when the drainhole is switched from the production
mode to the injection mode. For this reason, jet pumps, hydraulic
pumps and progressive cavity pumps are preferred in that case.
For under-pressured heavy oil reservoirs in which the drainhole
production flows through a syphon (Case 6), the tubing completion
assembly in which telescopic or articulated connector tubes are
used to connect the steam tubing to the drainholes, the packer may
be a three or four string packer, depending upon the location of
the inverted Y nipple joint with respect to the packer. With the Y
nipple joint below the packer, only three strings are connected to
the bottom face of the packer:the upper branch of the Y, the
production tubing extending into the oil sump and the short string
with its retrievable plug. To increase the packer depth, and,
correspondingly that of the apex of the syphon, the inverted Y
nipple joint is located above a four string packer, in which two of
the strings are connected to the lower branches of the inverted Y,
the third string is connected to the production tubing extending
into the oil sump and the fourth string is the temporarily
plugged-off pump by-pass. The production tubing may end just above
the packer without reaching the surface, if the production stream
flows through the casing/steam tubing annulus.
With steam generated downhole, together with permanent gases (CH4,
H2) using the equipment described and claimed in U.S. Pat. No.
5,052,482, it is preferable to inject the steam and gases through
the side opening of the downhole three-way valve into one
drainhole, while conveying the production stream from the other
drainhole to the central production tubing through the axial full
opening of its downhole valve. The equipment and procedures for
drilling, gravel packing, cementation, tie-in of multiple
drainholes and for their tubing completion, previously described,
are also applicable with some minor modifications which will be
indicated later.
It will be apparent to those skilled in the art of oil well design
that it is not possible to cover all the situations encountered in
all reservoirs, because of their infinite diversity, but that the
equipment and procedures described herein lend themselves to a very
large number of combinations and permutations, which are capable of
addressing most situations in which multiple horizontal drainholes
may be advantageously used. Such combinations and permutations,
which are obvious to those skilled in the art, do not detract from
the spirit of the present invention and are included in it.
RE-ENTRY INTO AN EXISTING CASED WELL (WORK-OVER)
The cost of drilling and cementing the vertical cased well is a
large portion of the total cost of a well presenting the general
configurations described above. Re-entry into an existing cased
well for drilling, gravel-packing, cementation and liner tie-in of
multiple drainholes is a cost-effective way of increasing
productivity.
If the existing cased well already presents a suitable deviation
for the use of Case 3 procedures, the absence of a pre-established
window in the casing string may be remedied by milling a side-track
window using available tapered mills guided by the novel
retrievable whipstock latched in a drillable whipstock packer set
slightly above the deviation depth. The procedures and equipment,
other than the special casing joint, are then the same as in Case
3, provided that known downhole orientation surveying methods are
used to remedy the absence of pre-determined alignment keys or
grooves in the casing.
In most fields, however, the existing casing will be essentially
vertical, so Cases 1, 2, 4, 6, 7 and 8 will be more relevant.
CASE 1a (TWIN WHIPSTOCK INSERT)
The procedures of Case 1 may be used if a twin whipstock insert of
diameter less than the drift diameter of the existing casing is
run-in, hung in the casing and cemented at the selected depth above
a plug permanently set in the casing. The oriented insert (FIG. 9),
is held by a known packer/hanger (58) set hydraulically or by
wireline tools. The hanger's slips are preferably located in the
lower part of the insert below the drainholes so as to avoid any
interference with them. Here again, elliptical windows will be
milled in the existing casing using tapered mills guided by the
twin whipstock (3).
In another embodiment (FIG. 9a), the hanger slips are located above
the twin whipstock, so that the casing may be entirely milled over
the depth interval of the windows, covered by the twin whipstock
(3).
CASE 2a (TWIN DEVIATED HOLES THROUGH MILLED CASING INTERVAL)
The plugged casing is milled over an interval sufficient to drill
the sidetracked starting holes of Case 2 (FIG. 9a). Starting of the
holes with a bent sub/downhole motor assembly may again be
facilitated by first under-reaming that interval. Following these
preliminary operations, the work proceeds as in Case 2, using the
same equipment, tools and procedures. It will be apparent to those
skilled in the art that the use of coiled tubings as liners and
their subsequent in-situ mechanical slotting are equally applicable
to any other case.
CASE 4a (STACKED DRAINHOLES IN MILLED CASING)
The existing casing is milled out and the hole is under-reamed to a
diameter of about 30 in. over the depth intervals corresponding
respectively to each drainhole start. A casing patch is then run-in
and fastened to the casing by means of hanger slips (59) above and
below the lower milled-out interval. This embodiment is shown on
FIG. 10.
The casing patch presents close similarities with the special
casing joint of Case 4, except that its outside diameter must be
less than the drift diameter of the existing casing and that its
outer surface, opposite the plugged telescopic stub (39) is now
covered by an external rubber packer (60), which, when inflated
with cement slurry entirely fills the reamed cavity. A suitable
device including shearing disks also allows to inject the cement
slurry in the two overlap (61) annular spaces between casing and
casing patch hangers (14) above and below the cement-filled
bladder, during the hydraulically-controlled extension of the stub
into the slurry filling the rubber bladder. As in Case 4, the stub
(39) is supported and guided during its extension by a fixed
guiding cage (41) and a mobile inner guide (42) which penetrates
only half way outside the casing. Added support and guidance is
also provided by several cables (62) attached to the rubber wall
and pulled under hydraulically-controlled tension from a drillable
drum (63) through inclined holes (64) in the casing patch wall, at
various locations around the machined edge of the elliptical window
(1) through which the stub is extended.
With the rubber bladder fully inflated and pressed against the
reamed cavity wall (40), the taught cables provide additional
guidance and support to the stub (39) in its fully extended
position. The drillable guides and the tail-end drillable collar
(35) of the stub are drilled-out after the cement has set. This
restores the vertical cased well to a diameter equal to that of the
casing patch drift diameter.
A second casing patch is run-in, oriented, hung and cemented, with
full extension of the second stub into the upper reamed interval,
thus providing the start for the second drainhole.
Drilling, gravel packing, liner hanging and cementing procedures
for both drainholes are identical with those of Case 4. The tubing
completion assembly equipment and procedures are also the same.
The embodiment of Case 4 in which tie-in of the drainholes is by
means of intermediate liners inserted and cemented in side-tracked
holes drilled through elliptical windows by guiding the bit with a
retrievable whipstock set in a drillable whipstock packer may also
be adapted. The absence of pre-established windows plugged with
drillable metal may be remedied in several ways.
The first method calls for milling each elliptical window into the
existing casing with a tapered mill guided by a suitable
retrievable whipstock. The whipstock required to mill the lowest
window and to drill and complete the lowest drainhole is set and
oriented in a packer, as in Case 2a. The whipstocks used to mill
the other windows may then be stacked, each into the adjacent lower
whipstock and oriented with respect to it by inserting into it
multiple prongs, in a way similar to that used for the top
whipstock of Case 1. The order in which stacked holes are drilled
and completed may be either from the bottom up or from the top
down. In an alternative procedure, the supporting packer is
released after completion of each hole or drainhole and
successively reset and re-oriented at a different depth for each of
the other holes or drainholes. Again the whipstocks are handled by
appropriate overshot latching tools, preferably equipped with end
milling cutters to remove any protruding obstruction.
The second method again uses a special casing patch, shown on FIG.
11, with an open elliptical window (65). The casing patch is set in
the casing by slips above and below an interval over which the
casing was milled out. The casing patch includes a pre-oriented
whipstock packer (31) in its lower part. It may also be run-in with
the retrievable whipstock (32) already in place. After setting the
hanger slips (14), the drilling bit and drill string, guided by the
whipstock through the open elliptical window, are used to drill the
side-tracked hole and operations continue as in Case 4.
This is the preferred embodiment for deep wells, because it
provides the largest diameter drainholes, for the minimum casing
diameter, provided that cementation problems are not likely in the
type of formation existing at the drainholes kick-off points.
CASE 6a (FLOW THROUGH A SYPHON IN EXISTING CASING)
The existing casing, with its perforations plugged off, constitutes
the oil sump required as the downwards leg of the syphon (see FIG.
11). The production tubing must extend to the bottom of the sump,
where the pump is located, as in Case 6.
Drilling, gravel packing, tie-in and cementing of the drainholes
may be obtained by any of the methods described in Cases 1a, 2a,
and 4a.
For instance, the twin whipstock used in Case la includes a
flow-through hole connected to a tail pipe (66) equipped with a
pump receiver nipple joint (67) at the bottom. The upper face of
the hole also serves to receive one of the alignment pins (8) of
the retrievable top whipstock. This hole is also terminated by a
polished bore receptacle (10) in which the production tubing
stinger, equipped with chevron seals, will be stabbed prior to
setting the packer, as in Case 6.
The only difference is that a casing patch is now used instead of a
special casing joint. Hangers (14) are used instead of threaded
connections.
The tubing completion assembly and its installation procedures are
identical with those of Case 6.
Using the drainhole drilling and tie-in method of Case 2a, the only
modification required is the drilling of a vertical hole through
the cement and drillable casing plug after cementation of the two
intermediate liners, to provide access into the oil sump through
which the production tubing will be inserted. The tubing completion
assembly of Case 6 is simplified because the tail pipe terminated
with its pump anchoring nipple joint is threaded directly into the
bottom face of the dual string packer.
The drainhole drilling and tie-in procedures of Case 4a remain
unchanged, but the tubing completion assembly is the same as in
Case 6.
CASE 7a (DUAL PUMPING IN WORK-OVER WELL)
The production tubing assembly is the same as in Case 7. It can be
used with any of the well configurations resulting from the
drainhole drilling and tie-in methods of Cases 1a, 2a and 4a.
CASE 8a ("HUFF AND PUFF" MODE OF OPERATION IN WORK-OVER WELL)
The tubing completion assembly is similar to that in Case 8. (see
FIG. 12). In principle, all the drilling and tie-in methods of
Cases 1a, 2a and 4a are applicable, provided that the inside
diameter of the insert or casing patch is sufficient to accomodate
two drainhole tubing strings below the packer, when the pump is
located above the packer, and three tubing strings when pumping is
through a syphon.
With the two drainholes operated in "huff and puff" known downhole
wireline retrievable three-way valves are also included in the
tubings in a valve nipple joint. The valve nipple joints (55),
connected to the lower branches of the Y are then below the hanger,
so their hydraulic control lines (56) also pass through and extend
below the hanger (14).
If dual pumps located in the drainholes are used (see FIG. 13), the
one located in the injection drainhole is pulled out of its seat
(e. g. a progressive cavity pump) or pumped out (e. g. a
casing-free type jet pump) prior to switching the drainhole to the
injection mode. Each type of pump is actuated through its own side
entry conduit The side entry of the rod string or that of the power
fluid tubing is always located below the valve nipple, so as not to
interfere with the valve operation while unseating the pump.
The pumped production stream in the annulus between liner and rod
string is discharged through the side port of the valve into the
casing/injection tubing annulus. A casing packer is no longer
required, but a 3 or 4 string hanger (69) is used instead. When the
Y nipple joint is below the hanger, three strings are required,
respectively connected to:--the upper branch of the Y,
both of the side-entry conduits (68) through which the rotating rod
strings (70) driving progressive cavity pumps are inserted.
When hydraulic or jet pumps are used, the power fluid, pumped from
the surface through a single tubing stabbed into a receptacle above
the hanger is also fed to the pumps in all drainhole liners by
means of twin conduits leading respectively to each of the two side
entry points. It is through those conduits that smaller power fluid
tubings are inserted into the drainhole liners, with a pump linked
to each of them. The production stream from each drainhole, mixed
with the spent power fluid is then discharged into the annulus
between liner and power fluid tubing to ultimately reach the casing
annulus where it is commingled with that of the other drainholes
and conveyed to the surface.
When the the Y nipple joint is above the hanger, the valve nipples
may then also be above the hanger, together with their control
lines. On the other hand, the two lower branches of the Y and the
corresponding two side entry conduits require that a 4 string
hanger be used.
In all cases, however, the tubing completion assembly may be run-in
and set in the casing in a single trip, even in the most complex
configurations of Cases 8 or 8a.
* * * * *