U.S. patent application number 13/004237 was filed with the patent office on 2011-07-14 for downhole hydraulic coupling assembly.
This patent application is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to Michael Hui Du, Gary Rytlewski, David Wei Wang.
Application Number | 20110168406 13/004237 |
Document ID | / |
Family ID | 44257626 |
Filed Date | 2011-07-14 |
United States Patent
Application |
20110168406 |
Kind Code |
A1 |
Du; Michael Hui ; et
al. |
July 14, 2011 |
DOWNHOLE HYDRAULIC COUPLING ASSEMBLY
Abstract
A completions system utilizing a unique hydraulic coupling. The
system includes an upper completion stinger configured for coupling
to a lower completion tubular. Both the stinger and the tubular are
outfitted with hydraulic lines therethrough. Thus, as the stinger
is coupled to the tubular, hydraulic lines are also coupled.
However, the termination of each line is sealingly covered by a
slidable sleeve in advance of attaining the coupling between the
stinger and tubular. Therefore, the lines are protected from
contamination during potentially significant periods of well
deployment that may occur in advance of completed coupling and
system installation. Furthermore, the manner of hydraulic coupling
between the stinger and tubular reduces the likelihood of damage to
the hydraulic lines during the installation process.
Inventors: |
Du; Michael Hui; (Pearland,
TX) ; Rytlewski; Gary; (League City, TX) ;
Wang; David Wei; (Sugar Land, TX) |
Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION
Sugar Land
TX
|
Family ID: |
44257626 |
Appl. No.: |
13/004237 |
Filed: |
January 11, 2011 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61294330 |
Jan 12, 2010 |
|
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|
Current U.S.
Class: |
166/380 ;
166/77.51; 166/85.5 |
Current CPC
Class: |
E21B 19/16 20130101;
E21B 17/023 20130101 |
Class at
Publication: |
166/380 ;
166/77.51; 166/85.5 |
International
Class: |
E21B 19/16 20060101
E21B019/16; E21B 19/18 20060101 E21B019/18; E21B 19/00 20060101
E21B019/00 |
Claims
1. A downhole hydraulic completions assembly comprising: an upper
completion stinger with a hydraulic stinger line therethrough, the
stinger line terminating at a passage isolated by a slidable
stinger sleeve relative a main body of said stinger; and a lower
completion tubular with a hydraulic tubular line therethrough, the
tubular line terminating at a port isolated by a slidable tubular
sleeve relative a main body of said tubular, the passage and the
port for hydraulic coupling therebetween upon physical coupling of
said stinger to said tubular.
2. The assembly of claim 1 wherein the physical coupling provides
shifting of the sleeves to expose the passage to the port.
3. The assembly of claim 1 wherein said upper completion stinger
further comprises a mule shoe with collets for interlocking with a
surface of the tubular sleeve.
4. The assembly of claim 1 wherein at least one of said passage and
said port is of a circumferential configuration.
5. The assembly of claim 4 wherein the stinger line is a first
hydraulic line of said stinger, the circumferential passage
configured to accommodate a second hydraulic line of said
stinger.
6. The assembly of claim 4 wherein the tubular line is a first
hydraulic line of said tubular, the circumferential port configured
to accommodate a second hydraulic line of said tubular.
7. The assembly of claim 1 wherein the stinger sleeve is disposed
about the main body of said stinger and the tubular sleeve is
disposed adjacent an inner wall of said tubular.
8. The assembly of claim 7 wherein the tubular sleeve is equipped
with a scraper ring for interfacing the inner wall.
9. The assembly of claim 1 wherein the stinger sleeve is interiorly
disposed relative the main body of said stinger and the tubular
sleeve is disposed about a main body of said tubular.
10. A hydraulically outfitted downhole completions system
comprising: upper completions disposed in a cased portion of a
well, said upper completions having a stinger with a hydraulic line
therethrough and terminating at a passage isolated by a slidable
sleeve relative a main body of the stinger; and lower completions
disposed in an at least partially open portion of the well adjacent
the cased portion, said lower completions having a tubular coupling
to the stinger and equipped with a hydraulic line therethrough, the
line of the tubular terminating at a port isolated by a slidable
sleeve relative a main body of the tubular.
11. The system of claim 10 wherein the coupling aligns the passage
and the port for hydraulic communication there between.
12. The system of claim 11 wherein the coupling provides shifting
of the sleeves to expose the passage to the port for the
communication.
13. The system of claim 10 wherein said upper completions further
comprises production tubing coupled to the stinger to provide a
conduit for production fluid flow to a surface of an oilfield
adjacent the well.
14. The system of claim 13 wherein said lower completions further
comprises production intake equipment in fluid communication with
the hydraulic line through the tubular, the system further
comprising chemical injection equipment disposed at the oilfield
surface and hydraulically coupled to the hydraulic line through the
tubular via the hydraulic line through the stinger.
15. A method comprising: installing a lower completion tubular in a
well, the tubular accommodating a hydraulic line through a main
body thereof and a slidable sleeve for sealing off a port at a
terminal end of the line; and deploying an upper completion stinger
to a location adjacently uphole of the tubular, the stinger
accommodating a hydraulic line through a main body thereof and a
slidable sleeve for sealing off a passage at a terminal end of the
line through the stinger.
16. The method of claim 15 further comprising: initiating coupling
of the stinger to the tubular; and maintaining the sealing with the
sleeves during said initiating.
17. The method of claim 16 further comprising: aligning the passage
with the port; and shifting the sleeves away from the passage and
the port during said aligning to allow for hydraulic coupling
between the lines.
18. The method of claim 17 further comprising performing a
hydraulically actuated application in the well through the
lines.
19. The method of claim 18 wherein the application is one of
chemical injection and operation of a hydraulically actuatable
downhole tool.
20. The method of claim 17 further comprising: decoupling the
stinger from the tubular: resealing the passage and the port with
the sleeves during the decoupling; and withdrawing the stinger from
the well.
Description
PRIORITY CLAIM/CROSS REFERENCE TO RELATED APPLICATION(S)
[0001] This Patent Document claims priority under 35 U.S.C.
.sctn.119 to U.S. Provisional App. Ser. No. 61/294,330, filed on
Jan. 12, 2010, and entitled, "Downhole Equipment and Method of Use"
incorporated herein by reference in its entirety. This Patent
Document also claims priority under 35 U.S.C. .sctn.120 to U.S.
patent application Ser. No. 12/056,643, filed on Mar. 27, 2008,
entitled, "System and Method for Engaging Well Equipment in a
Wellbore" and to U.S. patent application Ser. No. 11/850,243, filed
on Sep. 5, 2007, entitled, "System and Method for Engaging
Completions in a Wellbore", both of which are also incorporated
herein by reference in their entireties.
FIELD
[0002] Embodiments described relate to tools and techniques for
coupling hydraulic lines to one another. In particular, embodiments
of hydraulic line running through walls of downhole tubing segments
are detailed.
BACKGROUND
[0003] Exploring, drilling and completing hydrocarbon wells are
generally complicated, time consuming and ultimately very expensive
endeavors. As a result, over the years increased attention has been
paid to monitoring and maintaining the health of such wells.
Significant premiums are placed on maximizing the total hydrocarbon
recovery, recovery rate, and extending the overall life of the well
as much as possible. Thus, logging applications for monitoring of
well conditions play a significant role in the life of the well.
Similarly, significant importance is placed on well intervention
applications, such as clean-out techniques which may be utilized to
remove debris from the well so as to ensure unobstructed
hydrocarbon recovery.
[0004] As with monitoring and interventional applications, the
initial well design and architecture also plays a significant role
in maximizing efficient recovery from the well. For example, most
of the well is generally defined by a smooth steel casing that is
configured for the rapid uphole transfer of hydrocarbons and other
fluids from a formation. However, a buildup of irregular occlusive
scale, wax and other debris may occur at the inner surface of the
casing or tubing and other architecture restricting flow
there-through. Such debris may even form over perforations in the
casing, screen, or slotted pipe thereby also hampering hydrocarbon
flow into the main borehole of the well from the surrounding
formation.
[0005] In order to address scale buildup as noted above, a variety
of interventional techniques are available. For example, an
inexpensive gravity fed wireline technique may be employed wherein
chemical cleaners such as hydrochloric acid are delivered to
downhole sites of buildup. Alternatively, for more sizeable
buildups, particularly of calcium carbonate, barium sulfate and
other crystalline scale deposits, less passive techniques may be
utilized. These may include the use of explosive percussion, impact
bits, and milling. Further, for less hazardous and more complete
clean-outs, techniques employing mechanical fluid jetting tools are
generally the most common form of interventions. Such tools may be
conveyed into the well via coiled tubing and include a head for
jetting pressurized fluids, chemicals, solutions, beads, particles,
or penetrants toward the well wall in order to fracture and
dislodge scale and other debris.
[0006] Unfortunately, running interventional applications involves
the delivery of footspace eating clean-out equipment to the
oilfield and requires that production from the well be halted. So,
for example, a day's time and upwards of several hundred thousand
dollars may be spent on rig-up, running and disengaging coiled
tubing clean-out equipment, not to mention lost production time.
Therefore, as alluded to above, the initial well design and
architecture may call for the completions structure to be outfitted
with hydraulics capable of accommodating a circulating chemical
injection system. This is particularly the case where the
likelihood of buildup is accounted for up front, as is often the
case in deep water wells. Regardless, with such systems in place, a
metered amount of chemical mixture, such as the above noted
hydrochloric acid mix, may be near continuously circulated downhole
from the oilfield surface. That is, an injection line may be run
from surface to downhole points of interest for delivery of
chemical mix thereat. Upon delivery, the mix may be produced along
with the ongoing production of the well. Thus, the need to halt
production or run expensive interventions in order to address
undesirable buildup is eliminated.
[0007] The above noted chemical injection hydraulics may be
provided through a production tubing wall or other available
structure. However, the production tubing may be provided in
segmented form. As each tubing segment is installed, a challenge is
presented in physically coupling the segment to a previously
installed segment. In a well where the tubing is to accommodate a
hydraulic line as noted above, the challenge of coupling the
segments is exacerbated by the requirement of ensuring that
hydraulic terminations for each of the segments are also mated with
one another during the coupling. In this way, a continuous
hydraulic line may be incorporated throughout the completed tubing
wall. Indeed, even where the tubing is not segmented, its coupling
to an open lower completion may involve mating terminations should
the lower completion be outfitted with a chemical injection
line.
[0008] Unfortunately, the mating of hydraulic terminations slows
down the installation process. Perhaps more significantly, however,
the likelihood of improperly mated hydraulic terminations during
installation is substantial. Even though the hydraulic terminations
are generally high dollar, robust fittings, they are often damaged
during in the installation process. Thus, dollars are lost to
replacement of the terminations and even more so to the time lost
in the form of the added runs now required for installation or
re-installation of the tubing segments with the damaged
terminations.
[0009] Even more problematic than damaged terminations requiring
replacement is the high likelihood of operators being unaware of
damaged terminations in the first place. That is to say, improperly
connected terminations may not be learned of during the
installation process. Thus, where a fully functional hydraulic line
is essential to well operations, the results may be catastrophic,
particularly where the line is accommodated through well casing as
opposed to production tubing. To date, efforts have been directed
at aiding segment orientation during installation through the use
of certain swivel devices that may improve the likelihood of proper
hydraulic termination mating to a degree. However, there remains no
manner of guaranteeing that one termination is perfectly aligned
with another for mating during installation of completions
structure.
SUMMARY
[0010] A completions assembly is provided which includes an upper
completions stinger for connection to a lower completion tubular.
Both the tubular and the stinger are outfitted with hydraulic lines
that are configured for coupling to one another as the noted
connection between the tubular and stinger. Additionally, the line
of the stinger terminates at a seal that is isolated by a first
slidable sleeve relative the stinger. Similarly, the line of the
tubular terminates at a port that is isolated by a slidable sleeve
relative the tubular. Thus, the lines may be protected by the
sleeves until the connection is made.
BRIEF DESCRIPTION OF THE DRAWINGS
[0011] FIG. 1 is a front view of an embodiment of a completions
assembly with hydraulic lines coupled through separate stinger and
tubular completion segments.
[0012] FIG. 2 is an overview of an oilfield with a well
accommodating the completions assembly of FIG. 1 therein.
[0013] FIG. 3A is a schematic view of an upper completion stinger
with a hydraulic passage covered by a first slidable sleeve and
located adjacent a lower completion tubular with a port covered by
a second slidable sleeve.
[0014] FIG. 3B is a schematic view of the stinger and tubular of
FIG. 3A coupling to one another in a manner forcibly shifting the
slidable sleeves.
[0015] FIG. 3C is a schematic view of the stinger and tubular of
FIG. 3B upon completed coupling with the slidable sleeves shifted
to allow hydraulic communication between the passage and the
port.
[0016] FIG. 4 is a schematic view of an embodiment of the stinger
and tubular assembly which allows for hydraulic coupling regardless
of radial orientation of the seal and port relative to one
another.
[0017] FIG. 5A is an enlarged sectional view of the upper
completion stinger of FIG. 1.
[0018] FIG. 5B is an enlarged sectional view of the lower
completion tubular of FIG. 1.
[0019] FIG. 6 is a flow-chart summarizing an embodiment of
installing and utilizing downhole completions equipped with a
hydraulic coupling assembly.
DETAILED DESCRIPTION
[0020] Embodiments are described with reference to certain downhole
completions systems. In particular, a production assembly is
detailed throughout with production tubing running through a cased
well to a generally uncased production region. However, a variety
of different types of completions may utilize hydraulic coupling
tools and techniques as detailed herein. Indeed, any downhole
segmented tubulars equipped with hydraulics for coupling to one
another may take advantage of the embodiments described herein.
[0021] As used herein, terms such as "upper completion stinger" or
"lower completion tubular" are meant only to distinguish adjacent
downhole tubular structures for coupling to one another. So, for
example, no particular structural stinger features are meant to be
required due to use of the term "stinger". Further, even the term
"upper" is only utilized to distinguish the tubular that is meant
for positioning closer to the oilfield surface as measured through
the well. That is to say, the term "upper" does not to require that
the tubular literally be at a higher elevation than the adjacent
tubular. Indeed, in a horizontal well section the upper completion
stinger may not be above the lower completion tubular in terms of
elevation.
[0022] Referring now to FIG. 1, a front view of an embodiment of a
completions assembly 100 is shown. The assembly 100 is a segmented
tubular structure with a central channel 110 running continuously
therethrough. Additionally, hydraulic lines 135, 165 are run
through separate stinger 125 and tubular 150 completion segments.
Nevertheless, the lines 135, 165 are hydraulically coupled to one
another such that continuous hydraulics are also provided. More
specifically, physical coupling of the stinger 125 and tubular 150
results in hydraulic coupling of the lines 135, 165 as a passage
130 of the stinger line 135 is hydraulically aligned with a port
160 of the tubular line 165. That is to say, the passage 130 and
the port 160 serve as the terminations for the respective lines
135, 165 and, once hydraulically aligned, define a chamber that
allows hydraulic communication between the lines 135, 165. Thus,
continuous hydraulic communication between the completion segments
125, 150 is now provided.
[0023] As noted above, for sake of distinction, the upper tubular
is referred to as a stinger 125 and the lower tubular, merely a
tubular 150. However, these tubular segments 125, 150 may have a
variety of features commonly found in completions assemblies. For
example, the stinger 125 may serve as the coupling end of a larger
production tubing 210 as depicted in FIG. 2. Thus, collets 140 or
other suitable features may be provided for interlocking with the
tubular 150. More specifically, notice a slot 142 at the interior
of the tubular 150 for reception of the head 141 of a collet
140.
[0024] Continuing with reference to FIG. 1, the noted slot 142 is
more specifically located at the inner surface of a slidable sleeve
155 of the lower tubular 150. Thus, as the stinger 125 is plugged
into the lower tubular 150 it is received by the slidable sleeve
155. As the stinger 125 continues its downward push into the
tubular 150, the sleeve 155 is also forced downward. In the
embodiment shown, this downward movement of the sleeve 155 is
eventually halted by a limiter screw 175 through the body 157 of
the lower tubular 150. At this time, the stinger 125 and collets
140 may continue downward to achieve the above noted interlocking
with the slot 142 if such has not already been achieved.
[0025] Prior to the above described downward movement of the
slidable sleeve 155, the port 160 of the lower tubular 150 is
sealingly covered by the sleeve 155. However, the noted downward
movement of the sleeve 155 eventually exposes the port 160 which in
turn achieves hydraulic alignment with the passage 130 as detailed
above. Indeed, as detailed further below, another slidable sleeve
300 may be provided for sealingly covering the passage 130 until
the noted coupling and hydraulic alignment is achieved (see FIGS.
3A and 5A).
[0026] Referring now to FIG. 2, an overview of an oilfield 200 is
shown with a well 280 accommodating the completions assembly 100 of
FIG. 1 therein. In this embodiment, the well 280 traverses various
formation layers 290, 295 eventually reaching an uncased production
region 287 with perforations 289 thereat. The upper completion
includes production tubing 210 running through a majority of the
well 280 which is defined by casing 285. However, upon approaching
the production region 287, a production packer 270 is employed to
sealingly secure the tubing 210 in place. Furthermore, the tubing
210 may transition into a screened extension 260 for uptake of
production from the noted region 287. Note the intake ports 265 of
the extension. Often this is referred to as the lower `sand face`
completion. A formation isolation valve 275 may also be present
above the uncased production region 287 to provide fluid control to
the well 280, for example, to aid the installation process.
[0027] Following drilling and casing, installation of the
completions system depicted in FIG. 2 may involve achieving fluid
control as noted and installing or `hanging` the screened extension
260. Subsequent connection of the production tubing 210 to the
extension 260 is then followed by setting of the production packer
270 among a variety of other steps. However, in terms of connecting
the upper and lower completions, or in this case, connecting the
production tubing 210 to the extension 260, a unique form of
hydraulic coupling may also be involved. Indeed, the assembly 100
of FIG. 1 is shown serving as the jointed coupling between the
production tubing 210 and the extension 260. Thus, the entire
system may be equipped with independent hydraulics, apart from the
central production channel 110 of the system (see FIG. 1).
[0028] With added reference to FIG. 1, separate hydraulic lines
135, 165 may be hydraulically connected at the coupling assembly
100 of FIG. 2. As such, chemical injection or other production
aiding fluids may be transferred from the oilfield surface 200 all
the way down to the lower completion, the screened extension 260 in
this case. Thus, in one embodiment, a scale reducing acid mixture
may be ported into the well 280 or production channel 110 at
locations prone to such buildup, perhaps particularly directed at
the intake ports 265 of the extension 260. Once more, the
continuous hydraulics allowing for such chemical injection are
installed in a manner that avoids line contamination and
substantially reduces the likelihood of damage to the structure of
the connecting lines 135, 165 as detailed further below.
[0029] Continuing with reference to FIG. 2, the oilfield 200 is
depicted accommodating a host of surface equipment 220. A rig 221
is even provided to support other interventional equipment and
applications as needed. Further, the production tubing 210 is shown
descending from a well head 226 which accommodates a production
line 228 for carrying away produced fluids drawn from the
production region 287. A control unit 222 is also provided for
directing any number of applications. For example, as noted above,
the unit 222 may direct and regulate chemical injection through the
entire system so as to enhance production. Along these lines, an
injection unit 224 is provided adjacent the control unit 222. The
injection unit 224 may accommodate and regulate the distribution of
a chemical injection mixture through the system as directed by the
control unit 222.
[0030] Referring now to FIG. 3A, a schematic view of the hydraulic
coupling assembly 100 of FIG. 1 is shown. In this case, the upper
completion stinger 125 is shown adjacent the lower completion
tubular 150 prior to coupling as depicted in FIG. 1. So, for
example, with reference to FIG. 2, this would be immediately prior
to coupling of the production tubing 210 to the installed extension
260. Notably, at this time, during deployment of the production
tubing 210, the passage 130 of the associated stinger 125 is
covered by a first slidable sleeve 300 (or the stinger sleeve 300).
Thus, contamination of the stinger line 135 with well fluid during
deployment is avoided. By the same token, the port 160 of the lower
completion tubular 150 associated with the extension 260 is covered
by the second slidable sleeve 155 (or the tubular sleeve 155). This
is the sleeve 155 which is detailed with reference to FIG. 1
hereinabove. Regardless, contamination of the tubular line 165 with
well fluid is again avoided due to the sealed covering provided to
the port 160 by the indicated sleeve 155.
[0031] Sealingly covering the passage 130 and the port 160 in
advance of the coupling of the stinger 125 to the tubular 150 may
help to maintain functionality of the hydraulics. For example, the
risk of contamination is not limited to altering a particular
chemical mixture or other hydraulic fluid. Rather, the
contamination could amount to debris and particulate with the
capability of impeding or even disabling hydraulic function through
the connected lines 135, 165 of FIG. 1. By keeping the noted
passage 130 and port 160 sealingly covered in advance of their
hydraulic mating, such catastrophic blockage may be avoided.
[0032] Referring now to FIG. 3B, a schematic view of the hydraulic
coupling assembly 100 of FIG. 1 is again depicted. However, in this
case, the upper completion stinger 125 and the lower completion
tubular 150 are shown physically coupling to one another. Further,
as this coupling begins to take place, the slidable sleeves 300,
155 are forcibly shifted in opposing directions. That is, the first
sleeve 300 of the stinger 125 is shifted in an uphole direction
whereas the second sleeve 155 of the tubular 150 is shifted in a
downhole direction.
[0033] It is worth noting that in advance of the passage 130 and
the port 160 becoming hydraulically aligned as shown in FIG. 3C,
each remains sealingly covered in spite of the shifting of the
sleeves 300, 155. That is to say, each sleeve 300, 155 may serve as
a conventional dynamic seal continuing to maintain sealing in spite
of the shifting.
[0034] Referring now to FIG. 3C, yet another schematic view of the
hydraulic coupling assembly 100 of FIG. 1 is shown. In this view,
the upper completion stinger 125 is now shown fully coupled to the
lower completion tubular 150 as in the case of FIG. 1. The passage
130 and port 160 are now hydraulically aligned and uncovered by the
slidable sleeves 300, 155. As such, hydraulic communication between
the passage 130 and port 160 is now permitted as detailed with
reference to FIG. 1 above.
[0035] With added reference to FIG. 1, the physically and
hydraulically coupled assembly 100 may remain in place for
operations such as the noted chemical injection, hydraulic control
of downhole tools (even within the production region of FIG. 2), or
other applications. However, in other embodiments, the assembly 100
may be configured to allow controlled decoupling of the stinger 125
and tubular 150 following shorter term applications. For example,
the stinger 125 may be retracted such that heads 141 of the collets
140 shift the tubular sliding sleeve 155 back into position over
the port 160. This upward shift may be controllably halted by the
presence of the limiter screw 175, resulting in deflection of the
collets 140. The stinger sleeve 300 may similarly be spring loaded
or otherwise forcibly biased in a downhole direction. As such, the
continued uphole removal of the stinger 125 may proceed with the
port 160 and passage 130 sealingly re-covered by the appropriate
sleeves 155, 300 (returning to a position such as that of FIG.
3A).
[0036] Referring now to FIG. 4, a schematic view of the assembly
100 is shown in which the stinger 125 is equipped with a passage
130 that is circumferential. Indeed, as shown in FIG. 4, the
passage 130 is apparent about the perimeter of the stinger 125 and
defined by seal rings 400. As a result, no particular radial
orientation of the stinger 125 is required in order to attain
hydraulic coupling with the tubular 150. Indeed, as depicted in
FIG. 4, even though the port 160 of the tubular 150 is located
opposite the positioning shown in FIGS. 3A-3C, hydraulic coupling
with the passage 130 is nevertheless attained. In fact, the
hydraulic coupling is attained without any orientation adjustment
to the stinger 125 due to the noted circumferential nature of the
passage 130.
[0037] In other embodiments, the port 160, rather than the passage
130, may be of a circumferential nature. Alternatively, both the
port 160 and the passage 130 may be circumferential. Where
circumferential configurations are utilized, so too may multiple
hydraulic lines be employed. For example, multiple hydraulic lines
may be run through the main body of the stinger 125 to terminate at
a circumferential passage 130, or through the main body of the
tubular 150 where a circumferential port 160 is utilized. Perhaps
more importantly however, so long as at least one of the passage
130 or the port 160 is circumferential, the need to ensure a
particular radial orientation between the stinger 125 and tubular
150 is eliminated. Indeed, the configurations detailed hereinabove,
utilizing an interlocking stinger 125 and tubular 150 assembly with
sliding sleeves 300, 155, avoid the likelihood of damaged hydraulic
terminations during coupling. By the same token, the use of a
circumferential passage 130 and/or port 160 substantially avoids
the possibility of misalignment in coupling of the hydraulics.
Thus, the possibility of attaining a hydraulically malfunctioning
segmented assembly 100 due to improper downhole mating is virtually
eliminated.
[0038] Referring now to FIG. 5A, an enlarged sectional view of the
upper completion stinger 125 is shown in greater detail. In this
view, the stinger line 135 and passage 130 are shown through the
body of the stinger 125, leaving the main central channel 110
available, for example, for production fluids. The above noted
collets 140 are shown making up the terminal end of the stinger
125, often referred to as a mule shoe 500. Perhaps most notably,
however, a realistic depiction of the stinger sliding sleeve 300 is
shown. This sleeve 300 is similar to the sliding sleeve 155 of the
lower tubular 150 of FIG. 1. However, in the case of the stinger
125, the sleeve 300 is configured as a collar about the main body
of the stinger 125 as opposed to a more internal feature. Thus, the
stinger sleeve 300 is positioned to sealingly cover the outwardly
oriented passage 130. In one embodiment, a shear pin is provided
through the stinger sleeve 300 and into the main body of the
stinger 125 to prevent unintended shifting of the sleeve 300 before
coupling to the tubular 150 of FIG. 5B.
[0039] Referring now to FIG. 5B, an enlarged sectional view of the
lower completion tubular 150 is shown in greater detail. This view
is similar to that of FIG. 1, but with the stinger 125 removed.
Therefore, the internal sleeve 155 is located at a more uphole
location and covering the port 160. In this view, a collet 550 is
shown associated with the main body of the tubular 150 and
configured for retaining the sleeve 155 in place. Similar to the
shear pin for the stinger sleeve 300 of FIG. 5A as noted above, the
collet 550 may be employed to help ensure that the sleeve 155 of
the tubular 150 remains in place, sealingly covering the port 160,
until coupling with the stinger 125 is achieved.
[0040] In the embodiment of FIG. 5B, a scraper ring 575 is
incorporated into the sleeve 155 as an aid in dislodging any debris
which may have built up within the central channel 110. For
example, recall that the lower completion tubular 150 may be
installed or `hung` in a manner open to the well 280, perhaps far
in advance of deployment of the stinger 125 (and say, associated
production tubing 210 (see FIGS. 2 and 5A)). Thus, the scraper ring
575 may be provided to address any buildup during such interim at
the inner wall of the tubular 150 defining the channel 110, thereby
allowing the noted downward shift of the sleeve 155 during coupling
with the stinger 125 of FIG. 5A.
[0041] Embodiments detailed hereinabove describe a lower completion
tubular 150 with an internal sleeve 155 for sealing an internally
oriented port 160 and an upper completion stinger 125 with an
external sleeve 300 for sealing an externally oriented passage 130.
However, such orientations are relative. For example, an upper
completion may utilize an externally oriented sleeve and port for
coupling to an internally oriented sleeve and port for a lower
completion while still falling within the scope of embodiments
detailed herein.
[0042] Embodiments detailed above also focus on sleeves 300, 155
which are mechanically shifted. However in other embodiments
shifting may be electrically or hydraulically aided. Furthermore,
in another alternate embodiment, the sleeves 300, 155 may be
configured such that rotational positioning is determinative of
port 160 or passage 130 sealing, as opposed to the shifting of
lateral positioning.
[0043] Referring now to FIG. 6, a flow-chart is shown summarizing
an embodiment of installing downhole completions equipped with a
hydraulic coupling assembly. The first portion of the assembly, the
lower completion tubular, is installed as indicated at 620. This
portion includes hydraulics which are sealingly covered by a sleeve
as are hydraulics of the next portion of the assembly, the upper
completion stinger, which is deployed as indicated at 640. Thus,
hydraulic lines for the completions remain sealed off during
installation operations. Indeed, as indicated at 660, these
sealings are maintained even as the stinger and tubular are
initially connected to one another. However, as noted at 680, the
hydraulics of these separate completions are eventually coupled by
shifting of the sleeves. Nevertheless, this occurs following the
beginning of the connecting of the separate completions. Therefore,
the integrity of the hydraulics of each completion is maintained
throughout the installation process.
[0044] Embodiments described hereinabove include downhole tubular
accommodating hydraulic lines that may be coupled together in a
timely manner. At the same time the likelihood of damaging the
couplings during installation is reduced. Thus, less and expense
may be devoted to the installation and coupling that accompanies
many downhole hydraulically equipped tubular completions.
Furthermore, the odds of improper catastrophic installation in
terms of hydraulics is virtually eliminated where embodiments of
hydraulic coupling tools and techniques are utilized as detailed
herein.
[0045] The preceding description has been presented with reference
to presently preferred embodiments. Persons skilled in the art and
technology to which these embodiments pertain will appreciate that
alterations and changes in the described structures and methods of
operation may be practiced without meaningfully departing from the
principle, and scope of these embodiments. For example,
installation of completions as detailed herein is described with
reference to hydraulics that are utilized in conjunction with
production operations. However, such hydraulics may be employed for
actuation of downhole tools coupled to the lower completion or any
number of alternate hydraulically supported applications.
Regardless, the foregoing description should not be read as
pertaining only to the precise structures described and shown in
the accompanying drawings, but rather should be read as consistent
with and as support for the following claims, which are to have
their fullest and fairest scope.
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