US20110168406A1 - Downhole hydraulic coupling assembly - Google Patents

Downhole hydraulic coupling assembly Download PDF

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Publication number
US20110168406A1
US20110168406A1 US13/004,237 US201113004237A US2011168406A1 US 20110168406 A1 US20110168406 A1 US 20110168406A1 US 201113004237 A US201113004237 A US 201113004237A US 2011168406 A1 US2011168406 A1 US 2011168406A1
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United States
Prior art keywords
stinger
tubular
hydraulic
port
passage
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Abandoned
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US13/004,237
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English (en)
Inventor
Michael Hui Du
Gary Rytlewski
David Wei Wang
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Schlumberger Technology Corp
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Schlumberger Technology Corp
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
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Publication date
Application filed by Schlumberger Technology Corp filed Critical Schlumberger Technology Corp
Priority to US13/004,237 priority Critical patent/US20110168406A1/en
Assigned to SCHLUMBERGER TECHNOLOGY CORPORATION reassignment SCHLUMBERGER TECHNOLOGY CORPORATION ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: WANG, DAVID WEI, DU, MICHAEL HUI, RYTLEWSKI, GARY
Publication of US20110168406A1 publication Critical patent/US20110168406A1/en
Abandoned legal-status Critical Current

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
    • E21B17/02—Couplings; joints
    • E21B17/023—Arrangements for connecting cables or wirelines to downhole devices
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B19/00—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables
    • E21B19/16—Connecting or disconnecting pipe couplings or joints

Definitions

  • Embodiments described relate to tools and techniques for coupling hydraulic lines to one another.
  • embodiments of hydraulic line running through walls of downhole tubing segments are detailed.
  • the initial well design and architecture also plays a significant role in maximizing efficient recovery from the well.
  • 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.
  • 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.
  • 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.
  • chemical cleaners such as hydrochloric acid are delivered to downhole sites of buildup.
  • less passive techniques may be utilized. These may include the use of explosive percussion, impact bits, and milling.
  • 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.
  • 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.
  • a metered amount of chemical mixture such as the above noted hydrochloric acid mix
  • an injection line may be run from surface to downhole points of interest for delivery of chemical mix thereat.
  • the mix may be produced along with the ongoing production of the well.
  • the above noted chemical injection hydraulics may be provided through a production tubing wall or other available structure.
  • the production tubing may be provided in segmented form.
  • a challenge is presented in physically coupling the segment to a previously installed segment.
  • 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.
  • 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.
  • a completions assembly 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.
  • FIG. 1 is a front view of an embodiment of a completions assembly with hydraulic lines coupled through separate stinger and tubular completion segments.
  • FIG. 2 is an overview of an oilfield with a well accommodating the completions assembly of FIG. 1 therein.
  • 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.
  • 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.
  • 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.
  • 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.
  • FIG. 5A is an enlarged sectional view of the upper completion stinger of FIG. 1 .
  • FIG. 5B is an enlarged sectional view of the lower completion tubular of FIG. 1 .
  • FIG. 6 is a flow-chart summarizing an embodiment of installing and utilizing downhole completions equipped with a hydraulic coupling assembly.
  • Embodiments are described with reference to certain downhole completions systems.
  • a production assembly is detailed throughout with production tubing running through a cased well to a generally uncased production region.
  • 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.
  • 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.
  • 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.
  • 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 .
  • 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 .
  • continuous hydraulic communication between the completion segments 125 , 150 is now provided.
  • the upper tubular is referred to as a stinger 125 and the lower tubular, merely a tubular 150 .
  • these tubular segments 125 , 150 may have a variety of features commonly found in completions assemblies.
  • the stinger 125 may serve as the coupling end of a larger production tubing 210 as depicted in FIG. 2 .
  • 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 .
  • the noted slot 142 is more specifically located at the inner surface of a slidable sleeve 155 of the lower tubular 150 .
  • the stinger 125 is plugged into the lower tubular 150 it is received by the slidable sleeve 155 .
  • 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 .
  • 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.
  • the port 160 of the lower tubular 150 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 ).
  • FIG. 2 an overview of an oilfield 200 is shown with a well 280 accommodating the completions assembly 100 of FIG. 1 therein.
  • 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 .
  • a production packer 270 is employed to sealingly secure the tubing 210 in place.
  • the tubing 210 may transition into a screened extension 260 for uptake of production from the noted region 287 .
  • 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.
  • FIG. 2 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 ).
  • separate hydraulic lines 135 , 165 may be hydraulically connected at the coupling assembly 100 of FIG. 2 .
  • 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.
  • 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 .
  • 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.
  • 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.
  • the unit 222 may direct and regulate chemical injection through the entire system so as to enhance production.
  • 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 .
  • FIG. 3A a schematic view of the hydraulic coupling assembly 100 of FIG. 1 is shown.
  • 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 .
  • the passage 130 of the associated stinger 125 is covered by a first slidable sleeve 300 (or the stinger sleeve 300 ).
  • contamination of the stinger line 135 with well fluid during deployment is avoided.
  • 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 ).
  • 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 .
  • 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.
  • 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 .
  • FIG. 3B a schematic view of the hydraulic coupling assembly 100 of FIG. 1 is again depicted.
  • the upper completion stinger 125 and the lower completion tubular 150 are shown physically coupling to one another.
  • 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.
  • each sleeve 300 , 155 may serve as a conventional dynamic seal continuing to maintain sealing in spite of the shifting.
  • FIG. 3C yet another schematic view of the hydraulic coupling assembly 100 of FIG. 1 is shown.
  • 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.
  • 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.
  • the assembly 100 may be configured to allow controlled decoupling of the stinger 125 and tubular 150 following shorter term applications.
  • 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 ).
  • 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 .
  • the port 160 may be of a circumferential nature.
  • both the port 160 and the passage 130 may be circumferential.
  • multiple hydraulic lines may be employed.
  • 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.
  • the need to ensure a particular radial orientation between the stinger 125 and tubular 150 is eliminated.
  • FIG. 5A an enlarged sectional view of the upper completion stinger 125 is shown in greater detail.
  • 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 .
  • 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 .
  • the sleeve 300 is configured as a collar about the main body of the stinger 125 as opposed to a more internal feature.
  • the stinger sleeve 300 is positioned to sealingly cover the outwardly oriented passage 130 .
  • 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 .
  • 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 .
  • 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.
  • 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 .
  • 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 )).
  • 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 .
  • 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 .
  • 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.
  • 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.
  • 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 .
  • 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.
  • 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.
  • 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.

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  • Engineering & Computer Science (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Mechanical Engineering (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Quick-Acting Or Multi-Walled Pipe Joints (AREA)
  • Earth Drilling (AREA)
US13/004,237 2010-01-12 2011-01-11 Downhole hydraulic coupling assembly Abandoned US20110168406A1 (en)

Priority Applications (1)

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US13/004,237 US20110168406A1 (en) 2010-01-12 2011-01-11 Downhole hydraulic coupling assembly

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US29433010P 2010-01-12 2010-01-12
US13/004,237 US20110168406A1 (en) 2010-01-12 2011-01-11 Downhole hydraulic coupling assembly

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US20110168406A1 true US20110168406A1 (en) 2011-07-14

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US (1) US20110168406A1 (fr)
EP (1) EP2524104A4 (fr)
BR (1) BR112012017222A2 (fr)
WO (1) WO2011088013A2 (fr)

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CN104405296A (zh) * 2014-12-02 2015-03-11 东营市福利德石油科技开发有限责任公司 智能井井下对接工具
US9605492B2 (en) * 2013-10-07 2017-03-28 Halliburton Energy Services, Inc. Quick connect for wellbore tubulars
US20180030789A1 (en) * 2015-02-16 2018-02-01 Tercel Ip Limited Connecting Assembly and Receptacle Adapted to Receive Said Connecting Assembly for Connecting Two Tubing Sections, and Method for Installing and Connecting Two Tubing Sections in a Wellbore
US10195662B2 (en) 2014-06-25 2019-02-05 Halliburton Energy Services, Inc. Insulation enclosure incorporating rigid insulation materials
US10208551B2 (en) * 2015-06-03 2019-02-19 Schlumberger Technology Corporation Well system with settable shoulder
US20210332654A1 (en) * 2018-12-31 2021-10-28 Halliburton Energy Services, Inc. Perturbation based well path reconstruction

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Cited By (8)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US9605492B2 (en) * 2013-10-07 2017-03-28 Halliburton Energy Services, Inc. Quick connect for wellbore tubulars
US10195662B2 (en) 2014-06-25 2019-02-05 Halliburton Energy Services, Inc. Insulation enclosure incorporating rigid insulation materials
CN104405296A (zh) * 2014-12-02 2015-03-11 东营市福利德石油科技开发有限责任公司 智能井井下对接工具
US20180030789A1 (en) * 2015-02-16 2018-02-01 Tercel Ip Limited Connecting Assembly and Receptacle Adapted to Receive Said Connecting Assembly for Connecting Two Tubing Sections, and Method for Installing and Connecting Two Tubing Sections in a Wellbore
US10794121B2 (en) * 2015-02-16 2020-10-06 Tercel Ip Limited Connecting assembly and receptacle adapted to receive said connecting assembly for connecting two tubing sections, and method for installing and connecting two tubing sections in a wellbore
US10208551B2 (en) * 2015-06-03 2019-02-19 Schlumberger Technology Corporation Well system with settable shoulder
US20210332654A1 (en) * 2018-12-31 2021-10-28 Halliburton Energy Services, Inc. Perturbation based well path reconstruction
US11976526B2 (en) * 2018-12-31 2024-05-07 Halliburton Energy Services, Inc. Perturbation based well path reconstruction

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Publication number Publication date
WO2011088013A3 (fr) 2011-11-17
WO2011088013A2 (fr) 2011-07-21
EP2524104A4 (fr) 2017-06-28
EP2524104A2 (fr) 2012-11-21
BR112012017222A2 (pt) 2016-04-19

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