EP3039228A1 - Déflecteur résistant à l'érosion pour des outils de fond de trou de puits de forage - Google Patents

Déflecteur résistant à l'érosion pour des outils de fond de trou de puits de forage

Info

Publication number
EP3039228A1
EP3039228A1 EP13895955.6A EP13895955A EP3039228A1 EP 3039228 A1 EP3039228 A1 EP 3039228A1 EP 13895955 A EP13895955 A EP 13895955A EP 3039228 A1 EP3039228 A1 EP 3039228A1
Authority
EP
European Patent Office
Prior art keywords
seat
obturator
shape
sleeve
frangible
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.)
Granted
Application number
EP13895955.6A
Other languages
German (de)
English (en)
Other versions
EP3039228A4 (fr
EP3039228B1 (fr
Inventor
Zachary William Walton
Matthew James MERRON
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.)
Halliburton Energy Services Inc
Original Assignee
Halliburton Energy Services Inc
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.)
Filing date
Publication date
Application filed by Halliburton Energy Services Inc filed Critical Halliburton Energy Services Inc
Publication of EP3039228A1 publication Critical patent/EP3039228A1/fr
Publication of EP3039228A4 publication Critical patent/EP3039228A4/fr
Application granted granted Critical
Publication of EP3039228B1 publication Critical patent/EP3039228B1/fr
Active legal-status Critical Current
Anticipated expiration legal-status Critical

Links

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
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/12—Packers; Plugs
    • 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
    • E21B34/00—Valve arrangements for boreholes or wells
    • E21B34/06—Valve arrangements for boreholes or wells in wells
    • E21B34/063—Valve or closure with destructible element, e.g. frangible disc
    • 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
    • E21B34/00—Valve arrangements for boreholes or wells
    • E21B34/06—Valve arrangements for boreholes or wells in wells
    • E21B34/14—Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools
    • E21B34/142—Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools unsupported or free-falling elements, e.g. balls, plugs, darts or pistons
    • 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
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures

Definitions

  • a plurality of spaced tools are installed in a well and selectively operated.
  • a plurality of sleeve valves are installed in the well and opened in sequence starting with the bottom most valve. Once treatment through the bottom most valve is completed, the next higher up valve is opened and treatment performed through that valve.
  • each downhole well tool typically includes a metallic baffle containing seat to seal against the obturator and activate the tool.
  • baffles for use in abrasive wellbore servicing systems and methods.
  • the baffle is armored against erosion damage from materials flowing through the tool.
  • Figure 1 is a cut-away view of an embodiment of a wellbore servicing system according to the disclosure containing multiple well tools
  • Figure 2 is a cross-sectional view of a sleeve valve containing an embodiment of the baffle of the present invention for use in the wellbore servicing system of Figure 1 showing the sleeve valve in the run-in configuration;
  • Figure 3 is a cross-sectional view of a sleeve valve containing an embodiment of the baffle of the present invention for use in the wellbore servicing system of Figure 1 showing the sleeve valve in the actuated baffle configuration;
  • Figure 4 is a cross-sectional view of a sleeve valve containing an embodiment of the baffle of the present invention for use in the wellbore servicing system of Figure 1 showing the sleeve valve with the ball landed on the baffle seat configuration;
  • Figure 5 is a cross-sectional view of a sleeve valve containing an embodiment of the baffle of the present invention for use in the wellbore servicing system of Figure 1 showing the sleeve valve in the open configuration;
  • Figure 6 is a cross-sectional view of a sleeve valve containing an embodiment of the baffle of the present invention for use in the wellbore servicing system of Figure 1 showing the sleeve valve in the open flowback configuration;
  • Figure 7 is an enlarged cross-sectional view of the sleeve valve of Figure 2 illustrating details of the electro-hydraulic sleeve lock;
  • Figure 8 is an enlarged section view of the electro-hydraulic actuator of the sleeve system of Figure 7;
  • Figure 9 is a perspective view of an embodiment of the baffle in the sleeve valve of Figure 2;
  • Figure 10 is a top plan view of third alternative embodiment of the seat assembly of the sleeve system of Figure 2;
  • any use of any form of the terms “connect,” “engage,” “couple,” “attach,” or any other term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described.
  • the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to ... " Reference to up or down will be made for purposes of description with “up,” “upper,” “upward,” or “upstream” meaning toward the surface of the wellbore and with “down,” “lower,” “downward,” or “downstream” meaning toward the terminal end of the well, regardless of the wellbore orientation.
  • zone or “pay zone” as used herein refers to separate parts of the wellbore designated for treatment or production and may refer to an entire hydrocarbon formation or separate portions of a single formation such as horizontally and/or vertically spaced portions of the same formation.
  • the operating environment comprises a rig 106 (e.g., a drilling, completion, or workover rig) positioned on the earth's surface 104 over a wellbore 114 that penetrates a subterranean formation 102 for the purpose of recovering hydrocarbons.
  • the wellbore 114 may be drilled into the subterranean formation 102 using any suitable drilling technique.
  • the wellbore 114 extends substantially vertically away from the earth's surface 104 over a vertical wellbore portion 116, deviates from vertical relative to the earth's surface 104 over a deviated wellbore portion 136, and transitions to a horizontal wellbore portion 118.
  • all or portions of a wellbore may be vertical, deviated at any suitable angle, horizontal, and/or curved.
  • At least a portion of the vertical wellbore portion 116 is lined with a casing 120 that is secured into position against the subterranean formation 102 in a conventional manner using cement 122.
  • a horizontal wellbore portion may be cased and cemented and/or portions of the wellbore may be uncased.
  • the rig 106 comprises a derrick 108 with a rig floor 110 through which a tubing or work string 112 (e.g., cable, wireline, E-line, Z-line, jointed pipe, coiled tubing, casing, or liner string, etc.) extends downward from the servicing rig 106 into the wellbore 114 and defines an annulus 128 between the work string 112 and the wellbore 114.
  • a tubing or work string 112 e.g., cable, wireline, E-line, Z-line, jointed pipe, coiled tubing, casing, or liner string, etc.
  • the work string 112 delivers the wellbore servicing system 100 to a selected depth within the wellbore 114 to perform an operation such as perforating the casing 120 and/or subterranean formation 102, creating perforation tunnels and/or fractures (e.g., dominant fractures, micro-fractures, etc.) within the subterranean formation 102, producing hydrocarbons from the subterranean formation 102, and/or other completion operations.
  • the servicing rig 106 comprises a motor driven winch and other associated equipment for extending the work string 112 into the wellbore 114 to position the wellbore servicing system 100 at the selected depth.
  • FIG. 1 While the operating environment depicted in Figure 1 refers to a stationary servicing rig 106 for lowering and setting the wellbore servicing system 100 within a land-based wellbore 114, in alternative embodiments, mobile workover rigs, wellbore servicing units (such as coiled tubing units), and the like may be used to lower a wellbore servicing system into a wellbore. It should be understood that a wellbore servicing system may alternatively be used in other operational environments, such as within an offshore wellbore operational environment.
  • the subterranean formation 102 comprises a zone 150 associated with deviated wellbore portion 136.
  • the subterranean formation 102 further comprises first, second, third, fourth, and fifth horizontal zones, 150a, 150b, 150c, 150d, 150e, respectively, associated with the horizontal wellbore portion 118.
  • the zones 150, 150a, 150b, 150c, 150d, 150e are offset from each other along the length of the wellbore 114 in the following order of increasingly downhole location: 150, 150e, 150d, 150c, 150b, and 150a.
  • stimulation and production sleeve systems 200 comprising sleeve valves 200a, 200b, 200c, 200d, 200e, and 200f are located within wellbore 114 in the work string 112 and are associated with zones 150, 150a, 150b, 150c, 150d, and 150e, respectively.
  • zone isolation devices such as annular isolation devices (e.g., annular packers and/or swellpackers) may be selectively disposed within wellbore 114 in a manner that restricts fluid communication between spaces immediately uphole and downhole of each annular isolation device.
  • each sleeve valve comprises one or more sleeves which can be moved to selectively open ports spaced along the wall of the work string 112 to provide a fluid paths between the interior of the work string and the surrounding formation.
  • the sleeve valves 200a-200f can be opened in sequence starting with opening the ports associated bottom most sleeve valve 200a.
  • Sleeve valve 200a is opened by inserting an obturator into the well to contact a seat on a baffle in the valve. With the valve 200a open horizontal zone 150a can be treated by pumping fluids into the zone through the ports opened by valve 200a.
  • valve 200a is opened and treatment through this bottom most valve 200a is completed, the next higher up valve 200b is opened and treatment performed through that valve.
  • valve 200b is opened to treat zone 150b.
  • the valves 200b-200f each also comprises a baffle with seat which with the obturator block or seals off the interior of the work string 112 below the valve. This sequence can be repeated for each of the sleeve valves 200c- 200f until the uppermost sleeve valve 200f is actuated and used to treat zone 150f.
  • FIG. 2 a cross-sectional view of an embodiment of sleeve valve 200a of the stimulation and production sleeve system 200 (hereinafter referred to as "sleeve system" 200) is shown.
  • Valve 200a is typical of the construction of the valves 200b-200f.
  • Many of the components of sleeve valve 200a lie substantially coaxial with a central axis 202 of sleeve valve 200a.
  • Sleeve valve 200a comprises an upper adapter 204, a lower adapter 206, and a ported case assembly 208.
  • the ported case assembly 208 is joined between the upper adapter 204 and the lower adapter 206. Together, inner surfaces of the upper adapter 204, the lower adapter 206, and the ported case assembly 208, respectively, substantially define a sleeve flow bore 216.
  • the upper adapter 204 comprises a collar configured for attachment to an element of work string 112.
  • the lower adapter 206 is configured for attachment to an element of work string 112.
  • the upper and lower adapters comprise threads for connecting to the ported case assembly 208 and work string 112.
  • the ported case assembly 208 is substantially tubular in shape and comprises an upper sleeve portion 230 and a lower baffle portion 240.
  • the sleeve portion 230, baffle portion 240, upper adapter 204 and lower adapter 206 each have substantially the same inner and outer diameters.
  • the upper sleeve portion 230 further comprises ports 232.
  • ports 232 are through holes extending radially through the upper sleeve portion 230 and are selectively used to provide fluid communication between sleeve flow bore 216 and the annulus 128 immediately exterior to the upper sleeve portion 230.
  • the upper sleeve portion 230 comprises a sleeve 234 mounted to slide axially within the sleeve portion 232 selectively block and open ports 232.
  • sleeve 234 is hydraulically locked in the upper or run in position illustrated in Figure 2.
  • the upper or uphole direction is to the left sides of each figure.
  • Sleeve 234 is held in this position by filling annular chamber 236 with a hydraulic fluid.
  • Chamber 236 extends from sleeve portion 230 and into baffle portion 240.
  • Chamber 236 can be filled with hydraulic fluid using removable plug 242.
  • a rupture disk 244 closes off the lower end of chamber 236.
  • the structure for piercing the rupture disk 244 is best illustrated in reference to Figures 7 and 8 and various embodiments are disclosed in U.S. Patent 8,322,426 and U.S. Publications 2013/0048290 and 2013/0048291, which are incorporated herein by reference for all purposes.
  • the piercing structure comprises a cutter 246, actuator 248 and electronic package 250.
  • the actuator 248 comprises an explosive charge which when ignited by the electronic package 250 drives the cutter 246 in the uphold direction to pierce rupture disk 244.
  • Electronic package 250 comprises means for sensing and recording the passage along the sleeve bore 216 of obturators passing through the sleeve valve 200a. When a set number of obturators pass through the valve 200a, electronic package 258 initiates the actuator 248.
  • Porting 252 provides a path for the hydraulic fluid to vent from chamber 236 into flow bore 216.
  • the baffle portion 240 (240 also encloses the electronics, batteries, thruster, and rupture disc) comprises an annular baffle assembly 260 mounted in the bore of the baffle portion 242 to slide axially in the flow bore 216.
  • the details of construction of the baffle assembly will be described in more detail by reference to Figures 8 and 9.
  • the baffle assembly 260 comprises a sleeve 262 and a C-ring baffle 264 having an uphole facing seat 266.
  • Sleeve 262 is held in axial position in the baffle 240 illustrated in Figure 7 by a releasable mechanism such as a shear pin or snap ring (not shown).
  • baffle 264 is illustrated in its expanded condition where in its internal diameter is substantially the same as sleeve 262 and the gap 263 is present in the C-ring structure.
  • the seal ring comprising baffle 264 is spring-loaded are resiliently urged radially outward to engage sleeve 262.
  • Baffle 264 has tabs 267 which lock into a groove in sleeve 266; this axially holds the baffle 264 in position, (they are locked together axially only in the state where the baffle is expanded).
  • baffle 264 and sleeve 266 are forced together (by axial forces Fs and Fb) baffle 264 will climb up (should this read down?) the ramp services and tabs 267 to a point where the gap 263 in the C-ring structure of baffle 264 is closed and the internal diameter of the baffle 264 is less than the internal diameter of the sleeve 262.
  • the baffle 264 is in the expanded position illustrated in Figure 10, an obturator with an external diameter less than that of the sleeve 266 will pass through the baffles 264 without engaging it. It should be appreciated that when the baffle 264 contracts, that it can be of a sufficiently small internal diameter to engage an obturator.
  • a baffle erosion buffer or shield is provided.
  • This shield allows the system to be used to treat a greater number of treatment zones (treatment stages).
  • the shield comprises a nose cone ring 268 and a seat abutting ring 270.
  • the nose cone ring 268 as substantially the same into your an exterior diameters as the sleeve 262 and baffle 264 when arranged as illustrated in Figures 2, 7 and 10.
  • the annular surface of the ring 268 facing in the upward direction is tapered or rounded or angled to reduce flow turbulence. Turbulent flow has a more erosive impact on the components; an angled or rounded face reduces flow turbulence.
  • Ring 268 can be formed from an erosion resistant material such as carbide, hard steel or the like.
  • the seat abutting ring 270 is located downhole of the nose cone ring 268 and inside of the baffle 264. Ring 268 has a section 272 that covers the gap 263 to provide a continuous cylindrical surface on the interior of the baffle assembly 260 to reduce turbulence and the erosion of fact a flow there through.
  • the seat abutting ring 270 is made from a frangible material, such as, ceramic, cast-iron, phenolic are similar brittle erosion (abrading affect or particle impact affect which erode/corrode the material) resistant materials.
  • the operation sleeve system 200 will be described by reference to Figures 2-8.
  • the system 200 is of the type which is used in conjunction with an obturator 280 comprising magnetic material.
  • the obturator 280 is a spherical ball formed from the nonmagnetic material with a number of cylindrical magnets installed in the outer diameter of the obturator 282 created a magnetic field around the outer diameter.
  • the electronic package of each of the stimulation and production sleeve valves 200a-200f is programmed to count a certain number of obturators 280 passing through the valve.
  • the run-in condition of valve 200a is illustrated in Figure 2 with the baffle 264 in the expanded our pass through condition.
  • the run-in and operation of valve 200a is typical of the run in operation of valves 200b-200f .
  • the baffle 264 has been activated by the electronic package 250 sensing the passage of a set number of obturators 280 through the sleeve valve 200a. If for example, electronic package 250 of valve 200a has been programed to release the hydraulic lock on sleeve 234 after the passage of a single obturator 280, then sleeve 234 moves in a downhole direction to contact the baffle assembly 260. This movement of sleeve 234 causes the baffle 264 to ride down the ramp services and tabs 267 and contract to assume the obturator catching position illustrated in Figure 3. As the baffle 264 contracts the frangible seat abutting ring 270 breaks apart and fall down the wellbore. It is to be noted that at this point, that even though the sleeve 234 has moved downward the ports 230 remain blocked.
  • valve 200a The next step in the operation of valve 200a is illustrated in Figure 4.
  • the next obturator 280 moving down the wellbore engages baffle 264 and seals against the seat 266. With the obturator 280 in this position, the lower portion of the work string 212 below valve 200a is sealed off.
  • sleeve 262 is held in axial position by the shear pins, are the light (not shown).
  • operating a wellbore servicing system such as wellbore servicing system 100 may comprise providing a first sleeve system (e.g., of the type of sleeve systems 200 ) in a wellbore and providing wellbore servicing pumps and/or other equipment to produce a fluid flow through the sleeve flow bores of the sleeve system.
  • a first sleeve system e.g., of the type of sleeve systems 200
  • wellbore servicing pumps and/or other equipment to produce a fluid flow through the sleeve flow bores of the sleeve system.
  • an obturator may be introduced into the fluid flow so that the obturator travels downhole and into engagement with the seat of a baffle in first sleeve valve.
  • fluid pressure may be increased to cause the first sleeve system to open ports to provide treatment paths.
  • a method of performing a wellbore servicing operation may comprise providing a work string comprising a plurality of sleeve systems in a configuration as described above and positioning the work string within the wellbore such that one or more of the plurality of sleeve systems is positioned proximate and/or substantially adjacent to one or more of the zones.
  • the zones may be isolated, for example, by actuating one or more packers or similar isolation devices.
  • a method of performing a wellbore servicing operation may comprise providing well casing comprising a plurality of sleeve systems in a configuration as described above and positioning the casing such that one or more of the plurality of sleeve systems is positioned proximate and/or substantially adjacent to one or more of the zones.
  • the zones may be isolated, for example, by actuating one or more packers or similar isolation devices.
  • the servicing fluid communicated to the zone may be selected dependent upon the servicing operation to be performed.
  • Nonlimiting examples of such servicing fluids include a fracturing fluid, a hydrajetting or perforating fluid, an acidizing, an injection fluid, a fluid loss fluid, a sealant composition, or the like.

Landscapes

  • Geology (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Mining & Mineral Resources (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • Physics & Mathematics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Earth Drilling (AREA)
  • Branch Pipes, Bends, And The Like (AREA)
  • Treatment Of Water By Oxidation Or Reduction (AREA)
  • Physical Or Chemical Processes And Apparatus (AREA)
  • Taps Or Cocks (AREA)
  • Filling Or Discharging Of Gas Storage Vessels (AREA)

Abstract

L'invention concerne un ensemble siège destiné à être utilisé dans des systèmes d'entretien de puits de forage, ledit ensemble siège comprenant un déflecteur cylindrique ayant un siège de forme annulaire comportant un siège orienté vers le haut destiné à recevoir un obturateur, le siège définissant un passage central. Des bagues présentant une résistance à l'érosion sont placées à l'intérieur et à l'avant du déflecteur afin de protéger le déflecteur et le siège contre l'érosion provoquée par des fluides et des solides de traitement passant à travers le système d'entretien.
EP13895955.6A 2013-10-21 2013-10-21 Déflecteur résistant à l'érosion pour des outils de fond de trou de puits de forage Active EP3039228B1 (fr)

Applications Claiming Priority (1)

Application Number Priority Date Filing Date Title
PCT/US2013/065863 WO2015060809A1 (fr) 2013-10-21 2013-10-21 Déflecteur résistant à l'érosion pour des outils de fond de trou de puits de forage

Publications (3)

Publication Number Publication Date
EP3039228A1 true EP3039228A1 (fr) 2016-07-06
EP3039228A4 EP3039228A4 (fr) 2017-05-10
EP3039228B1 EP3039228B1 (fr) 2019-01-09

Family

ID=52993261

Family Applications (1)

Application Number Title Priority Date Filing Date
EP13895955.6A Active EP3039228B1 (fr) 2013-10-21 2013-10-21 Déflecteur résistant à l'érosion pour des outils de fond de trou de puits de forage

Country Status (7)

Country Link
EP (1) EP3039228B1 (fr)
AR (2) AR098127A1 (fr)
AU (1) AU2013403420C1 (fr)
CA (2) CA2989547C (fr)
DK (1) DK3039228T3 (fr)
MX (1) MX368525B (fr)
WO (1) WO2015060809A1 (fr)

Families Citing this family (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
DK3268831T3 (da) 2015-03-12 2020-12-07 Ncs Multistage Inc Elektrisk aktiveret apparat til flowregulering i borehuller

Family Cites Families (11)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US7182135B2 (en) * 2003-11-14 2007-02-27 Halliburton Energy Services, Inc. Plug systems and methods for using plugs in subterranean formations
US7644772B2 (en) * 2007-08-13 2010-01-12 Baker Hughes Incorporated Ball seat having segmented arcuate ball support member
US7708066B2 (en) * 2007-12-21 2010-05-04 Frazier W Lynn Full bore valve for downhole use
WO2010120774A1 (fr) * 2009-04-17 2010-10-21 Exxonmobil Upstream Research Company Systèmes et procédés de déviation de fluides dans un puits de forage à l'aide de bouchons destructibles
US8668012B2 (en) * 2011-02-10 2014-03-11 Halliburton Energy Services, Inc. System and method for servicing a wellbore
US8322426B2 (en) 2010-04-28 2012-12-04 Halliburton Energy Services, Inc. Downhole actuator apparatus having a chemically activated trigger
US20120261131A1 (en) 2011-04-14 2012-10-18 Peak Completion Technologies, Inc. Assembly for Actuating a Downhole Tool
US8668006B2 (en) * 2011-04-13 2014-03-11 Baker Hughes Incorporated Ball seat having ball support member
US9151138B2 (en) 2011-08-29 2015-10-06 Halliburton Energy Services, Inc. Injection of fluid into selected ones of multiple zones with well tools selectively responsive to magnetic patterns
US20130048290A1 (en) 2011-08-29 2013-02-28 Halliburton Energy Services, Inc. Injection of fluid into selected ones of multiple zones with well tools selectively responsive to magnetic patterns
CA2859399A1 (fr) 2011-12-14 2013-06-20 Utex Industries, Inc. Ensemble siege extensible pour isolation de zones de fracture dans un puits

Non-Patent Citations (1)

* Cited by examiner, † Cited by third party
Title
See references of WO2015060809A1 *

Also Published As

Publication number Publication date
AR098127A1 (es) 2016-05-04
CA2924555A1 (fr) 2015-04-30
DK3039228T3 (en) 2019-04-08
MX2016003306A (es) 2016-10-13
EP3039228A4 (fr) 2017-05-10
AR116285A2 (es) 2021-04-21
CA2989547A1 (fr) 2015-04-30
EP3039228B1 (fr) 2019-01-09
WO2015060809A1 (fr) 2015-04-30
AU2013403420A1 (en) 2016-03-17
AU2013403420B2 (en) 2016-10-27
AU2013403420C1 (en) 2017-03-16
CA2924555C (fr) 2018-02-13
MX368525B (es) 2019-10-07
CA2989547C (fr) 2020-01-07

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