EP2909440B1 - Flow velocity and acoustic velocity measurement with distributed acoustic sensing - Google Patents
Flow velocity and acoustic velocity measurement with distributed acoustic sensing Download PDFInfo
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- EP2909440B1 EP2909440B1 EP14743240.5A EP14743240A EP2909440B1 EP 2909440 B1 EP2909440 B1 EP 2909440B1 EP 14743240 A EP14743240 A EP 14743240A EP 2909440 B1 EP2909440 B1 EP 2909440B1
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- Prior art keywords
- velocity
- pressure pulse
- acoustic
- well
- optical waveguide
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/10—Locating fluid leaks, intrusions or movements
- E21B47/107—Locating fluid leaks, intrusions or movements using acoustic means
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
- E21B47/13—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. radio frequency
- E21B47/135—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. radio frequency using light waves, e.g. infrared or ultraviolet waves
Description
- This disclosure relates generally to equipment utilized and operations performed in conjunction with a subterranean well and, in an example described below, more particularly provides for flow velocity and acoustic velocity measurement with distributed acoustic sensing.
- It is beneficial to be able to determine characteristics of fluids entering a wellbore, and flow rates of those fluids, so that decisions relating to production of the fluids can be better informed. For example, if it is known that an unacceptably large flow rate of an undesired fluid is entering the wellbore at a certain location, a decision may be made to restrict or prevent the undesired fluid from entering the wellbore.
- Therefore, it will be appreciated that advancements are continually needed in the arts of determining fluid compositions and flow rates in wells. Such advancements may be used in production, injection, stimulation, conformance, or other types of well operations.
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US-A-2012/152024 discloses a method and apparatus for sensing fluid flow within a conduit using a distributed array system. - According to a first aspect of the present invention, there is provided a well flow velocity measurement method, comprising: propagating at least one pressure pulse through multiple fluid compositions in a well; detecting a velocity of the pressure pulse along an optical waveguide in the well, the optical waveguide being included in a distributed acoustic sensing system; and determining an acoustic velocity in the fluid composition based on the velocity of the pressure pulse.
- According to a second aspect of the present invention, there is provided a well flow velocity measurement system, comprising: a pressure pulse generator configured to propagate at least one pressure pulse through multiple fluid compositions in a well; and a distributed acoustic sensing system configured to detect coherent Rayleigh backscattering along an optical waveguide in the well, whereby a velocity of the pressure pulse in the well is determined.
- For a better understanding of the present invention, reference is now made, by way of example only, to the following drawings, in which:
-
FIG. 1 is a representative partially cross-sectional view of a well system and associated method which can embody principles of this disclosure. -
FIG. 2 is a representative plot of pressure pulse location versus time. -
FIG. 3 is a representative plot of pressure pulse velocity versus time. -
FIG. 4 is a representative plot of acoustic pulse location versus time. - Representatively illustrated in
FIG. 1 is a well flowvelocity measurement system 10 and associated method which can embody principles of this disclosure. However, it should be clearly understood that thesystem 10 and method are merely one example of an application of the principles of this disclosure in practice, and a wide variety of other examples are possible. Therefore, the scope of this disclosure is not limited at all to the details of thesystem 10 and method described herein and/or depicted in the drawings. - This disclosure provides unique techniques for determining velocities of fluid flows in wells, and for determining characteristics of the fluids. These technique can be used to determine flow rates, acoustic velocities and compositions of the various fluids which flow through a
wellbore 12. - In the
FIG. 1 example, thewellbore 12 is generally vertical and is lined withcasing 14 andcement 16. However, in other examples, thewellbore 12 may be generally horizontal or inclined, and may be uncased or open hole, at least in an area of interest. - A
pressure pulse 18 is transmitted through thewellbore 12. Thepressure pulse 18 may be transmitted from the earth's surface, or from another location in the well. For example, apressure pulse generator 30 may be used to produce positive and/or negative pressure pulses, which propagate through the fluids in thewellbore 12. - Pressure pulses can be positive where a compressed air or nitrogen gun is used to dump a pre-charged volume of gas into the
wellbore 12. Alternatively, pressurized well fluids may be dumped into an evacuated chamber to generate a negative pressure pulse. Furthermore, flow exiting a well may be modulated by a choke or valve at the surface to generate either positive or negative pulses, or both. - Apparatus and methods for transmitting
such pressure pulses 18 are described inUS Patent Nos. 5,754,495 and6,321,838 , although other types of pressure pulse generators may be used, if desired. A preferred pressure pulse generator is the HalSonics(TM) system marketed by Halliburton Energy Services, Inc. of Houston, Texas USA. - A pressure pulse can also be generated by striking a structure in the well, such as a tubular string, the
casing 14, etc. When the structure is impacted, a pressure wave develops in contents of the structure and propagates away from a location of the impact. A mechanism could, for example, deliver a hammer impact driven by differential pressure, an electromagnetic solenoid, or other mechanical actuator. - In other examples, the
pressure pulses 18 could be generated by detonating a series of explosive or other exothermic devices in the well. Thus, the scope of this disclosure is not limited to any particular manner of generating thepressure pulses 18. - Note that it is not necessary for the
pressure pulses 18 to be generated at or near the earth's surface. In some examples, thepressure pulses 18 could be generated at or near a bottom of thewellbore 12, at some location between the surface and the bottom of the wellbore, etc. If thepressure pulses 18 are generated at a location between the surface and the bottom of thewellbore 12, then the pulses can travel in opposite directions via the wellbore from the location where they were generated. - The
pressure pulses 18 are detected by means of a sensor located in the well. In this example, the sensor comprises an optical waveguide 22 (such as, an optical fiber or ribbon), which may be part of a cable including one or more optical waveguides, electrical conductors, hydraulic conduits, etc. The sensor is preferably part of a distributed acoustic sensing (DAS)system 20, which is capable of detecting acoustic energy as distributed along anoptical waveguide 22. - In the technique known to those skilled in the art as distributed acoustic sensing (DAS), acoustic energy distributed along the
optical waveguide 22 can be measured by detecting coherent Rayleigh backscattering in the waveguide. In this manner, the pressure pulses 18 and their reflections can be effectively tracked as they travel along thewaveguide 22 in the well. - The
DAS system 20 ofFIG. 1 comprises surface optics, electronics and software, commonly known to those skilled in the art as aninterrogator 24, and theoptical waveguide 22. Theoptical waveguide 22 may be installed in thewellbore 12, inside or outside of thecasing 14 or other tubulars, optionally in thecement 16 surrounding the casing, etc. - The
interrogator 24 launches light into the optical waveguide 22 (e.g., from an infrared laser or other light source 26). Adetector 28 detects the light returned via the sameoptical waveguide 22. TheDAS system 20 uses measurement of backscattered light (e.g., coherent Rayleigh backscattering) to detect the acoustic energy along thewaveguide 22. - In another technique, an array of weak fiber Bragg gratings or other artificially introduced reflectors can be used with the
optical waveguide 38 to detect acoustic signals along the waveguide. - The
interrogator 24 and/or thepressure pulse generator 30 may be controlled via acontrol system 32, for example, including at least aprocessor 34 andmemory 36. Signal processing is used to segregate thewaveguide 22 into an array of individual "microphones" or acoustic sensors, typically corresponding to 1-10 meter segments of the waveguide. - The
waveguide 22 may be housed in a metal tubing or control line and positioned in thewellbore 12. In some examples, thewaveguide 22 may be in cement surrounding thecasing 14, in a wall of the casing or other tubular, suspended in thewellbore 12, in or attached to a tubular, etc. The scope of this disclosure is not limited to any particular placement of thewaveguide 22. - The
pressure pulse 18 is reflected back through thewellbore 12, and thereflected pressure pulse 38 is also detected by theDAS system 20. Thus, theDAS system 20 detects the propagation of thepressure pulse 18 and thereflected pressure pulse 38 as they displace through thewellbore 12. - The
pressure pulse 18 may be reflected off of a bottom of the well, off of a plug or other obstruction in thewellbore 12, or at a fluid/air or fluid/metal interface at or near the surface. In addition, other changes in acoustic impedance can cause thepressure pulse 18 to be reflected. Such changes in acoustic impedance can include changes in acoustic velocity due to changes in fluid composition in thewellbore 12, changes incasing 14 diameter, etc. The scope of this disclosure is not limited to any particular manner of producing thereflected pressure pulse 38. - Using the principles of this disclosure, flow velocity, Vf and acoustic velocity, Va of fluid compositions in the
wellbore 12 can be readily determined. If flow velocity is known, a volumetric flow rate can be readily calculated by multiplying the flow velocity by flow area. - The acoustic velocity Va in a fluid composition depends on the fluids in the composition and a compliance of a pipe or conduit containing the fluid composition. If one knows the acoustic velocity of the fluid composition, the fluids in the composition (for example, an oil/water ratio) can be readily estimated.
- In the
FIG. 1 example, two sets ofperforations 42a,b are depicted in thecasing 14, so thatrespective fluid compositions 40a,b are produced into thewellbore 12. Below thebottom perforations 42a, no flow enters the well. Between theperforations 42a,b, only thefluid composition 40a is present in thewellbore 12. Above theupper perforations 42b, thefluid compositions 40a,b are commingled. - In the
FIG. 1 example, thepressure pulse 18 is generated at the surface, which causes an acoustic wave or signal to travel from the surface through thewellbore 12 with velocity Vo (in this case, opposing the direction of flow of thefluids 40a,b). When thepulse 18 encounters the bottom of the well, it is reflected back toward the surface with velocity Vw . (in this case, with the direction of flow of thefluids 40a,b). - The reflected
pulse 38 may return to the surface and be reflected again through thewellbore 12. With theoptical waveguide 22 installed in the well and connected to theDAS interrogator 24, it is possible to observe the propagation of thepulses - Reflections will occur whenever there is a change in acoustic impedance. For fluids in pipe, such changes occur, for example, when an end of the pipe is blocked by a plug, when the inner diameter of the pipe changes, or if the pipe terminates inside another pipe with a larger diameter, etc. Amplitudes and signs of reflected pulses are readily calculated, for example, as detailed in Kinsler, L.E., et al., Fundamentals of Acoustics, (1982, John Wiley & Sons, Inc.).
- As the pressure pulse or acoustic wave propagates in either direction, it decreases in amplitude due to losses, and spreads out due to dispersion. Although the wave may be detected moving back and forth through the
wellbore 12 for an extended period of time, it is advantageous to measure the velocity of wave propagation early on while the wave amplitude is relatively high and its pulse width is relatively narrow. However, the flow property measurement techniques described here depend on pulse velocity, not pulse amplitude. - Velocities of the
pressure pulses 18 and theirreflections 38 can be readily determined using theDAS interrogator 24, for example, by dividing displacement of the signals by elapsed time. Using this information, with thesystem 10 configured as depicted inFIG. 1 , an acoustic velocity in the commingledfluids 40a,b can be determined, as well as a velocity of the commingled fluids through thewellbore 12. - In the
FIG. 1 example, for a section of thewellbore 12 above theupper perforations 42b:FIG. 1 example, the reflected signal 38), Vo is the velocity of a signal traveling opposite the flow of fluid (in theFIG. 1 example, the generated signal 18), Va is the acoustic velocity in the commingledfluids 40a,b, and Vf is the velocity of the fluids through thewellbore 12. Solving the above linear equations yields:FIG. 1 example. -
- A similar analysis can be performed for each section of the
wellbore 12, enabling a contribution to the flow from each set ofperforations 42a,b to be determined. Since the acoustic velocity Va in the fluids in thewellbore 12 can be readily determined, a fluid composition contribution of thefluids 40a,b flowing into the individual sections of thewellbore 12 can also be inferred. - If Equation 4 yields a negative number for the velocity Vf , this is an indication that the fluid is flowing in an opposite direction to that assumed when applying values to the variables in Equations 1-4. The principles of this disclosure are applicable no matter whether a fluid flows with or in an opposite direction to a signal 36a generated by the
signal generator 34, and no matter whether a fluid flows with or in an opposite direction to a reflected signal 36b. - If, as mentioned above, the
pressure pulses 18 are generated between the surface and the bottom of thewellbore 12, then the reflectedpulses 38 can return to the source location, and flow along thewellbore 12 can be determined as described above. If the reflectedpulses 38 do not return to the source location, then flow velocity at the source location can be determined from the velocities of thepressure pulses 18 propagating away from the source location. -
FIG. 2 is a representative plot showing a position of a pressure pulse 18 (and its reflections) repeatedly traversing thewellbore 12. Note that different portions of the plot have respective different slopes, depending on whether the pulse is traveling through only thefluid composition 40a, or through the commingledfluid compositions 40a,b. The change in slope is caused by changes in flow velocity from combining two or more flows, as well as changes in the composition of the fluids (e.g., due to mixing multiple flow streams). - Pulse velocity is proportional to the slope or derivative of pulse position with respect to time.
FIG. 3 is a representative plot of the pulse velocity as a function of time (the derivative ofFIG 2 ). - Thus, the pulse velocities in the
fluid composition 40a and in the commingledfluid compositions 40a,b can be readily determined. Using this data, the acoustic velocity Va in eachfluid composition 40a,b can be readily determined from Equation (3), and the velocities Vf of thefluid composition 40a and commingledfluid compositions 40a,b can be readily determined from Equation (4). - Note that the upward and downward velocities are different at any position along the
wellbore 12 in which there is flow. This can be explained by examining Equations (1) and (2), and noting a sign difference for Vf , indicating that for a given flow rate and acoustic velocity Va , the pulse velocity Vw of the reflectedsignal 38 is always greater than the pulse velocity Vo of the generatedsignal 18 at any measurement point in thewellbore 12, for producing wells. For injection wells, this would be reversed. - The acoustic velocity Va in a fluid composition depends on the fluids in the composition and the compliance of the pipe walls or conduit walls containing the fluid (such as, the
casing 14 in theFIG. 1 example). Because the pipe walls or conduit walls are not infinitely stiff, the speed of sound in the system is reduced in a quantifiable way. (see, e.g., Robert McKee and Eugene "Buddy" Broerman, "Acoustics in Pumping Systems", 25th International Pump User Symposium (2009)). - If one knows the acoustic velocity of the fluid composition and the pipe wall compliance(s) (readily calculated from pipe parameters such as the elasticity modulus of the steel pipe, the inside pipe diameter and the pipe wall thickness), the fluids in the composition (for example, an oil/water ratio) can be readily estimated.
- In order to infer the composition of the fluid (oil, water, or the fractions of oil and water), the pipe compliance is very important. Pipe compliance can reduce the speed of sound in the pipe by as little as a few percent all the way up to 50 percent or more.
- Pipe compliance of a steel pipe is caused by not having infinitely stiff walls. It causes the acoustic wave traveling down the pipe to move slower than it would in a pipe with infinitely stiff walls.
-
FIG. 4 is a plot of acoustic pressure along a non-flowing test well taken with an installed optical waveguide connected to a DAS system. Multiple up and down reflections are observed. Slopes of the V-shaped traces depicted inFIG. 4 are indicative of the acoustic velocity Va of the well fluid. The absolute values of the upward and downward velocities should be equal as the well was not flowing. - The
FIG. 4 data was generated downhole during a fracturing operation. An acoustic pulse resulted from a pressure differential across a ball (plug) opening a fracturing sleeve. An acoustic wave travels from 250 m to about 400 m and back toward the surface, where it reflects at 250 m. - It may now be fully appreciated that the above disclosure provides significant advancements to the arts of determining fluid compositions and flow rates in wells. Flow rates at multiple different locations in a well can be readily determined. Acoustic velocities in different fluid compositions at different locations in the well can also be determined.
- A well flow velocity measurement method is provided to the art by the above disclosure. In one example, the method can comprise: transmitting an acoustic signal (such as the pressure pulse 18) through at least one
fluid composition 40a,b in a well; detecting velocities Vu, Vd of the acoustic signal in both opposite directions along anoptical waveguide 22 in the well, theoptical waveguide 22 being included in a distributedacoustic sensing system 20; and determining an acoustic velocity Va in the fluid composition based on the velocities of the acoustic signal. - The distributed
acoustic sensing system 20 may detect coherent Rayleigh backscattering along theoptical waveguide 22. - The transmitting step can include propagating at least one
pressure pulse 18 through thefluid composition 40a,b. The detecting step can include detecting at least one reflection of thepressure pulse 18. - The transmitting step can include transmitting the acoustic signal through multiple
fluid compositions 40a,b in the well. The determining step can include determining the acoustic velocity Va in each of the multiplefluid compositions 40a,b. - Determining the acoustic velocity Va in the
fluid composition 40a,b can include compensating for pipe compliance. - The distributed
acoustic sensing system 20 can indicate acoustic energy as distributed along theoptical waveguide 22. - The distributed
acoustic sensing system 20 may include aninterrogator 24 which detects coherent Rayleigh backscattering in theoptical waveguide 22. - Another well flow velocity measurement method described above can comprise: propagating at least one
pressure pulse 18 through at least onefluid composition 40 a,b in a well; detecting a velocity of thepressure pulse 18 along anoptical waveguide 22 in the well, the optical waveguide being included in a distributedacoustic sensing system 20; and determining an acoustic velocity Va in the fluid composition based on the velocity of the pressure pulse. - The detecting step can include detecting the velocity of the
pressure pulse 18 in both opposite directions along theoptical waveguide 22. - The propagating step includes propagating the
pressure pulse 18 through multiplefluid compositions 40 a,b in the well. - A well flow
velocity measurement system 10 is also described above. In one example, thesystem 10 can include apressure pulse generator 30 which propagates at least onepressure pulse 18 through at least onefluid composition 40 a,b in a well, and a distributedacoustic sensing system 20 which detects coherent Rayleigh backscattering along anoptical waveguide 22 in the well, whereby a velocity of the pressure pulse in the well is determined. - The
system 10 may include aprocessor 34 which determines an acoustic velocity Va in thefluid composition 40 a,b based on the velocity of thepressure pulse 18. - Although various examples have been described above, with each example having certain features, it should be understood that it is not necessary for a particular feature of one example to be used exclusively with that example. Instead, any of the features described above and/or depicted in the drawings can be combined with any of the examples, in addition to or in substitution for any of the other features of those examples. One example's features are not mutually exclusive to another example's features. Instead, the scope of this disclosure encompasses any combination of any of the features.
- Although each example described above includes a certain combination of features, it should be understood that it is not necessary for all features of an example to be used. Instead, any of the features described above can be used, without any other particular feature or features also being used.
- It should be understood that the various embodiments described herein may be utilized in various orientations, such as inclined, inverted, horizontal, vertical, etc., and in various configurations, without departing from the principles of this disclosure. The embodiments are described merely as examples of useful applications of the principles of the disclosure, which is not limited to any specific details of these embodiments.
- In the above description of the representative examples, directional terms (such as "above," "below," "upper," "lower," etc.) are used for convenience in referring to the accompanying drawings. However, it should be clearly understood that the scope of this disclosure is not limited to any particular directions described herein.
- The terms "including," "includes," "comprising," "comprises," and similar terms are used in a non-limiting sense in this specification. For example, if a system, method, apparatus, device, etc., is described as "including" a certain feature or element, the system, method, apparatus, device, etc., can include that feature or element, and can also include other features or elements. Similarly, the term "comprises" is considered to mean "comprises, but is not limited to."
- Of course, a person skilled in the art would, upon a careful consideration of the above description of representative embodiments of the disclosure, readily appreciate that many modifications, additions, substitutions, deletions, and other changes may be made to the specific embodiments, and such changes are contemplated by the principles of this disclosure. For example, structures disclosed as being separately formed can, in other examples, be integrally formed and vice versa. Accordingly, the foregoing detailed description is to be clearly understood as being given by way of illustration and example only, the scope of the invention being limited solely by the appended claims and their equivalents.
Claims (15)
- A well flow velocity measurement method, comprising:propagating at least one pressure pulse (18) through multiple fluid compositions (40a, b) in a well (12);detecting a velocity of the pressure pulse along an optical waveguide (22) in the well, the optical waveguide being included in a distributed acoustic sensing system (20); anddetermining an acoustic velocity in the fluid composition based on the velocity of the pressure pulse.
- The method of claim 1, wherein the detecting further comprises detecting the velocity of the pressure pulse in both opposite directions along the optical waveguide.
- The method of claim 1 or claim 2, wherein the distributed acoustic sensing system detects coherent Rayleigh backscattering along the optical waveguide.
- The method of any one preceding claim, wherein the detecting further comprises detecting at least one reflection of the pressure pulse.
- The method of any one preceding claim, wherein the determining further comprises determining the acoustic velocity in each of the multiple fluid compositions.
- The method of any one preceding claim, wherein the distributed acoustic sensing system indicates acoustic energy along the optical waveguide.
- The method of any preceding claim, wherein the distributed acoustic sensing system includes an interrogator which detects coherent Rayleigh backscattering in the optical waveguide.
- The method of any preceding claim, wherein the propagating further comprises generating the acoustic signal at a location between the earth's surface and a bottom of the well, the acoustic signal propagating in opposite directions from the location.
- The method of any preceding claim, wherein the propagating further comprises applying an impact to a tubular string.
- The method of any preceding claim, wherein determining the acoustic velocity in the fluid composition further comprises compensating for pipe compliance.
- The method of any one preceding claim, wherein:the pressure pulse travels as an acoustic signal; andthe detecting of velocities of the acoustic signal takes place in both opposite directions along the optical waveguide (22) .
- A well flow velocity measurement system, comprising:a pressure pulse generator (30) configured to propagate at least one pressure pulse (18) through multiple fluid compositions (40a, b) in a well (12); anda distributed acoustic sensing system (20) configured to detect coherent Rayleigh backscattering along an optical waveguide (22) in the well, whereby a velocity of the pressure pulse in the well is determined.
- The system of claim 12, wherein:a computer is configured to determine an acoustic velocity in the fluid composition based on the velocity of the pressure pulse; and/orin use of the system, an acoustic velocity in each of the multiple fluid compositions is determined.
- The system of claim 12 or claim 13, wherein:in use of the system, the velocity of the pressure pulse in both opposite directions along the optical waveguide is determined; and/orthe distributed acoustic sensing system is configured to detect at least one reflection of the pressure pulse.
- The system of any one of claims 12 to 14, wherein:the distributed acoustic sensing system is configured to indicate acoustic energy along the optical waveguide; and/orthe pressure pulse generator is configured to apply an impact to a tubular string (14); and/orthe pressure pulse generator is configured to propagate the pressure pulse in opposite directions from a location in the well.
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US13/748,720 US20140202240A1 (en) | 2013-01-24 | 2013-01-24 | Flow velocity and acoustic velocity measurement with distributed acoustic sensing |
PCT/US2014/010682 WO2014116424A1 (en) | 2013-01-24 | 2014-01-08 | Flow velocity and acoustic velocity measurement with distributed acoustic sensing |
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EP2909440A1 EP2909440A1 (en) | 2015-08-26 |
EP2909440A4 EP2909440A4 (en) | 2016-07-20 |
EP2909440B1 true EP2909440B1 (en) | 2019-06-26 |
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EP (1) | EP2909440B1 (en) |
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None * |
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EP2909440A4 (en) | 2016-07-20 |
US20140202240A1 (en) | 2014-07-24 |
WO2014116424A1 (en) | 2014-07-31 |
EP2909440A1 (en) | 2015-08-26 |
CA2891596A1 (en) | 2014-07-31 |
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