CHARACTERISTICS

BACKGROUND

The present disclosure relates generally to monitoring equipment useful in operations related to subterranean wellbores, e.g., wellbores employed for oil and gas exploration, drilling and production. More particularly, embodiments of the disclosure employ distributed acoustic sensing (DAS) systems for monitoring downhole events.

Generally, DAS systems employ a waveguide, such as a fiber optic cable, that provides distributed strain sensing over a length of the waveguide. These systems may be suitable for a number of downhole applications ranging from temperature sensing to passive seismic monitoring. The waveguide of a D AS system may he delivered into a wellbore on a conveyance such as a coiled tubing strand, which generally includes a continuous strand of a flexible tube that may be wound and unwound from a spool. The length of a coiled tubing strand may be in the range of about 10,000 feet to about 25,000 feet in some instances, and thus, the coiled tubing strand may be unwound from a spool to readily lower the waveguide along with downhole tools to a subterranean location.

BRIEF DESCRIPTION OF THE DRAWINGS

The disclosure is described in detail hereinafter, by way of example only, on the basis of examples represented in the accompanying figures, in which:

FIG. 1 is a partial, cross-sectional side view a D AS monitoring system for monitoring downhole events within a coiled tubing strand;

FIG. 2A is a cross-sectional side view of a portion of the coiled tubing strand of FIG. I illustrating an optical waveguide used in monitoring a position of a ball dropped through the coiled tubing strand;

FIG. 2B is a graphical representation of DAS data acquired from the optical waveguide at three distinct times when the ball of FIG 2A was at three distinct locations within the coiled tubing strand;

FIG. 3 is a cross-sectional side view of a portion of the coiled tubing strand of FIG. 1 illustrating the optical waveguide used in monitoring a position of a fluid mixture pumped through the coiled tubing strand; FIG. 4 is a cross-sectional side view of a portion of the coiled tubing strand of FIG. 1 illustrating the optical waveguide used in detecting the location of a fluid leak in the coiled tubing strand; and

FIG. 5 is a flowchart illustrating a procedure for a monitoring an operation within a tubular conveyance carrying a DAS optical waveguide into a wellbore.

DETAILED DESCRIPTION

The present disclosure includes DAS systems and procedures for detecting and monitoring wellbore events occurring within the interior of a tubular conveyance such as a coiled tubing strand. Embodiments of the disclosure include an optical waveguide carried by the coiled tubing strand for monitoring the location of a target within the coiled tubing strand, wherein the target may be anything flowing or otherwise traveling inside the coiled tubing strand. In one example, the target may be a ball dropped through the coiled tubing strand. The optical waveguide can be used to determine whether the ball encounters an obstruction within the coiled tubing strand, and/or can confirm that the ball has properly seated on a downhole tool actuated by engagement with the ball. In other embodiments, the location of a target such as a liquid sand flow or other fluid mixture can be monitored, and/or the location of a leak through a lateral wall of the coiled tubing strand can be detected.

Figure 1 is a partially cross-sectional side view of a DAS monitoring system 10 in accordance with exemplary embodiments of the present disclosure. The DAS monitoring system 10 includes a data acquisition tool 12, which generally includes a coiled tubing strand 14 and a signal cable 16. The signal cable 16 extends along a length of the coiled tubing strand 14 and facilitates real-time measurement of acoustic intensity as a function of position.

The signal cable 16 may comprise an optical wave guide in the form of one or more fiber optic strands. In some embodiments, each of the fiber optic strands may be employed to sense a different downhole parameter, or multiple strands may be deployed for redundancy. In some embodiments, the signal cable 16 may additionally or alternatively operate to transmit electrical power and or data signals as appreciated by those skilled in the art. The fiber optic strands of the signal cable 16 may be jacketed to protect the signal cable 16 from a harsh downhole environment, and may be sufficiently flexible to withstand winding and unwinding associated with operation of the coiled tubing strand 14. in some embodiments the signal cable 16 may be embedded within a tubular wall of the coiled tubing strand 14 or may extend along an inner diameter or an outer diameter of the coiled tubing strand 14. The coiled tubing strand 14 and the signal cable 16 are wound together around a spool 18, which facilitates storage, transportation and deployment of the coiled tubing strand 14 and signal cable 16. In other embodiments, the signal cable 16 may be conveyed on an alternate conveyance such as a drill sting, production tubing or other tubular string. An upper end 20 of the coiled tubing strand 14 is coupled to a reel termination assembly 22, which may be configured to permit fluids and solid objects to be pumped through the coiled tubing strand 14 as the spool 18 is rotated. The reel termination assembly 22 includes an inlet 24 through which fluids may be pumped into and/or out of the coiled tubing strand 14. The reel termination assembly 22 also includes a bulkhead device 26 wiiere an additional length of signal cable 16 may be inserted into the coiled tubing strand 14, or a length of the signal cable 16 may be withdrawn from the coiled tubing strand 14.

In some embodiments, the bulkhead device 26 may facilitate connection of the signal cable 16 to a DAS measurement unit 32. The DAS measurement unit 32 is operable to supply laser light pulses to the signal cable 16 and receive and/or analyze the returned signal(s) to perform distributed sensing of vibration, pressure, strain, or other phenomena indicative of acoustic energy interactions with the optical fiber along the length of the coiled tubing strand 16. The light pulses from the DAS measurement unit 32 pass through the signal cable 16 and encounter one or more acoustic energy-dependent phenomena within the coiled tubing strand 16. Such phenomena may include spontaneous and/or stimulated Briilouin (gain/loss) backscatter, which are sensitive to strain in the fiber. Strain variations modulate the inelastic optical collisions within the fiber, giving a detectable Briilouin subcarrier optical frequency shift in the 9- 11 GHz range which can be used for making DAS measurements.

The DAS measurement unit 32 is operably coupled to a controller 34 having a processor 36 and a computer readable medium 38 operably coupled thereto. The computer readable medium 38 can include a nonvolatile or non-transitory memory with data and instructions that are accessible to the processor 36 and executable thereby. The computer readable medium 38 may also be pre-programmed or selectively programmable with one or more acoustic signatures for comparison with signals received by the DAS measurement unit 32, e.g. , to identify and locate a target within the coiled tubing strand 14. Alternatively or additionally, the processor 36 may be optionally coupled to a desktop computer 40 having a display, or another computing device which may receive data from multiple sources. In some embodiments, the desktop computer 40 may receive signals indicative of the target detected by DAS measurement unit 32 and/or processor 36 for display, storage and/or further processing.

From the spool 18, the coiled tubing strand 14 extends over guide arch 44 into a wellbore 46 where an annulus 48 is defined between the coiled tubing strand 14 and the geologic formation“G.” A lower end 49 of the coiled tubing strand 14 is coupled to a downhole tool 50 The wellbore 46 extends from a surface location“S” to a subterranean location within a geologic formation“G.” In the illustrated example, a casing string 52 extends at least partially into the wellbore 46 and is cemented within the geologic formation “G”. In other embodiments, the coiled tubing system 10 may be operated in connection with fully open-hole wellbores. A blow-out preventer stack 54 is provided at the surface location “S,” and may be automatically operable to seal the wellbore 46 in the event of an uncontrolled release of fluids from the wellbore 46. Also at the surface location“S,” a tubing injector 56 is provided to selectively impart drive forces to the coiled tubing strand 14, e.g., to run the strand 14 into the wellbore 26 or to pull the strand 14 from the wellbore 26. The tubing injector 56, guide arch 44 and other equipment may be supported on a derrick (not shown), crane or similar other oilfield apparatus, as appreciated by those skilled in the art. Although wellbore 46 is illustrated as extending from a terrestrial surface location“S,” in other embodiments, a wellbore may extend from an offshore or subsea surface location without departing from the spirit and scope of the disclosure.

Referring to FIG. 2A, illustrated in a cross-sectional side view' is a portion of the coiled tubing strand 14. The signal cable 16 extends along an interior surface 58 of the coiled tubing strand 14 in a helical pattern. The helical pattern of the signal cable 16 may facilitate bending of the coiled tubing strand 14 over the guide arch 44 (FIG. 1 ), coiling and uncoiling of the coiled tubing strand 14 and other operational loads. In other embodiments, the signal cable 16 may extend in a straight, sinusoidal or other pattern without departing from the principles of the disclosure.

A generally spherical ball 60, or a tool actuator having an alternate shape (dart, plug, etc.), may be dropped through the coiled tubing strand 14 or pumped down the coiled tubing string by a fluid 62. The fluid 62 may include drilling mud or other fluids suitable for a particular application. Although fluid 62 is represented by an arrow- indicating a downhole direction, the fluid 62 may also be induced to How upwardly, e.g., in a reverse circulation operation. The ball 60 may be operable to land, e.g., in a seat within the downhole tool 50 (FIG. 1) or at another downhole location to actuate a device, plug a fluid flow path, or for other purposes recognized in the art. In some embodiments, it may be beneficial to reduce the flow rate of the fluid 62 prior to landing the ball 60 to prevent damage to the ball seat and ensure proper seating of the ball. Thus, it may be beneficial to accurately determine the duration of travel through the coiled tubing strand 14. Calculations of the travel time needed for the ball 60 to land may be based on the flow rate of the fluid 62, depth of the downhole tool 50, diameter of the coiled tubing strand 14, etc. may be approximate and inaccurate in the event the ball 60 becomes lodged on the signal cable 16 or other impediment in the coiled tubing strand 14. The velocity and position of the ball 60 may be monitored in real time using the DAS monitoring systems 10 (FIG. 1).

As the ball 60 progresses through the coiled tubing strand 14, the flow of fluid 62 around the ball 60 may generate fluid eddies 64, drag, turbulent or differential flow patterns around the ball 60. This flow of fluid 62 around the ball 60 will generate acoustic energy that may strain the signal cable 16 and be detectable by the DAS measurement unit 32 (FIG, 1). Thus, the flow of the ball 60 and/or the eddies 64 around the ball 60 represent a target within the coiled tubing strand 14 for which a location within the coiled tubing strand 14 may be determined using the DAS monitoring system 10 The acoustic signature of the ball 60 moving through the coiled tubing strand 14 may be identified to provide a real-time indication of the position of the ball 60 downhole.

As illustrated in FIG. 2B, the acoustic signature may comprise an observable moving dual peak pattern. Tire longitudinal position along the coiled tubing strands 14 is plotted along the vertical axis and the intensity or magnitude of the acoustic energy may be plotted on the horizontal axis. At an initial time (t=0) a first peak 66 in the acoustic energy plot be observed indicating a position at a leading end (directly downstream) of the ball 60 where eddies 64 occur in front of the ball 60, and a second peak 68 indicating a position at a trailing end (directly upstream) of the ball 60. At time t=0, the acoustic energy plot reveals a longitudinal position, e.g., position A, of the ball 60 within the coiled tubing strand 14. Similarly, at first subsequent time (time t— 1), the first and second peaks 66, 68 indicate a longitudinal“position B” within the coiled tubing strand 14 that is downstream of position A, and at second subsequent time (time t=2), the first and second peaks 66, 68 indicate a longitudinal“position C” within the coiled tubing strand 14 downstream of positions A and B. Accordingly, with the time and position information provided by the DAS measurement unit 32, a position and velocity of the ball 14 may be monitored in real time. The seating of the ball 60 at the appropriate location may be positively verified, e.g , by confirming that the acoustic signature of the ball 60 remains at the longitudinal position of the downhole tool 50 (FIG. 1) or other selected position over an appropriate time interval.

In some embodiments, the ball 60 may carry an acoustic transmitter 70 therein. The acoustic transmitter 70 may include electronic components that produce a chirp having a recognizable acoustic signature, one or more flow passages that produce a whistle as fluid 62 flows therepast, or another mechanism for producing acoustic energy that may be detected by the signal cable 16. The acoustic energy provided by the acoustic transmitter 70 may supplement the acoustic energy provided by the eddies 64, or may be used to provide additional well logging capabilities. For example, the acoustic transmitter 70 may produce an acoustic signal 72, which may be reflected by the geologic formation“G” to produce an echo 74 of the acoustic signal that may be detected by the signal cable 16. In this manner, the ball 70 may measure seismic information which can produce real-time information about the lithology of the surrounding geologic formation“G.”

Referring to FIG. 3, a cross-sectional side view of the coiled tubing strand 14 illustrates fluid 62 flowing to deploy a target through the coiled tubing strand 14. The target may be a volume of liquid sand 76, cement or any other fluid with differing densities or characteristics than the fluid 62. The volume of liquid sand 76 generally defines a leading end 82 and a trailing end 84, which may be detected by the signal cable 16. The DAS measurements may include certain patterns or acoustic signatures indicative of changes in the material properties in the environment around the signal cable 16, e.g., changes in density associated with the leading and trailing ends 82, 84 of the liquid sand 76 or within the volume of liquid sand 76. An operator user may visually identify these patterns and determine and track the liquid sand 76 flowing within the coiled tubing strand 14. Tracking the liquid sand may include determining if any gaps or bubbles form therein having a density differing from the liquid sand 76. Gaps or bubbles may be generated, e.g. due to interactions between the liquid sand and the signal cable 16, where the signal cable is disposed within the flow. Any excessive flow churn or vortex creation associated with a twisted signal cable, e.g. , may he identified by comparison with a known example acoustic signatures enabling corrective actions to be employed. Since the speed of sound depends on the density of fluid, DAS measurements collected through the signal cable 16 may be converted to a density or bulk flow rate of the fluid surrounding the signal cable using algorithms recognized in the art.

Referring to FIG. 4, a cross-sectional side view' of the coiled tubing strand 14 illustrates fluid 62 leaking from an interior 86 of the coiled tubing strand 14, which may be targeted by the DAS monitoring system 10 (FIG. 1). The fluid 62 may leak through a pinhole 88 formed through a wall 90 of the coiled tubing strand 14. Fatigue failures in a coiled tubing strand 14 often present themselves initially as a pinhole 88. An acoustic signature of the spray of fluid 62 escaping into the annulus 48 (FIG. 1) may be measured with the aid of the data acquisition tool 12, and a longitudinal location of the pinhole 88 may be determined. Additionally, where a leak through a pinhole 88 is detected or suspected, the data provided by the data acquisition tool 12 may be processed to determine a bulk flow rate of the fluid 62 flowing at a downhole location. The bulk flow' rate of the fluid 62 flowing downhole may be compared to the bulk flow rate observed, measured or determined at the surface location“S.” (FIG. 1). Where there is a discrepancy of the downhole and surface level bulk flow rates, the existence of a leak through a pinhole 88 may be verified.

Referring to FIG. 5, a flowchart illustrates one example procedure 100 for a monitoring an operation within a tubular conveyance. Initially at step 102, a coiled tubing strand is deployed into a wellbore to convey a signal cable into the wellbore. The signal cable may extend in a helical manner along an interior flowpath of the coiled tubing strand. Tire helical arrangement of the signal cable facilitates flexing of the coiled tubing strand as the coiled tubing strand is unwound from a reel. If the signal cable is not already connected to a DAS measurement unit, it may be connected at step 104. The DAS Measurement Unit may provide thousands of laser light pulses through the signal cable and receive and analyze the returned optical signals indicative of the acoustic energy encountered by the signal cable along its length. Next, a ball may be deployed into the coiled tubing strand at step 106. The ball may be pumped downhole with a fluid such as drilling mud, cleanout fluid or another appropriate fluid. Tire ball may be configured to seat at a downhole tool to actuate a function of the downhole tool as recognized in the art.

At step 108 DAS measurements from the signal cable are acquired by the DAS measurement unit. Simultaneously, the DAS measurements may be processed to determine a measure of acoustic energy as a function of position along the coiled tubing strand at step 110. Also at the same time, an acoustic signature of the ball moving through the coiled tubing strand may be detected in the processed DAS measurements (step 112). For example, the position of eddies at leading and trailing ends of the ball may he detected due to the differential in acoustic energy between the eddies and the drilling mud, cleanout fluid or other fluid more distant from the ball through which the ball is flowing. The raw measurements and/or the processed measurements including the acoustic signature may be transmitted to a personal computer for storage, display or further processing. Steps 108, 110 and 112 may be repeated continuously as the ball moves down the coiled tubing strand. In this manner, an operator may monitor the position of the bah as it moves down the coiled tubing strand, and a velocity of the ball may be determined if desired. If the ball meets an obstruction in the coiled tubing strand, the progress of the acoustic signature may be interrupted giving the operator an indication of the position or depth of the obstruction.

Where the ball does not meet an obstruction, the ball may be landed at the downhole tool to actuate a function of the downhole tool at step 114. For example, the ball may engage a seat of the downhole tool to plug a flowpath, adjust a valve or another downhole function recognized in the art. At step 116, the position of the ball at the downhole tool may be verified by detecting the acoustic signature of the ball at the downhole tool. Again, the acoustic energy of eddies formed as fluid flows past the ball may be detected, or a whistle or electronic chirp may be detected by the signal cable and DAS measurement unit. With the positive verification of the location of the ball, an operator may continue wellbore operations in confidence. In the event that the location of the ball may not be positively verified, in some embodiments, further wellbore operations may be suspended either by an operator or a set of instructions executed by the processor.

At step 118, once the ball has landed, the signal cable may continue to be used monitor operations occurring within the coiled tubing strand. For example, leaks through a sidewall of the coiled tubing strand may be detected by comparing the DAS measurements with an acoustic signature of a leak preprogrammed into a memory of a computer or the DAS measurement unit. The acoustic signature of a leak may be pre -determined by collecting DAS measurements of a known leak, for example. Other operations such as delivery of different density fluids may also be monitored.

The aspects of the disclosure described below are provided to describe a selection of concepts in a simplified form that are described in greater detail above. This section is not intended to identify key features or essential features of the claimed subject matter, nor is it intended to be used as an aid in determining the scope of the claimed subject matter.

In one aspect, the disclosure is directed a method of monitoring a downhole operation. The method includes (a) acquiring downhole distributed acoustic sensing measurements from a signal cable deployed into a wellbore on a tubular conveyance, (b) detecting an acoustic signature of a target flowing within the tubular conveyance by processing the distributed acoustic sensing measurements, and (c) determining a location of the target within the tubular conveyance based on the acoustic signature.

In one or more example embodiments, the method further includes deploying a downhole tool into the wellbore on the tubular conveyance, and flowing an actuator through the tubular conveyance to actuate the downhole tool. The actuator may be the target, and determining the location of the target may include tracking the actuator by determining a plurality of locations of the actuator corresponding to a plurality of times as the actuator flows through the tubular conveyance. In some embodiments, the method may further include verifying a seated position of actuator at the downhole tool.

In some embodiments, detecting the acoustic signature of the target includes detecting a dual peak signature of the actuator representing a differential flow at leading and trailing ends of the actuator. In example embodiments, the method further includes transmitting an acoustic signal from a transmitter carried by the actuator, and detecting the acoustic signature of the target may include detecting the acoustic signal with the signal cable or detecting an echo of the acoustic signal with the signal cable.

In some example embodiments, the tubular conveyance is a coiled tubing strand and detecting an acoustic signature of the target includes detecting a leak in the coiled tubing strand by detecting an acoustic signature of fluid flowing through an opening in a lateral wall of the coiled tubing strand. In some embodiments, processing the distributed acoustic sensing measurements includes determining a downhole bulk flowrate of a fluid inside the coiled strand and comparing the downhole bulk flow rate to a bulk flow rate of the fluid into the coiled tubing strand at a surface location.

In one or more example embodiments, detecting an acoustic signature of the target includes detecting a volume of fluid within the coiled tubing strand by detecting a change in density of fluid flowing through the coiled tubing strands at the leading and trailing ends of the volume of fluid. In some embodiments, the method further includes comprising detecting changes in density within the volume of fluid.

According to another aspect, the disclosure is directed to a wellbore monitoring system. The system includes a tubular conveyance extending into a wellbore, a signal cable extending along a length of the tubular conveyance within the wellbore, a distributed acoustic sensing unit operably coupled to the signal cable for acquiring downhole distributed acoustic sensing measurements from the signal cable, a processor operably coupled to the distributed acoustic sensing unit for processing the distributed acoustic sensing measurements, and a memory operably coupled to the acoustic sensing unit, the memory having a set of instructions stored thereon that, when executed by the processor cause the processor to compare the processed distributed acoustic sensing measurements to a predetermined acoustic signature of a downhole event within the tubular conveyance.

In some embodiments, the predetermined acoustic signature includes at least one of the set consisting of an actuator dropped through the tubular conveyance, a volume of fluid moving through the tubular conveyance inducing a change in fluid properties at a fixed location within the tubular conveyance, and a leak of fluid flowing through a sidewall of the tubular conveyance. In some embodiments, the predetermined acoustic signature is an acoustic signature of an acoustic transmitter carried by the actuator.

In one or more example embodiments, the tubular conveyance includes a coiled tubing strand. The signal cable may extend through an interior of the coiled tubing strand in a helical pattern.

According to still another aspect, the disclosure is directed to a method for monitoring a downhole operation that includes (a) deploying a signal cable into a wellbore on a tubular conveyance, wherein the signal cable extends along a length of the tubular conveyance, (b) dropping an actuator through an interior passageway of the tubular conveyance into the wellbore, (c) acquiring downhole distributed acoustic sensing measurements from the signal cable; and (d) detecting, in the distributed acoustic sensing measurements, an acoustic signature of the actuator moving through the tubular conveyance, wherein the acoustic signature includes a dual peak pattern indicative of relatively high levels of acoustic energy at leading and trailing ends of the actuator.

In one or more example embodiments, the method further includes suspending further downhole operations until a location of the acoustic signature corresponds with a location of a downhole tool actuated by the actuator. In some embodiments, deploying the signal cable into the wellbore includes deploying the signal cable into the wellbore on a coiled tubing strand by unwinding the coiled tubing strand from a reel. In some embodiments, the method according further includes detecting an acoustic signature of a pinhole leak including fluid flowing a lateral wall of the coiled tubing strand at a downhole location. In some example embodiments, the method further includes comparing a downhole hulk flowrate of a fluid inside the coiled strand to a downhole bulk flow rate of the fluid into the coiled tubing strand at a surface location.

The Abstract of the disclosure is solely for providing the United States Patent and Trademark Office and the public at large with a way by which to determine quickly from a cursory reading the nature and gist of technical disclosure, and it represents solely one or more examples.

While various examples have been illustrated in detail, the disclosure is not limited to the examples shown. Modifications and adaptations of the above examples may occur to those skilled in the art. Such modifications and adaptations are in the scope of the disclosure.