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WO2025090097A2 - Détermination de vitesse d'empilement annulaire basée sur la semblance d'ondes de flexion en fuite dans des puits tubés - Google Patents

Détermination de vitesse d'empilement annulaire basée sur la semblance d'ondes de flexion en fuite dans des puits tubés Download PDF

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Publication number
WO2025090097A2
WO2025090097A2 PCT/US2023/079628 US2023079628W WO2025090097A2 WO 2025090097 A2 WO2025090097 A2 WO 2025090097A2 US 2023079628 W US2023079628 W US 2023079628W WO 2025090097 A2 WO2025090097 A2 WO 2025090097A2
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Prior art keywords
cement
inches
acoustic
velocity
semblance
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WO2025090097A3 (fr
Inventor
Amit PADHI
Qingtao Sun
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Halliburton Energy Services Inc
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Halliburton Energy Services Inc
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Publication of WO2025090097A2 publication Critical patent/WO2025090097A2/fr
Publication of WO2025090097A3 publication Critical patent/WO2025090097A3/fr
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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
    • E21B47/00—Survey of boreholes or wells
    • E21B47/005—Monitoring or checking of cementation quality or level
    • 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
    • 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
    • E21B47/14—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 using acoustic waves
    • E21B47/16—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 using acoustic waves through the drill string or casing, e.g. by torsional acoustic waves

Definitions

  • a wellbore is formed using a drill bit at the lower end of a drill string.
  • the drill bit is rotated while force is applied through the drill string and against the rock face of the formation being drilled.
  • the drill string and bit are removed, and the wellbore is lined with a string of casing. An annular area is thus formed between the string of casing and the formation penetrated by the wellbore.
  • a cementing operation is typically conducted in order to displace drilling fluid and fill part or all of the hollow-cylindrical annular area between the casing and the borehole wall with cement.
  • the combination of cement and casing strengthens the wellbore and facilitates the zonal fluid isolation of certain sections of a hydrocarbon-producing formation (or “pay zones”) behind the casing.
  • the first string of casing is placed from the surface and down to a first drilled depth.
  • This casing is known as a surface casing. In the case of offshore operations, this casing may be referred to as a conductor pipe.
  • one of the main functions of the initial string(s) of casing is to isolate and protect the shallower, usable water bearing aquifers from contamination by any other wellbore fluids.
  • casing strings are almost always cemented entirely back to surface.
  • One or more intermediate strings of casing is also run into the wellbore. These casing strings will have progressively smaller outer diameters into the wellbore. In most current wellbore completion jobs, especially those involving so called unconventional formations where high- pressure hydraulic operations are conducted downhole, these casing strings may be entirely cemented.
  • an intermediate casing string may be a liner, that is, a string of casing that is not tied back to the surface.
  • the process of drilling and then cementing progressively smaller strings of casing is repeated several times until the well has reached total depth.
  • the final string of casing is also a liner.
  • the final string of casing referred to as a production casing, is also typically cemented into place.
  • Additional tubular bodies may be included in a well completion. These include one or more strings of production tubing placed within the production casing or liner. Each tubing string extends from the surface to a designated depth proximate a production interval, or “pay zone.” Each tubing string may be attached to a packer. The packer serves to seal off the annular space between the production tubing string(s) and the surrounding casing.
  • cement sheath surrounding the casing strings have a high degree of circumferential and axial integrity around the casing annulus against fluid channeling or flowing through the cement along the wellbore.
  • the cement must also bond with the casing surface and borehole wall to perform a hydraulic seal against fluid migration along the wellbore. This means that the cement is fully placed into the annular region to prevent fluid communication between fluids at the level of subsurface completion and aquifers residing just below the surface.
  • fluids may include fracturing fluids, aqueous acid, and formation fluids.
  • the integrity of a cement sheath may be determined through the use of a cement bond log.
  • a cement bond log uses an acoustic signal that is transmitted by a logging tool at the end of a wireline.
  • the logging tool includes a transmitter, and then a receiver that “listens” for sound waves generated by the transmitter through the surrounding case strings.
  • the logging tool includes a signal processor that takes a continuous measurement of the amplitude of sound pulses from the transmitter to the receiver.
  • the theory behind the cement bond long is that the amplitude of a sonic signal as it travels through a well cemented pipe is only a fraction of the amplitude through uncemented pipe.
  • Figure 1 illustrates a system including an acoustic logging tool
  • Figure 2 illustrates an example information handling system
  • Figure 3 illustrates another example information handling system
  • Figure 4 is a schematic showing potential ray paths of energy from cement-formation interface according to some embodiments of the present disclosure
  • Figure 5 illustrates a workflow of one embodiment of the present disclosure
  • Figure 7 is a semblance map created for a range of annular thicknesses and cement velocities; and [0014] Figure 8 shows a conversion of time domain images into radial distance domain images according to embodiments of the present disclosure.
  • the present disclosure relates to the field of well drilling and completions, and more specifically to the evaluation of cement integrity behind a casing string using acoustic signals.
  • Ultrasonic waveform data can be gathered using various techniques, such as a pitch-catch technique performed using transducers in a pitch-catch arrangement.
  • the ultrasonic waveform data collected by the pitch-catch arrangement includes leaky-Lamb wave measurements which can be classified into symmetric mode and anti-symmetric mode components.
  • the flexural mode or zeroorder antisymmetric mode (Ao) is highly dispersive in certain frequency ranges. Further, the flexural mode is sensitive to the interface conditions between casing and cement.
  • the interface between cement and formation affects the leaked and subsequently reflected energy that escapes out of the flexural mode traveling through the casing.
  • the flexural mode (Ao) is the wave mode that travels along the casing.
  • the leaked portion that gets reflected back is called the secondary flexural mode, which is the result of the leaked and reflected energy.
  • acoustic logging tools may be used to emit an acoustic signal which may traverse through at least part of a conduit string to at least part of a casing to at least part of the cement to at least part of the cement-formation section. Reflected signals are measured by the acoustic logging tool. Reflected signals may be analyzed to determine if the section of casing is fully bonded to the cement, or is free pipe, or is partially bonded to the cement. Further, the analysis of the reflected signals can determine if the cement is bonded to the formation or partially bonded to the formation.
  • Figure 1 illustrates an operating environment for an acoustic logging tool 100 as disclosed herein.
  • Acoustic logging tool 100 may comprise a transmitter 102 and/or a receiver 104. Additionally, transmitter 102 and receiver 104 may be configured to rotate in acoustic logging tool 100. In examples, there may be any number of transmitters 102 and/or any number of receivers 104, which may be disposed on acoustic logging tool 100. Additionally, transmitter 102 and receiver 104 may be configured to rotate in acoustic logging tool 100. Acoustic logging tool 100 may be operatively coupled to a conveyance 106 (e.g., wireline, slickline, coiled tubing, pipe, downhole tractor, and/or the like) which may provide mechanical suspension, as well as electrical connectivity, for acoustic logging tool 100.
  • a conveyance 106 e.g., wireline, slickline, coiled tubing, pipe, downhole tractor, and/or the like
  • Conveyance 106 and acoustic logging tool 100 may extend within conduit string 108 to a desired depth within the wellbore 110.
  • tubing may be concentric in the casing, however in other examples the tubing may not be concentric.
  • Conveyance 106 which may include one or more electrical conductors, may exit wellhead 112, may pass around pulley 114, may engage odometer 116, and may be reeled onto winch 118, which may be employed to raise and lower the tool assembly in the wellbore 110.
  • Signals recorded by acoustic logging tool 100 may be stored on memory and then processed by display and storage unit 120 after recovery of acoustic logging tool 100 from wellbore 110.
  • signals recorded by acoustic logging tool 100 may be conducted to display and storage unit 120 by way of conveyance 106.
  • Display and storage unit 120 may process the signals, and the information contained therein may be displayed for an operator to observe and stored for future processing and reference.
  • signals may be processed downhole prior to receipt by display and storage unit 120 or both downhole and at surface 122, for example, by display and storage unit 120.
  • Display and storage unit 120 may also contain an apparatus for supplying control signals and power to acoustic logging tool 100.
  • Typical conduit string 108 may extend from wellhead 112 at or above ground level to a selected depth within a wellbore 110.
  • Conduit string 108 may comprise a plurality of joints 130 or segments of conduit string 108, each joint 130 being connected to the adjacent segments by a collar 132. Additionally, conduit string 108 may include a plurality of tubing.
  • Figure 1 also illustrates inner conduit string 138, which may be positioned inside of conduit string 108 extending part of the distance down wellbore 110.
  • Inner conduit string 138 may be production tubing, tubing string, conduit string, or other pipe disposed within conduit string 108.
  • Inner conduit string 138 may comprise concentric pipes. It should be noted that concentric pipes may be connected by collars 132.
  • conduit string 108 may be comprised of inner conduit string 138.
  • a digital telemetry system may be employed, wherein an electrical circuit may be used to both supply power to acoustic logging tool 100 and to transfer data between display and storage unit 120 and acoustic logging tool 100.
  • a DC voltage may be provided to acoustic logging tool 100 by a power supply located above ground level, and data may be coupled to the DC power conductor by a baseband current pulse system.
  • acoustic logging tool 100 may be powered by batteries located within the downhole tool assembly, and/or the data provided by acoustic logging tool 100 may be stored within the downhole tool assembly, rather than transmitted to surface 122 during logging.
  • Acoustic logging tool 100 may be used for excitation of transmitter 102.
  • one or more receivers 104 may be positioned on the acoustic logging tool 100 at selected distances (e.g., axial spacing) away from transmitter 102.
  • the axial spacing of receiver 104 from transmitter 102 may vary, for example, from about 0 inches (0 cm) to about 40 inches (101.6 cm) or more.
  • at least one receiver 104 may be placed near the transmitter 102 (e.g., within at least 1 inch (2.5 cm) while one or more additional receivers may be spaced from 1 foot (30.5 cm) to about 5 feet (152 cm) or more from the transmitter 102.
  • acoustic logging tool 100 may include more than one transmitter 102 and more than one receiver 104.
  • acoustic logging tool 100 may include more than one transmitter 102 and more than one receiver 104.
  • an array of receivers 104 may be used.
  • Receiver 104 may include any suitable acoustic receiver suitable for use downhole, including piezoelectric elements that may convert acoustic waves into an electric signal.
  • Transmission of acoustic waves by the transmitter 102 and the recordation of signals by receivers 104 may be controlled by display and storage unit 120, which may include an information handling system 144.
  • the information handling system 144 may be a component of the display and storage unit 120.
  • the information handling system 144 may be a component of acoustic logging tool 100.
  • An information handling system 144 may include any instrumentality or aggregate of instrumentalities operable to compute, estimate, classify, process, transmit, receive, retrieve, originate, switch, store, display, manifest, detect, record, reproduce, handle, or utilize any form of information, intelligence, or data for business, scientific, control, or other purposes.
  • an information handling system 144 may be a personal computer, a network storage device, or any other suitable device and may vary in size, shape, performance, functionality, and price.
  • Information handling system 144 may include a processing unit 146 (e.g., microprocessor, central processing unit, etc.) that may process EM log data by executing software or instructions obtained from a local non-transitory computer readable media 148 (e.g., optical disks, magnetic disks).
  • Non-transitory computer readable media 148 may store software or instructions of the methods described herein.
  • Non-transitory computer readable media 148 may include any instrumentality or aggregation of instrumentalities that may retain data and/or instructions for a period of time.
  • Non-transitory computer readable media 148 may include, for example, storage media such as a direct access storage device (e.g., a hard disk drive or floppy disk drive), a sequential access storage device (e.g., a tape disk drive), compact disk, CD-ROM, DVD, RAM, ROM, electrically erasable programmable read-only memory (EEPROM), and/or flash memory; as well as communications media such wires, optical fibers, microwaves, radio waves, and other electromagnetic and/or optical carriers; and/or any combination of the foregoing.
  • Information handling system 144 may also include input device(s) 150 (e.g., keyboard, mouse, touchpad, etc.) and output device(s) 152 (e.g., monitor, printer, etc.).
  • input device(s) 150 e.g., keyboard, mouse, touchpad, etc.
  • output device(s) 152 e.g., monitor, printer, etc.
  • the input device(s) 150 and output device(s) 152 provide a user interface that enables an operator to interact with acoustic logging tool 100 and/or software executed by processing unit 146.
  • information handling system 144 may enable an operator to select analysis options, view collected log data, view analysis results, and/or perform other tasks.
  • FIG. 2 illustrates an example information handling system 144 which may be employed to perform various steps, methods, and techniques disclosed herein.
  • information handling system 144 includes a processing unit (CPU or processor) 202 and a system bus 204 that couples various system components including system memory 206 such as read only memory (ROM) 208 and random-access memory (RAM) 210 to processor 202.
  • system memory 206 such as read only memory (ROM) 208 and random-access memory (RAM) 210
  • processors disclosed herein may all be forms of this processor 202.
  • Information handling system 144 may include a cache 212 of high-speed memory connected directly with, in close proximity to, or integrated as part of processor 202.
  • Information handling system 144 copies data from memory 206 and/or storage device 214 to cache 212 for quick access by processor 202.
  • cache 212 provides a performance boost that avoids processor 202 delays while waiting for data.
  • These and other modules may control or be configured to control processor 202 to perform various operations or actions.
  • Other system memory 206 may be available for use as well. Memory 206 may include multiple different types of memory with different performance characteristics. It may be appreciated that the disclosure may operate on information handling system 144 with more than one processor 202 or on a group or cluster of computing devices networked together to provide greater processing capability.
  • Processor 202 may include any general purpose processor and a hardware module or software module, such as first module 216, second module 218, and third module 220 stored in storage device 214, configured to control processor 202 as well as a specialpurpose processor where software instructions are incorporated into processor 202.
  • Processor 202 may be a self-contained computing system, containing multiple cores or processors, a bus, memory controller, cache, etc.
  • a multi-core processor may be symmetric or asymmetric.
  • Processor 202 may include multiple processors, such as a system having multiple, physically separate processors in different sockets, or a system having multiple processor cores on a single physical chip.
  • processor 202 may include multiple distributed processors located in multiple separate computing devices but working together such as via a communications network. Multiple processors or processor cores may share resources such as memory 206 or cache 212 or may operate using independent resources.
  • Processor 202 may include one or more state machines, an application specific integrated circuit (ASIC), or a programmable gate array (PGA) including a field PGA (FPGA).
  • ASIC application specific integrated circuit
  • PGA programmable gate array
  • FPGA field PGA
  • the information handling system 144 may comprise a processor 202 that executes one or more instructions for processing the one or more measurements.
  • the information handling system 144 may comprise processor 202 that executes one or more instructions for processing the one or more measurements.
  • Information handling system 144 may process one or more measurements according to any one or more algorithms, functions, or calculations discussed below. In one or more embodiments, the information handling system 144 may output a return signal.
  • Processor 202 may include, for example a microprocessor, microcontroller, digital signal processor (DSP), application specific integrated circuit (ASIC), or any other digital or analog circuitry configured to interpret, execute program instructions, process data, or any combination thereof.
  • Processor 202 may be configured to interpret and execute program instructions or other data retrieved and stored in any memory such as memory 206 or cache 212.
  • Program instructions or other data may constitute portions of a software or application for carrying out one or more methods described herein, memory 206 or cache 212 may comprise read-only memory (ROM), random access memory (RAM), solid state memory, or disk-based memory.
  • Each memory module may include any system, device or apparatus configured to retain program instructions, program data, or both for a period of time (e.g., computer-readable non-transitory media). For example, instructions from a software or application may be retrieved and stored in memory 206 for execution by processor 202.
  • Each individual component discussed above may be coupled to system bus 204, which may connect each and every individual component to each other.
  • System bus 204 may be any of several types of bus structures including a memory bus or memory controller, a peripheral bus, and a local bus using any of a variety of bus architectures.
  • a basic input/output (BIOS) stored in ROM 208 or the like, may provide the basic routine that helps to transfer information between elements within information handling system 144, such as during start-up.
  • BIOS basic input/output
  • Information handling system 144 further includes storage devices 214 or computer-readable storage media such as a hard disk drive, a magnetic disk drive, an optical disk drive, tape drive, solid-state drive, RAM drive, removable storage devices, a redundant array of inexpensive disks (RAID), hybrid storage device, or the like.
  • Storage device 214 may include software modules 216, 218, and 220 for controlling processor 202.
  • Information handling system 144 may include other hardware or software modules.
  • Storage device 214 is connected to the system bus 204 by a drive interface. The drives and the associated computer-readable storage devices provide nonvolatile storage of computer-readable instructions, data structures, program modules and other data for information handling system 144.
  • a hardware module that performs a particular function includes the software component stored in a tangible computer-readable storage device in connection with the necessary hardware components, such as processor 202, system bus 204, and so forth, to carry out a particular function.
  • the system may use a processor and computer-readable storage device to store instructions which, when executed by the processor, cause the processor to perform operations, a method or other specific actions.
  • the basic components and appropriate variations may be modified depending on the type of device, such as whether information handling system 144 is a small, handheld computing device, a desktop computer, or a computer server.
  • processor 202 executes instructions to perform “operations”, processor 202 may perform the operations directly and/or facilitate, direct, or cooperate with another device or component to perform the operations.
  • information handling system 144 employs storage device 214, which may be a hard disk or other types of computer-readable storage devices which may store data that are accessible by a computer, such as magnetic cassettes, flash memory cards, digital versatile disks (DVDs), cartridges, random access memories (RAMs) 210, read only memory (ROM) 208, a cable containing a bit stream and the like, may also be used in the exemplary operating environment.
  • Tangible computer-readable storage media, computer-readable storage devices, or computer- readable memory devices expressly exclude media such as transitory waves, energy, carrier signals, electromagnetic waves, and signals per se.
  • an input device 222 represents any number of input mechanisms, such as a microphone for speech, a touch-sensitive screen for gesture or graphical input, keyboard, mouse, motion input, speech and so forth. Additionally, input device 222 may take in data from one or more sensors 136, discussed above.
  • An output device 224 may also be one or more of a number of output mechanisms known to those of skill in the art. In some instances, multimodal systems enable a user to provide multiple types of input to communicate with information handling system 144.
  • Communications interface 226 generally governs and manages the user input and system output. There is no restriction on operating on any particular hardware arrangement and therefore the basic hardware depicted may easily be substituted for improved hardware or firmware arrangements as they are developed.
  • each individual component described above is depicted and disclosed as individual functional blocks.
  • the functions these blocks represent may be provided through the use of either shared or dedicated hardware, including, but not limited to, hardware capable of executing software and hardware, such as a processor 202, that is purpose-built to operate as an equivalent to software executing on a general -purpose processor.
  • a processor 202 that is purpose-built to operate as an equivalent to software executing on a general -purpose processor.
  • the functions of one or more processors presented in Figure 2 may be provided by a single shared processor or multiple processors.
  • Illustrative embodiments may include microprocessor and/or digital signal processor (DSP) hardware, read-only memory (ROM) 208 for storing software performing the operations described below, and random-access memory (RAM) 210 for storing results.
  • DSP digital signal processor
  • ROM read-only memory
  • RAM random-access memory
  • VLSI Very large-scale integration
  • one or more parts of the example information handling system 144 may be virtualized.
  • a virtual processor may be a software object that executes according to a particular instruction set, even when a physical processor of the same type as the virtual processor is unavailable.
  • a virtualization layer or a virtual “host” may enable virtualized components of one or more different computing devices or device types by translating virtualized operations to actual operations. Ultimately however, virtualized hardware of every type is implemented or executed by some underlying physical hardware.
  • a virtualization computer layer may operate on top of a physical computer layer.
  • the virtualization computer layer may include one or more virtual machines, an overlay network, a hypervisor, virtual switching, and any other virtualization application.
  • Figure 3 illustrates another example information handling system 144 having a chipset architecture that may be used in executing the described method and generating and displaying a graphical user interface (GUI).
  • Information handling system 144 is an example of computer hardware, software, and firmware that may be used to implement the disclosed technology.
  • Information handling system 144 may include a processor 202, representative of any number of physically and/or logically distinct resources capable of executing software, firmware, and hardware configured to perform identified computations.
  • Processor 202 may communicate with a chipset 400 that may control input to and output from processor 202.
  • chipset 300 outputs information to output device 224, such as a display, and may read and write information to storage device 214, which may include, for example, magnetic media, and solid-state media. Chipset 300 may also read data from and write data to RAM 210.
  • a bridge 302 for interfacing with a variety of user interface components 304 may be provided for interfacing with chipset 300. Such user interface components 304 may include a keyboard, a microphone, touch detection and processing circuitry, a pointing device, such as a mouse, and so on. In general, inputs to information handling system 144 may come from any of a variety of sources, machine generated and/or human generated.
  • Chipset 300 may also interface with one or more communication interfaces 226 that may have different physical interfaces.
  • Such communication interfaces may include interfaces for wired and wireless local area networks, for broadband wireless networks, as well as personal area networks.
  • Some applications of the methods for generating, displaying, and using the GUI disclosed herein may include receiving ordered datasets over the physical interface or be generated by the machine itself by processor 202 analyzing data stored in storage device 214 or RAM 210. Further, information handling system 144 receives inputs from a user via user interface components 304 and executes appropriate functions, such as browsing functions by interpreting these inputs using processor 202.
  • information handling system 144 may also include tangible and/or non- transitory computer-readable storage devices for carrying or having computer-executable instructions or data structures stored thereon.
  • tangible computer-readable storage devices may be any available device that may be accessed by a general purpose or special purpose computer, including the functional design of any special purpose processor as described above.
  • tangible computer-readable devices may include RAM, ROM, EEPROM, CD-ROM or other optical disk storage, magnetic disk storage or other magnetic storage devices, or any other device which may be used to carry or store desired program code in the form of computer-executable instructions, data structures, or processor chip design.
  • Computer-executable instructions include, for example, instructions and data which cause a general-purpose computer, special purpose computer, or special purpose processing device to perform a certain function or group of functions.
  • Computer-executable instructions also include program modules that are executed by computers in stand-alone or network environments.
  • program modules include routines, programs, components, data structures, objects, and the functions inherent in the design of special-purpose processors, etc. that perform particular tasks or implement particular abstract data types.
  • Computer-executable instructions, associated data structures, and program modules represent examples of the program code means for executing steps of the methods disclosed herein. The particular sequence of such executable instructions or associated data structures represents examples of corresponding acts for implementing the functions described in such steps.
  • methods may be practiced in network computing environments with many types of computer system configurations, including personal computers, hand-held devices, multi-processor systems, microprocessor-based or programmable consumer electronics, network PCs, minicomputers, mainframe computers, and the like. Examples may also be practiced in distributed computing environments where tasks are performed by local and remote processing devices that are linked (either by hardwired links, wireless links, or by a combination thereof) through a communications network. In a distributed computing environment, program modules may be located in both local and remote memory storage devices.
  • FIG 4 is a schematic of a system 400 in which a pitch-catch (P-C) and pulse-echo (P-E) receiver configurations may be utilized by acoustic logging tool 100 (e.g., referring to Figure 1) concurrently during measurement operations.
  • P-C pitch-catch
  • P-E pulse-echo
  • FIG. 4 illustrates potential ray paths of Ao mode, leaked, and reflected Ao energy from cement-formation interface in accordance with measurement operations that may be performed and/or described in the present disclosure.
  • P-C Transmitter 402 which operates and functions according to the description above regarding transmitter 102, emits pulsed acoustic waves to obtain acoustic cement evaluation measurements through P-C receiver 406.
  • the distance between P-C transmitter 402 and P-C receiver 406 may be from about 0.1 inch (0.254 cm) to about 30 inches (76.2 cm), or from about 4 inches (10.16 cm) to 27.5 inches (69.85 cm), or from about 6 inches (15.24 cm) to 25 inches (63.5 cm), or from about 8.5 inches (21.6 cm) to 20 inches (50.8 cm) and from about 8.5 inches (21.6 cm) to 15 inches (38.1 cm) according to embodiments of the present disclosure.
  • P-E transceiver 404 may transmit ultrasonic or sonic acoustic waves into casing 408. The reflection of the acoustic waves, the echo, may be measured by P-E transceiver 404 for cement evaluation.
  • Flexural attenuation is one of the cement evaluation measurements as flexural attenuation is a function of acoustic impedance on both sides of casing 408, and therefore depends on the material properties of cement 410 on the other side of casing 408 and is sensitive to the interface between cement 410 and formation 412.
  • an ultrasonic acoustic downhole tool may emit pulses in the range of a few hundred kilohertz, for example.
  • the cement 410 sheath behind casing 408 is evaluated by sending a short pressure pulse toward casing wall that excites elastic waves inside casing 408. The propagation of these waves is strongly affected by casing 408 -cement 410 bond quality and the cement 410 properties.
  • An acoustic beam at oblique incidence onto casing 408 excites modes of the family of Lamb waves, which are predominantly the zeroth-order antisymmetric (flexural) and symmetric (extensional) modes. Based on the zeroth-order antisymmetric (flexural) mode response, such as the flexural attenuation, the quality of cement 410 installation may be estimated. These wave modes are collected using the pitch-catch source and receiver combinations oriented appropriately governed by dispersion equations detailed below.
  • casing 408 When casing 408 is excited using acoustic waves (ultrasonic and/or sonic) incident on it at angles necessary to generate flexural wave mode in casing 408, some portion of the energy leaks into the annulus and gets reflected by the cement-formation interface. If there are defects in the annulus in between casing and cement-formation interface, some energy also gets reflected by those defects. These reflections travel to P-C receiver 406 and the defects may create a signature waveform, separate and apart from all other captured waveforms, that may be studied. If one waveform from each acquisition at every depth and azimuth is taken and all such waveforms are displayed together after sorting based on depth or azimuth, then a structural image of the annulus may be created and interpreted.
  • acoustic waves ultrasonic and/or sonic
  • Such an image may be a time domain image because of the waveforms being time domain traces.
  • signature waveforms may be displayed on the time domain traces, which may relate to physical structures based on an approximate understanding of travel times.
  • a more direct interpretation is possible from an image that has been converted to radial distance from the center of the well.
  • Such conversion needs an estimate of the average or stacking velocity of the annular material all the way to the cement-formation interface.
  • An estimate of the velocity that is valid only close to casing 408 may lead to an inaccurate conversion of time to radial distance for structures away from the immediate neighborhood of casing 408.
  • a method to estimate a velocity of the annular material from the waveforms data collected on multiple receivers which is an average velocity of the entire material in the annulus and not just of the material right next to casing 408.
  • the method utilizes reflections of leaked A o mode energy from the cement-formation interface or from the cement-second casing interface in a double casing scenario and is based on creating semblance maps and picking velocities and annular thicknesses that maximize semblance.
  • the semblance value may be defined as the sum of the amplitude of the flexural mode response along a travel time curve computed using Equation (1) or Equation (2) described below.
  • an ultrasonic tool with transducers oriented to excite and receive Ao mode can acquire waveform data in multiple receivers in an array.
  • the acquisition can be assumed to be a 2D acquisition for the purpose of analysis.
  • the array data can be utilized to create semblance maps by stacking amplitudes picked from the waveforms at time samples determined by travel time equation for leaked Ao mode that reflects from cement-formation interface. Such reflections can have all the segments of the overall ray path as compressional- compressional wave modes denoted as CC in the following travel time equation:
  • Equation (1) Nfl ex is determined using dispersion equations and casing elastic properties.
  • these reflections can have the overall ray path comprised of a combination of compressional waves which get converted into shear waves after hitting the cement-formation interface or cement-second casing interface. These waves are modeled as compressional-shear plus shear-compressional wave modes denoted CS + SC wave modes. The corresponding travel time equation is given as follows:
  • Equation (2) may be used for the travel time equation if the CS+SC wave mode is relatively strong compared to CC wave mode. If the compressional wave velocity of the cement is not close to the shear wave velocity of the casing, then Equation (1) may be used for the travel time equation.
  • the travel time equation depends upon the elastic properties of the media in which the waves travel and on the physical dimensions of the layers including the annulus.
  • the objective is to find the values of the compressional wave velocity and the thickness of the annulus for which the semblance maximizes.
  • travel times are computed for a range of annular thicknesses and compressional wave velocities and then amplitudes are stacked along the travel time curves from the array of waveform data to get a semblance map with annular thickness and annular compressional wave velocities as two axes.
  • Equation (2) the Vp/Vs ratio for the cement is assumed based on available cement reports. There can be multiple thicknesses and compressional wave velocities for which semblance values may be high and comparable.
  • the top multiple solutions are chosen, and the mean and standard deviation are calculated for the annular thickness and compressional wave velocities.
  • the mean values can be used to create a velocity profile that may be further used to convert time domain images into radial distance domain images.
  • the compressional wave velocity determined on the basis of semblance map can be called as stacking velocity because the semblance map is created by stacking or summing amplitudes from array waveforms. As Ao mode travels along the casing and leaks into the annulus, its phase spectrum changes along the array. This phenomenon helps reduce uncertainty on the semblance map.
  • Figure 5 is a workflow 500 of an example of a procedure according to some embodiments of the present disclosure.
  • workflow 500 may be performed on information handling system 144 (e.g., referring to Figure 1).
  • variables may be measured and/or chosen related to the array setup (the distance between P-C transmitter 402 and P-C receiver 406 (referring to Figure 4), and their configuration (pitch-catch or pulse-echo)), the logging fluid, and the casing properties are identified by personnel from measurements, databases, personnel selection, and/or any combination thereof.
  • a decision must be made on which equation should be used in the process of creating a semblance map depending upon the type of cement used in the annulus.
  • Equation (2) may be used for the travel time equation. If the compressional wave velocity of the cement is not close to the shear wave velocity of the casing, then Equation (1) may be used for the travel time equation. If Equation (2) is used, then the V P /V S ratio for the cement is assumed based on available cement reports.
  • a computed travel time is calculated based on Equation (1) or (2) described above. Equation (1) or (2) is used to compute the leaked and reflected wave mode travel time for a specific thickness of the cement, cement velocity (already obtained from semblance analysis), and the specific input variables that were measured and/or selected in step 502.
  • step 506 if the computed travel time matches the measured travel time of the analyzed return signal, waveform amplitude, corresponding to the computed travel time in step 504, is picked and stored. This waveform amplitude then becomes the amplitude corresponding to that cement thickness. This calculation is repeated for multiple thicknesses by small increments in step 508.
  • step 510 a decision must be made on whether the calculations have been performed for a cement thick enough to be representative of downhole conditions. A 7-inch-thick (17.8 cm-thick) cement may be considered thick enough for some operators. Others may consider a 6-inch-thick (15.2 cm- thick) cement is enough to perform its duties.
  • a thickness ranging from about 3 inches (7.62 cm) to about 7 inches (17.8 cm), or from about 3.25 inches (8.3 cm) to about 6 inches (15.2 cm), or from about 3.5 inches (8.9 cm) to about 5 inches (12.7 cm) may be considered a range of maximum annular thickness for cement. If enough calculations have been performed (i.e., operators can choose between a 3-inch-thick (7.62 cm) cement and a 7-inch (17.8 cm) thick cement), then the procedure ends in step 512. Otherwise, the procedure goes back to step 506. Thus, a time domain waveform is converted to a distance domain waveform because now every annular thickness (and hence distance from casing) has an amplitude stored for it.
  • Figure 6 shows examples of waveform data collected using an array of transmitter and receivers as described in Figure 4 above with water as logging fluid and cement in the annulus following the procedure described in Figure 5 above.
  • Ao mode and leaked Ao energy reflected by the cement-formation interface can be identified on the waveforms.
  • the rectangle frame around the data in Figure 6 corresponds to the echo or reflection due to the third interface, which is a cement-second casing interface in this example.
  • the annular thickness was 3 inches (7.6 cm), and the annulus contained a cement with cement velocity of approximately 2600 m/s. Travel time curves have been plotted on the array dataset to mark the time location of the wave modes of interest.
  • Such a collection of waveforms comprises one data acquisition and is used to create semblance map and derive velocity at one location. Such collection of waveforms is obtained at each combination of depth and azimuth.
  • Figure 7 is a semblance map created using the array data of Figure 4 for a range of annular thicknesses and cement velocities following the procedure described in Figure 5.
  • the top solutions based on semblance values are picked from the semblance map and the mean of the annular thicknesses and cement velocities corresponding to the highest probability to obtain the semblance value is taken as the final solution.
  • the annular thickness and compressional wave velocity are used to create a velocity profile in combination with casing and logging fluid layer thickness and sound speed to convert the time domain structural images into a radial distance domain of the annulus. This process can be repeated for every depth and azimuth to create a velocity profile at each depth and azimuth in a logging operation.
  • Figure 8 shows a conversion of time domain images into radial distance domain images according to embodiments of the present disclosure.
  • Water was used as logging fluid and cement was used in the annulus in this example.
  • the conversion is performed using the semblance map of Figure 7 using the data acquired with apparatus as described in Figure 4 above following the procedure as described in Figure 5.
  • the radial distance domain image of Figure 8 was started from the casing-logging fluid interface. From the radial distance image, the annular thickness can be directly interpreted to be approximately 3.2 inches (8.1 cm), which is close to the true value of 3 inches (7.6 cm) used in the example.
  • the semblance-based method can provide a good estimate of the annular velocity until the cement-formation interface from the data collected by the multi -receiver array. It may be extended to concentric multi-casing scenarios instead of a single casing scenario. Computation of semblance from CC or CS+SC modes is contingent to the type of cement under consideration. If CS+SC mode is used, then the ratio between compressive velocity and shear velocity (V P /V S ) for the cement can be deducted based on the available cement report.
  • compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods may also “consist essentially of’ or “consist of’ the various components and steps.
  • indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the elements that it introduces.
  • the systems and methods may comprise any of the various features disclosed herein, comprising one or more of the following statements.
  • a method of determining a cement integrity behind a conduit string using acoustic signals comprising: transmitting an acoustic signal into at least part of a conduit string; measuring a return signal from at least part of the conduit string; analyzing the return signal; computing travel times for leaked and reflected waves for a range of annular thicknesses and compressional wave velocities; comparing the computing travel times with the analyzed return signal; and plotting a semblance map of annular thicknesses as a function of compressional wave velocities.
  • Statement 2 The method of Statement 1, wherein the acoustic signals are obtained from an acoustic logging tool in a pitch-catch (P-C) receiver configuration.
  • P-C pitch-catch
  • Statement 3 The method of Statement 1 or Statement 2, wherein the acoustic signals are obtained from an acoustic logging tool in a pitch-catch (P-C) receiver configuration, wherein the distance between a P-C transmitter and a P-C receiver is from about 6 inches to about 20 inches.
  • P-C pitch-catch
  • Statement 4 The method of any one of Statements 1-3, wherein the acoustic signals are obtained from an acoustic logging tool in a pitch-catch (P-C) receiver configuration, wherein a distance between a P-C transmitter and a P-C receiver is from about 8.5 inches to about 15 inches.
  • Statement 5. The method of any one of Statements 1-4, further determining if a compressional wave velocity of the cement is close to a shear wave velocity of the conduit string to select a travel time equation to create a semblance map.
  • Statement 6 The method of any one of Statements 1-5, further computing travel times for leaked and reflected waves for a range of annular thicknesses and compressional wave velocities to get a semblance map with annular thickness and annular compressional wave velocities as two axes.
  • Statement 7 The method of any one of Statements 1-6, further plotting a semblance map for a range of annular thicknesses and cement velocities, picking a top solution based on semblance values from the semblance map, and taking the corresponding annular thickness and cement velocity.
  • Statement 8 The method of any one of Statements 1-7, further creating a velocity profile based on a combination of conduit string material properties, logging fluid layer thickness, logging fluid sound speed, annular thickness, and compressional wave velocity, and converting a time domain structural image into a radial distance domain image of an annulus.
  • Statement 9 The method of any one of Statements 1-8, further repeating the creation for every depth and azimuth to create a velocity profile as a function of depth and azimuth in a logging operation.
  • a method of determining a cement thickness and velocity of a wave propagation comprising: a), transmitting an acoustic signal into at least part of a conduit string; b). measuring a return signal from at least part of the conduit string; c). computing one or more amplitudes of a resonate signal from the return signal; d). calculating a semblance for a range of annular thicknesses and cement velocities; e). plotting a semblance map as a function of cement thickness and cement velocity; f). calculating a mean cement thickness and velocity based on semblance values; and g). converting a time domain image to a radial distance domain image using the mean cement thickness and velocity.
  • Statement 11 The method of Statement 10, further repeating steps a) through g) at several depths and azimuths to obtain a 3D radial distance domain image.
  • Statement 12 The method of Statement 10 or Statement 11, further determining if a compressional wave velocity of the cement is close to a shear wave velocity of the conduit string to select a travel time equation to create the semblance map.
  • Statement 13 The method of any one of Statements 10-12, wherein the acoustic signal is obtained from an acoustic logging tool in a pitch-catch (P-C) configuration.
  • Statement 14 The method of any one of Statements 10-13, wherein the acoustic signals are obtained from an acoustic logging tool in a pitch-catch (P-C) configuration, wherein a distance between a P-C transmitter and a P-C receiver is from about 4 inches to about 30 inches.
  • P-C pitch-catch
  • Statement 15 The method of any one of Statements 10-14, wherein the acoustic signals are obtained from an acoustic logging tool in a pitch-catch (P-C) configuration, wherein a distance between a P-C transmitter and a P-C receiver is from about 6 inches to about 20 inches.
  • P-C pitch-catch
  • Statement 16 The method of any one of Statements 10-15, wherein the acoustic signals are obtained from an acoustic logging tool in a pitch-catch (P-C) configuration, wherein a distance between a P-C transmitter and a P-C receiver is from about 8.5 inches to about 15 inches.
  • P-C pitch-catch
  • Statement 18 The system of Statement 17, wherein the acoustic signals are obtained from an acoustic logging tool in a pitch-catch (P-C) configuration, wherein a distance between a P-C transmitter and a P-C receiver is from about 4 inches to about 30 inches.
  • P-C pitch-catch
  • Statement 19 The system of Statement 17 or Statement 18, wherein the acoustic signals are obtained from an acoustic logging tool in a pitch-catch (P-C) configuration, wherein a distance between a P-C transmitter and a P-C receiver is from about 6 inches to about 20 inches.
  • Statement 20 The system of any one of Statements 17-19, wherein the acoustic signals are obtained from an acoustic logging tool in a pitch-catch (P-C) configuration, wherein a distance between a P-C transmitter and a P-C receiver is from about 8.5 inches to about 15 inches.
  • ranges from any lower limit may be combined with any upper limit to recite a range not explicitly recited, as well as, ranges from any lower limit may be combined with any other lower limit to recite a range not explicitly recited, in the same way, ranges from any upper limit may be combined with any other upper limit to recite a range not explicitly recited.
  • any numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range are specifically disclosed.
  • every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values even if not explicitly recited.
  • every point or individual value may serve as its own lower or upper limit combined with any other point or individual value or any other lower or upper limit, to recite a range not explicitly recited.

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Abstract

L'invention concerne des systèmes et des procédés de détermination de l'intégrité du ciment derrière une colonne de tubage à l'aide de signaux acoustiques dans le domaine du forage et des complétions de puits. En particulier, les systèmes et les procédés évaluent l'interface entre le ciment et la formation et/ou la seconde colonne de ciment et déterminent l'épaisseur du ciment. Des données sont traitées pour déterminer des vitesses d'onde de compression annulaires dans un puits tubé à l'aide d'un procédé de semblance ou par empilement de l'amplitude de l'énergie de mode A0 ayant fui qui a été réfléchie par la formation de ciment ou l'interface de la seconde colonne de ciment. La vitesse d'onde de compression annulaire est nécessaire pour convertir des images de domaine temporel de l'espace annulaire en images de domaine de distance radiale pour une meilleure interprétation de conditions annulaires. Un procédé de semblance est utilisé pour déterminer une estimation de vitesse pour l'espace annulaire et l'épaisseur annulaire. Le procédé de semblance est utilisé pour toutes les profondeurs et azimuts pour créer des images de domaine de distance radiale détaillées de l'anneau dans des puits tubés.
PCT/US2023/079628 2023-10-25 2023-11-14 Détermination de vitesse d'empilement annulaire basée sur la semblance d'ondes de flexion en fuite dans des puits tubés Pending WO2025090097A2 (fr)

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US18/494,208 US20250137368A1 (en) 2023-10-25 2023-10-25 Leaky Flexural Wave Semblance Based Annular Stacking Velocity Determination In Cased Wells
US18/494,208 2023-10-25

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US9772419B2 (en) * 2014-03-10 2017-09-26 Read As Decomposing full-waveform sonic data into propagating waves for characterizing a wellbore and its immediate surroundings
WO2019200242A1 (fr) * 2018-04-12 2019-10-17 Schlumberger Technology Corporation Évaluation de ciment de tubage à l'aide d'une détection automatisée d'arrivées d'ondes de compression d'accrochage (p)
US11661837B2 (en) * 2018-08-31 2023-05-30 Halliburton Energy Services, Inc. Cement bonding evaluation with a sonic-logging-while-drilling tool
GB2609627A (en) * 2021-08-09 2023-02-15 Equanostic As Method for determining if a wellbore consists of micro annulus, free pipe or solid bonding between the wellbore and a casing
US11746644B2 (en) * 2021-12-02 2023-09-05 Halliburton Energy Services, Inc. Measuring low-frequency casing guided waves to evaluate cement bond condition behind casing in the presence of a tubing

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