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    • 专利摘要:
    Techniques for facilitating the use of a distributed vibration sensing system for collecting data in a wellbore application to provide improved strain data collection, such as for seismic survey, are provided. The techniques facilitate the selection of an optimal variable reference length which optimally preserves the signal bandwidth and the time resolution of the detection system and which can be adjusted using the actual apparent speed and the maximum recoverable frequency. monitored parameters. The invention also relates to real-time processing techniques of DVS data using a preliminary variable optimal reference length, as well as techniques for further processing of the DVS data at a later time using an updated variable maximum reference length which is derived from the preliminary processing of DVS data.
    公开号:FR3077142A1
    申请号:FR1900557
    申请日:2019-01-22
    公开日:2019-07-26
    发明作者:Theo Cuny；Ali Ozbek；Arthur Hartog
    申请人:Services Petroliers Schlumberger SA；
    IPC主号:
    专利说明:

    Title of the invention: OPTIMIZATION OF A REFERENCE LENGTH FOR SIGNAL PRESERVATION PURPOSES AND
    TREATMENT OF A REFERENCE LENGTH AT
    DISTRIBUTED VIBRATION DETECTION PURPOSES
    BACKGROUND OF THE INVENTION Hydrocarbon fluids, such as petroleum and natural gas, are obtained from an underground geological formation, called reservoir, by drilling a well which penetrates into the formation containing the hydrocarbons . Once a wellbore is drilled, additional training and wellbore information can be obtained using a wired line tool, that is, a tool routed into the well via a wired line, in order to prepare a production, to know more precisely the formation or to ensure that the well is consolidated. After that, various forms of well completion components can be installed in the well in order to control and improve the production efficiency of various fluids from the reservoir. Information from the wells may be useful, but reliably obtaining useful information from the well can be difficult.
    One way in which information can be obtained from a well is to use a distributed optical fiber detection system, such as an acoustic detection or distributed vibration system. The detection system can be, for example, permanently installed as part of the well completion components or can be lowered into the well with the cable line tool, as part of the cable line. More generally, the detection system can be lowered into the wellbore on any type of transport system (smooth cable, spiral tube, etc.) or component. Fiber optic sensors use the fact that environmental effects, such as pressure, stress, vibration and temperature, can alter the amplitude, phase, frequency, spectral content or polarization of light propagating through an optical fiber. The advantages of fiber optic sensors include their light weight, small size, passive nature, energy efficiency and robustness. In addition, fiber optic sensors can potentially have very high sensitivity and wide bandwidth. In addition, certain classes of sensors can be distributed along the length of an optical fiber so that a suitable interrogation system can be used to monitor selected environmental parameters at continuous locations at the same time. For example, when deployed in a hydrocarbon well, a fiber optic sensor can provide indications of fluid production characteristics, such as temperature, fluid composition, density, viscosity, flow rate , etc. Or the sensor can provide information indicating the operating status of downhole components, for example by monitoring vibrations in the region near the components. In addition, the sensor can provide information regarding features of the earth formation penetrated by the well, such as monitoring for seismic events.
    Brief Description of the Drawings [0003] Certain embodiments of the invention are described with reference to the accompanying drawings, in which identical reference numbers indicate identical elements. It is understood, however, that the accompanying drawings illustrate only the various implementations described in this document and are not intended to limit the scope of the various technologies described in this document. The drawings show and describe various embodiments of the present invention.
    [Fig-1] is a schematic representation of an example of a well system which includes a distributed vibration detection system (hereinafter "DVS"), according to one embodiment.
    [Fig.2] is a schematic representation of an example of a control system which can be used in conjunction with the DVS system of Figure 1, according to one embodiment.
    [Fig. 3] is a graphic illustration of criteria selected to define variable optimal reference length values, according to one embodiment.
    [Fig.4] is a graphic illustration of an example of a relationship between a variable optimal reference length determined using the criteria of Figure 3 and the smallest input wavelength, according to one embodiment .
    [Fig.5] is an example of a workflow for generating differentiated DVS phase data using a fixed reference length.
    [Fig. 6] is an example of a workflow for generating differentiated DVS phase data using a profile of variable optimal reference length, according to one embodiment.
    [Fig.7] is an example of a workflow for processing DVS data in real time using a profile of preliminary variable optimal reference length, according to one embodiment.
    [Fig. 8] is another example of a workflow for a new processing of DVS data using a new profile of variable optimal reference length which is created on the basis of the preliminary processing of DVS data in accordance with the flow of work of Figure 7, according to one embodiment.
    SUMMARY Certain embodiments of the present disclosure relate to a method for use in a well which includes deploying an optical fiber along well equipment and positioning the equipment in a well. drilling that penetrates a region of interest. The optical fiber is connected to a distributed vibration detection system, and a length of the fiber is used to detect an indication of a vibration signal in the region of interest. A wavelength of interest of the signals to be detected is selected as a function of the length of the optical fiber to create a variable reference length profile. The profile has reference length values to be applied to phase data acquired from the detected signals. The values vary depending on the length of the optical fiber. The variable reference length profile is used to process the phase data acquired from the optical fiber, where a reference length value associated with a particular section of the optical fiber is used to process the phase data acquired from of this particular section.
    Embodiments also relate to a method which includes deploying a distributed vibration detection system to detect incident dynamic stress along the length of an optical fiber. The method also includes creating a variable reference length profile to generate optimal reference length values adjusted for corresponding sections of the optical fiber. The profile is created by selecting, for each section of the optical fiber, the smallest wavelength of the signal causing the dynamic stress experienced by this section of the optical fiber.
    Embodiments also relate to a method which includes deploying a distributed vibration detection system to detect incident dynamic stress along the length of an optical fiber, and creating a length profile Preliminary variable reference length to define preliminary optimal reference length values adjusted for corresponding sections of the optical fiber. A set of differentiated phase data is generated by applying preliminary values to optical data acquired from the optical fiber which indicates the detected dynamic stress.
    Description of the Embodiments In the following description, many details are presented to provide an understanding of the present disclosure. However, those skilled in the art will understand that the embodiments of this disclosure can be practiced without these details and that many variations or modifications from the described embodiments may be possible.
    In the description and the appended claims: the terms "connect", "connection", "connected", "in connection with" and "connecting" are used to mean "in direct connection with" or "in connection with via one or more elements ”; and the term "together" is used to mean "one item" or "more than one item". In addition, the terms "couple", "coupling", "coupled", "coupled together" and "coupled to" are used to mean "directly coupled together" or "coupled together via one or more elements". As used in this document, the terms "up" and "down", "up" and "down", "up" and "down", "upstream" and "downstream" ; "Above" and "below"; and other equivalent terms indicating relative positions above or below a given point or element are used in the description to more clearly describe certain embodiments of the invention.
    The present disclosure relates generally to systems and methods that facilitate the use of a distributed vibration detection system to collect data. For example, the distributed vibration detection system can be used in a well application to obtain improved collection of stress related data, for example for seismic prospecting. To this end, the techniques described in this document facilitate the selection of a desired reference length which optimally preserves the bandwidth of a signal and the time resolution of the detection system and which can be adjusted using the apparent speed and the maximum recoverable frequency of the monitored parameters. The optimal reference length may vary depending on specific factors, such as depth within a well, speed and bandwidth, and the present technique takes such factors into account when selecting a reference length which optimizes data collection.
    The present disclosure also introduces a technique for processing the data collected by the distributed vibration system which allows the reference length to change along the optical fiber so that the reference length can be optimized locally rather than represent an overall trade-off that is used regardless of the location along the entire sensing fiber. In addition, multiple techniques for processing distributed vibration data are disclosed which provide a better set of data at the well site and / or during further processing, for example, in the geophysicist's office. or at another location distant from the well site.
    In general, optical fiber monitoring systems, in particular distributed optical fiber monitoring systems, use an optical source (for example, a laser) to generate pulses of optical energy to be sent into an optical fiber that is deployed in a region of interest (for example, in a wellbore). As the pulses sent move along the length of the optical fiber, small imperfections in the fiber reflect part of the pulses, generating a backscatter. When the fiber is stressed (for example from vibration or acoustic signals propagating through the region of interest), the distances between the imperfections change. Therefore, the backscattered light also changes. By monitoring changes in the backscattered light generated by the fiber in response to interrogation pulses, it is possible to determine the dynamic stress, or vibration, experienced by the fiber. The stress or vibration measured can then be used to derive information about the parameters of interest, such as the characteristics of a surrounding earth formation.
    One type of fiber optic monitoring system is called a distributed vibration detection system (DVS) or, alternatively, a distributed acoustic detection system (DAS). For convenience, both the DVS and DAS systems are referred to generally in this document as the DVS system. DVS systems have been used to efficiently collect seismic data in applications such as pipeline safety monitoring and vertical seismic profiling. DVS systems have also been deployed to monitor fluid flow in underground boreholes.
    In DVS systems, a narrow band laser is generally used as an optical source to generate pulses of interrogation light to be sent into the detection fiber. The use of a narrow band laser causes interference between backscatter from different parts of the fiber which are occupied by a probe pulse at any time. This is a form of multipath interference and gives rise to a one-dimensional scab signal (along the fiber axis), sometimes called Rayleigh coherent noise or coherent backscatter. The term “phase-OTDR (optical reflectometry in the time domain)” is also used in this context. Interference modulates both the intensity and phase of the backscattered light and tiny changes ("wavelength") in the length of a section of a fiber are enough to drastically change the value of the amplitude and phase. Therefore, the technique can be useful for detecting small stress changes.
    However, the local amplitude (proportional to the square root of the intensity) or the phase, which can be measured locally with respect to specific locations on the detection fiber, has a strongly non-linear relationship with the stress. applied. On the contrary, the measurement of the phase difference over a length of the fiber gives a more linear transfer function between the stress and the phase difference and is therefore chosen as an indicator for detecting stress changes. The phase difference can be measured in the electrical or digital domains by mixing the backscattered light with a local oscillator which converts the scattered light, including its phase, into a frequency that can be captured electronically. The phase difference can then be calculated in the digital domain or by an analog phase measurement circuit before digitization.
    In another example, the phase of the scattered light returning from two separate locations can be compared in the optical domain with a phase detection interferometer which includes a delay line fiber which causes mixing at the level of the detector. the backscattered light returning from two separate locations in the fiber. Another approach is to send pairs of sounding pulses separated by a defined frequency and a sending time, thereby giving two sets of backscatter signals at different frequencies which combine at the detector to form a beat frequency . The backscatter signals arriving at the detector were broadcast from slightly different locations in the fiber which are separated by AL = AT * c / (2 * Ng), where "ΔΤ" is the temporal separation of the sounding pulses , "C" is the speed of light in a vacuum, and "Ng" is the group index of the fiber. Another approach is to modulate the phase of one of a pair of pulses so that the phase of the second pulse, relative to that of the first, varies in a predefined fashion with each repetition of the sequence d pulses (for example, the relative phase of the pulses is shifted by a quarter of a cycle between repetitions of the pulse sequence). Regardless of how the phase is acquired, these differential phase techniques involve comparing the phase at two locations in the fiber separated by what is sometimes known as "reference length" or "d 'differentiation interval'.
    Techniques for selecting a reference length (also referred to in this document as "GL") in order to obtain an optimal compromise between the spatial resolution of a DVS system and the signal to noise ratio (RSB) in a application for seismic drilling of wells are disclosed in international publication No. WO 2016/112147 A1, published July 14, 2016. According to these techniques, a reference length is selected using the equation 1 below · _ .. V mir! (1)
    GL = ratio x • dom where “V min ” is the minimum wave speed of the monitored parameter, for example a seismic wave; and "f dom " is the dominant frequency of the monitored parameter. In the disclosed embodiments, the input wavelength is defined by n and 1 dom is a wavelength of interest of the seismic wave. In particular, the "ratio" is in a range between 0.3 to 0.6 so that the SNR is greater than a target value and the difference between the output (measured) and input wavelength is less than another target value. Generally, GL is selected to be 0.6 times the input wavelength in applications where RSB is the primary consideration (and spatial resolution is considered to be unimportant or less important ).
    Although the use of equation 1 to select a desired GL effectively improves the SNR, in certain applications, it can also present an excessively large compromise with regard to the bandwidth of the signal and can therefore potentially affect the reliability of temporal data recording.
    Consequently, the embodiments disclosed in this document relate to the selection of a desired GL which preserves the RSB as in the prior art while also protecting the bandwidth of the signal.
    Another potential drawback of selecting a GL according to equation 1 is that it involves the use of a single GL for the entire data set, which limits its definition by associating it with the minimum apparent wave speed and at the dominant frequency. However, in embodiments involving seismic drilling of wells where the speed of the seismic wave varies with depth, the selection of a single GL may not be optimal for all sections of the sensing fiber. For example, if the GL is selected to be optimal for the lower section of the fiber, the GL may be sub-optimal for the upper section because of the different wave velocities. This can lead to over-data for the upper section of the fiber because the GL is too long, or under-smoothing if the GL is too short, and therefore have a detrimental impact on the quality of the data acquired when the speed of the seismic waves varies. on the different sections of the wellbore.
    Therefore, embodiments disclosed in this document relate to a treatment approach where the optimal GL is changed along the length of the fiber, thereby facilitating the selection of a local optimal GL based on '' an actual local speed and frequency. This approach locally improves the RSB and preserves the signal, rather than the selection of a GL based on a global compromise. Techniques for processing a DVS dataset in real time (for example, at the well site) and / or at a later time (for example, remote from the well site) using a selected optimal GL that varies the along the length of the fiber are also disclosed.
    Referring to Figure 1, an example of a well system 20 comprising a DVS system 22 is illustrated. In this embodiment, the DVS system 22 includes an optical fiber 24 used to obtain data, for example strain data. The optical fiber 24 can be in the form of a cable and can be coupled to an interrogation unit 26. For some applications, the interrogation unit 26 includes a detector for monitoring backscatter signals. In addition, the interrogation unit 26 may include a suitable optical source, for example a narrow band laser, to establish interference between the backscatter signals returned from different parts of the fiber 24. For example, the interrogation unit 26 can be used to provide a sounding signal sent along fiber 24 via the laser. The interrogation unit 26 can also be part of or be coupled to a processor-based control system 28 used to process the collected data.
    In the specific example illustrated in Figure 1, the fiber 24 is deployed along a well equipment 30. For example, the well equipment 30 may include a well train 32, for example a production tube, and the fiber 24 can be fixed along the well train 32. Depending on the application, the fiber 24 can be glued or otherwise fixed to the well train 32 in order to facilitate the monitoring of the stresses due to vibrations from seismic waves, fluid flow and / or other sources. In another example (not shown in Figure 1), the well equipment may include a wired line tool and a wired line cable to transport the wired line tool, and the fiber may be connected to the line cable cable. As illustrated, the well string 32 can be deployed in a wellbore 34, although the DVS system 22 can be used in other well applications and in applications not involving a well.
    The data obtained by the DVS 22 system can be processed according to various methods as described above. In addition, the data can be processed in whole or in part on a processor-based control system 28. An example of a processing system 28 is illustrated in FIG. 2 and can be in the form of a computer system having a processor 36, for example a central processing unit (CPU). The processor 36 can be operatively used to assimilate data from the fiber 24/1 interrogation unit 26 and to process the data. Depending on the application, data processing may involve the execution of various models / algorithms relating to the evaluation of signal data, for example backscatter data, received from the detection fiber 24. As For example, the data can be processed to determine suitable values, for example optimal values, of reference lengths for the DVS system 22 for corresponding sections of the fiber 24, as will be described in more detail below. referring to the various equations and the various workflows presented below.
    The processor 36 can be operatively coupled to a memory 38, an input device 40 and an output device 42. The input device 40 can include various devices, such as a keyboard, a mouse, a voice recognition unit, a touch screen, other input devices or a combination of these devices. The output device 42 may include a visual and / or audio output device, such as a computer screen, monitor or other display medium having a graphical user interface. In addition, the treatment can be performed on a single device or on multiple devices on site, away from the location of the well or with certain devices on site and other devices located remotely. As soon as the desired signal processing has been carried out to evaluate the vibrations / stresses to determine the desired reference length values, the processed data, the results, the analysis and / or the recommendations can be displayed on output 42 and / or stored in memory 38.
    In embodiments disclosed in this document, the criteria which have been selected to define the optimality of the reference length are based on the preservation of the data and on metrics which have a clear meaning for the geophysicist and other users of the DVS system. When selecting criteria, optical preprocessing of the DVS data set was generally assumed to be non-linear.
    To determine the criteria for optimality, a Klauder wavelet model was used to control both the speed of arrival of the seismic wave and its bandwidth (low and high frequency). After the generation of simple synthetic geophysics, it was introduced into a mathematical model of DVS physics to produce a synthetic optical signal, which was then introduced into a standard optical processing algorithm. As GL is one of the parameters of this processing, the impact of GL on the data could be studied while varying the geophysical parameters of the model.
    Using this approach, the effect of GL on the output DVS dataset was studied and compared to the geophysical model. This resulted in the definition of three criteria for selecting optimal GLs, which are the increase in bandwidth at the lowest frequency ("LF increase") (50), the attenuation at the highest frequency (" HF attenuation ”) (52) and the loss of time resolution of the output time wavelet relative to the input wavelet (“ loss of resolution ”) (54). Example graphs of the three criteria 50, 52, 54 are shown in Figure 3, where the horizontal axis on each graph represents the reference length value. In Figure 3, the upper graph is a plot of the EF 50 rise, where the vertical axis represents the increase in decibels (dB). The intermediate graph is a plot of the HF 52 attenuation, where the vertical axis represents the dB attenuation. The lower graph is a plot of loss of resolution 54, where the vertical axis represents time in milliseconds (ms). In the examples presented, to avoid edge effects, frequencies near the lowest and highest limits of bandwidth have been taken into account (i.e. the LF increase 50 has been evaluated at 10 Hz above the minimum frequency, and the HF attenuation 52 has been evaluated at 10 Hz below the maximum frequency).
    The first two criteria, that is to say the increase LF 50 and the attenuation HF 52, have clear meanings relating to the distortion of the bandwidth of the signal, and on the manner in which it can be controlled. The third criterion, i.e. loss of resolution 54, relates to the reliability (for example, uncertainty) of the temporal recording of data after optical processing, since it is important that there is have no apparent delay in reliable seismic survey processing using a DVS dataset.
    Once the three criteria 50, 52, and 54 have been selected, constraints were then applied to the criteria in order to define an optimal GL for this example. First, as shown in Figure 3, the LF 50 boost and HF 52 attenuation were constrained to be no more than 1 dB. Second, as shown in Figure 3, the loss of resolution 54 was constrained to be less than 0.5 milliseconds, so that time records were reliable at an output sample rate of 1 millisecond. The criteria that are defined here are examples. In embodiments in which the LF increase 50, the HF attenuation 52 and the loss of resolution 54 are selected as criteria, other target values can be selected. For example, in some applications, preserving bandwidth may be considered more important than RSB. Therefore, a lower limit on the target value for HF 52 attenuation can be applied, such as 0.1 dB for example. In other applications, preserving bandwidth may be considered less important than improving RSB, in which case a higher target value for HF 52 attenuation may be selected, such as 2 dB for example. Whatever the case, the loss of resolution must always remain less than 1 ms to avoid affecting the results of the earthquake survey.
    In the example of Figure 3, and for the application of particular interest (that is to say, a seismic survey), the use of these three criteria and these constraints leads to the definition of '' a range 56 of admissible GL values in which the optimal GL for a particular application is at the upper limit of this range (as the reference 58 shows in this example), because the more the GL value increases, the more the RSB is high (up to a limit). An example of this relationship between GL and RSB can be seen in the plot of the HF 52 attenuation in Figure 3. As this example shows, when the value of GL increases, the HF 52 attenuation also increases until it reaches a limit (represented by the peak at around GL = 72 m in this example).
    Anyway, in the admissible range 56 for the example of FIG. 3, the optimal GL is defined as being the highest GL which provides (1) a maximum increase of 1 dB at the most low bandwidth frequency; (2) a maximum attenuation of 1 dB at the highest frequency of the bandwidth; and (3) a maximum loss of temporal resolution of 0.5 milliseconds.
    Using this definition of optimal GL, the relationship of GL with the parameters of the geophysical input was studied. The study found that the optimal GL is not sensitive to the lowest frequency of the bandwidth, and is linearly associated with the speed and inverse of the highest frequency. Further analysis revealed that the optimal GL is approximately linearly associated with the ratio of the speed of the wave to the highest frequency, which defines the shortest wavelength. This result is presented in Figure 4, which illustrates the approximate linear relationship between the optimal GL (vertical axis) and the shortest wavelength (horizontal axis). When a linear model is fitted to the relationship shown in Figure 4 (which corresponds to line 60 in this example), an adjustment rule for the optimal GL is obtained.
    Therefore, optimal values for GL can be provided by the equation ïp L = a U Tf J x V (2) I 'max where "V" is the apparent speed (local speed) of the seismic wave, and "f max " is the maximum frequency of the recoverable local bandwidth. The parameter a (Ahf, ^ LF> Tf #) represents the adjustment value or a multiplier which is derived from the linear relation illustrated in figure 4. In this example, (X is a function of HF attenuation, of increase LF and loss of resolution, and a (Ahf = ldB, & LF = ΙάΒ, Ύρρ = 0.5 ms) · However, it is understood that the multiplier is determined according to the criteria chosen and the target values selected for these criteria and therefore, in other embodiments or applications in which the concepts disclosed in this document are implemented, the range or the optimal value of the multiplier “a” may be different from that presented in FIG. 4. In embodiments, the range of the multiplier "a" is in the range of 0 to 1. In embodiments, the value of the HF attenuation can be selected in the range of 0.1 dB to 2 dB, the value of the LF boost can be selected in the range from 0.1 to 2 dB and the value of the loss of resolution can be selected up to a maximum of 1 ms, the range of the multiplier “a” then being determined accordingly between 0.2 and 0 6. This definition of an optimal GL represented in equation 2 above can then be applied to the processing of the DVS data set. In some embodiments, the optimal GL can be applied to the entire dataset, although this can result in an overall compromise on data quality. In other embodiments, the quality of DVS data can be improved by selecting an optimal GL which varies so that it is locally optimal along the detection fiber.
    FIG. 5 is a workflow diagram showing an example of processing a DVS data set in applications in which a fixed GL (as opposed to a variable GL) is used. In Fig. 5, DVS data 62, i.e. phase data, and a fixed GL 64 are provided as inputs to a differentiation interval processing block 66 which applies an overall central difference to generate differentiated phase data 68 as an output. The techniques for obtaining phase data have been described above. Any of these techniques or techniques of the prior art which may be known or techniques which may be developed may be used with the workflow of Figure 5 to acquire the phase data at which the differentiation interval and the GL are then applied to derive the differentiated phase data.
    Unlike Figure 5, Figure 6 is a workflow diagram showing an example of DVS data processing 62 using a variable optimal GL 70 which was selected according to Equation 2. As shown in Figure 6, the differentiation interval processing block 66 is replaced so that a variable value for the optimal GL (block 70) is used for the differentiation interval, where the variable value is controlled by a reference profile which is defined by the length of the cable (block 72), i.e. the length of the sensing fiber. In general, the reference profile provides a correlation between the depth and a detection location along the fiber. As such, using the cable length as a reference profile can help avoid difficulties with depth calibration or changes in the output depth spacing. The reference profile that is associated with the variable GL profile is used to assign depth to the GL values in the variable GL profile and thus helps to define which local GL value should be applied to a particular depth section of the data. since phase data can be recorded or processed with their own independent depth spacing, recording interval, etc. At processing block 74, the phase data 62, the cable length (or the reference profile) 72 and the variable optimal GL 70 are provided as inputs to interpolate a variable GL profile which is adapted to the parameters d recording or reading phase data. In processing block 76, the variable GL profile is modified to guarantee a linear decrease at the beginning and at the end in order to avoid side effects and to be able to process all of the data points in the data set . The processing block 78 maintains a local zero phase output (as in block 66 of Figure 5), but uses the variable GL profile as an input rather than a fixed GL. In block 80, the data is then normalized locally by the GL in order to avoid problems of variable amplitude and to preserve the output unit. The output of the workflow is a set of differentiated phase data 82.
    When the inventors applied the processing workflow of Figure 6 to a real DVS data set, the result was visually very close to conventional speed data. No clear distortions in the output data could be discerned, which presented an improved SNR compared to the use of a small fixed GL for the entire dataset, which therefore validates the use of equation 2 and the workflow in Figure 6 to define a variable optimal GL.
    The concepts contained in Equation 2 and the workflow of Figure 6 can be used to process DVS data in real time at the well site and / or to reprocess DVS data later, for example at a location distant from the well site (for example, the geophysicist's office). For real-time processing, in various embodiments, Equation 2 and the workflow in Figure 6 can be used to estimate a preliminary GL and a preliminary GL profile during a planning stage , for example before seismic prospecting is carried out, on the basis of previous data or of assumptions concerning the well site and the surrounding geology and of the seismic source. The estimates can then be used for real-time processing of DVS data at the well site to improve the quality of the acquired data set. However, if historical data is not available for estimation, then the DVS data can be processed at the well site using a preliminary GL which is selected by a user, for example the geophysicist, or which is determined by in another way, for example as disclosed in the international publication No. WO 2016/112147 A1, published July 14, 2016, mentioned above. Whichever GL is selected for real-time processing, the DVS data from the well site can then be reprocessed later using the variable optimal GL defined by Equation 2 and the workflow in Figure 6 to produce an updated (or more updated) DVS dataset. In embodiments, the updated or more updated DVS data set has improved quality.
    For example, the estimation of a preliminary GL can be carried out at the planning stage of a seismic survey. At this point, a geophysicist generally plans the acquisition using an approximate velocity model of seismic signals, such as a simple blocked velocity model or velocity information previously obtained from nearby wells or logs. Similarly, at this point, the bandwidth of the seismic source that will be used for seismic prospecting is known and can therefore be used as a preliminary approximation of the recoverable bandwidth in the DVS dataset. The approximate velocity model and the bandwidth of the seismic source can therefore be used as inputs during the work planning phase to derive a variable GL profile which contains a first approximation of the local optimal GL, using the Equation 2. At this stage, the characteristics of the well and the deployment of the detection fiber are also generally known and, if this is the case, can be used to derive the associated reference profile. As illustrated in the workflow example in Figure 7, the variable GL profile and the reference profile can then be used when processing optical data in real time during prospecting to provide improved results at the site level. well.
    Referring to the example of Figure 7, an approximate velocity model 90 and a bandwidth of the seismic source 92 are provided as inputs to a processing block 94 to estimate a reference length optimal local. In the embodiments described in this document, the optimal local reference length is determined by the application of equation 2, where “V” corresponds to the speed model 90 and “fmax” corresponds to the bandwidth of the source 92. The estimated optimal reference length is then provided as input to a processing block 96, with information 98 which is relevant to the well and the detection fiber which indicates the length over which the reference profile will be defined, for example the location of the end of the fiber as in a permanent prospecting application, the winch depth planned for a prospecting by cable line, etc. The processing block 96 uses the estimated reference length and the well and fiber information 98 to create a variable reference length profile and a reference profile. In the processing block 100, these profiles are then used to process the optical data received 102 using a variable GL in accordance with the workflow represented in FIG. 7 (for example, blocks 76 (reduce the edges), 78 (apply local central difference), 80 (normalize)). The output of block 100 is an updated DVS data set 104 which was generated in real time at the well site.
    In embodiments, the updated DVS data set 104 can then be stored (as in memory 38) with the optical data 102 so that it can be reprocessed later, for example at the office level of the geophysicist, to further update (for example, improve) the updated DVS dataset 104. This new processing can be based on new attributes extracted from the updated DVS dataset 104. However, it is understood that the new processing can be performed on a DVS data set when the real-time processing at the well site has simply applied a fixed reference length or another reference length which has not been determined in accordance with the workflows described in this document.
    Regardless of how the DVS data set for the new processing was obtained, in Figure 8, the data set 104 can be chosen and the actual local speed can be estimated to give a profile updated speed (for example, higher quality) which corresponds more closely to the actual conditions present during seismic prospecting (block 106). Similarly, an actual local bandwidth can be estimated which takes into account the local attributes present during prospecting, such as soil attenuation and a partial loss of the bandwidth of the seismic source (block 108). Using the two updated profiles, an updated local optimal GL (using equation 2) can be determined (block 110) and then used to reprocess (block 112) the optical data 102 (again using the workflow of processing (for example, blocks 76, 78 and 80) shown in Figure 7) to generate a more up-to-date (e.g., improved) DVS data set 114. In this workflow, like actual optical data from the site wells are available, the actual depth 116 from the dataset can be used for the reference profile, as shown in Figure 8.
    The various blocks of the workflows presented in FIGS. 5 to 8 have been called processing blocks which can be executed by a processor-based processing system, like the system 28 shown in FIG. 2. However, it it is understood that certain functions illustrated in the processing blocks can also be implemented by a system operator. In addition, it should be understood that workflows can include additional functionality and that various functions can be performed in different orders or in parallel. In addition, it should be understood that the sink system 20, including the DVS system 22 and the fiber optic cable 24, shown in Figure 1 can be used to acquire the optical data for processing in accordance with the workflows. shown in Figures 5 to 8. In applications in which the techniques disclosed in this document are used for seismic prospecting, the arrangement of Figure 1 may further include a seismic source which is deployed, for example, to a location on the surface penetrated by borehole 34.
    In addition, in the preceding description, the data (for example, the optical data or the processed DVS data) and instructions (in particular software instructions for implementing the work flows or parts of the work flows shown in Figures 5 to 8) are stored in suitable storage devices (such as, but not limited to, the storage device 38 of Figure 2) which are implemented in the form of one or more several non-transient storage media readable by computer or readable by a machine. Storage devices can include different forms of memory including semiconductor memory devices; magnetic disks such as fixed disks, floppy disks and removable disks; other magnetic media including a tape; optical media such as compact discs (CD) or digital video discs (DVD); or other types of storage devices.
    Furthermore, although the techniques for optimizing GL have been described in the context of an application for seismic profiling of wellbore, the techniques can be used in various applications and in various environments. In addition, when used in seismic profiling, the techniques are not limited to a particular type of seismic wave, but can be applied to compression waves, shear waves, refracted waves, etc. In addition, in some applications, multiple different types of waves may be of interest in the acquired optical data set. For example, in seismic profiling, both compression waves and shear waves may be of interest. In such applications, multiple optimal reference length profiles can be determined for each type of wave of interest. In such embodiments, each of the optical reference length profiles can be applied to the optical data set to thereby generate multiple sets of output data, each having been optimized for the particular wave of interest, by example.
    Although the invention has been disclosed in relation to a limited number of embodiments, those skilled in the art, having the benefit of this disclosure, will find many modifications and variations from these. It is intended that the appended claims cover these modifications and variations to the extent that they fall within the true spirit and scope of the invention.
    权利要求:
    Claims (1)
    [1" id="c-fr-0001]
    Method for use in a well, comprising:
    the deployment of optical fiber along well equipment; positioning well equipment in a wellbore that penetrates a region of interest;
    connecting the optical fiber to a distributed vibration detection system;
    the use of a length of the optical fiber to detect signals indicating a vibration in the region of interest;
    selecting a wavelength of interest of the signals to be detected as a function of the length of the optical fiber to generate a variable reference length profile to be applied to phase data acquired from the detected signals, in which the variable reference length profile defines reference length values which vary as a function of the length of the optical fiber; and using the variable reference length profile to process the phase data acquired from the length of the optical fiber, wherein a reference length value associated with a particular section of a plurality of sections of the fiber optics is used to process the phase data acquired from the particular section to thereby generate processed phase data.
    The method of claim 1, wherein selecting the wavelength of interest includes selecting the smallest wavelength of interest.
    The method of claim 1, wherein the use includes using the length of the optical fiber to detect signals in the form of seismic waves propagating in the region of interest. The method of claim 1, wherein the selection comprises estimating an apparent speed and a maximum frequency of the bandwidth of the signals to be detected at each of the plurality of sections of the optical fiber.
    The method of claim 4, wherein the apparent speed is estimated based on a preexisting speed model and wherein the maximum frequency is estimated based on a bandwidth of a seismic source to be used for generating seismic waves in the region of interest.
    The method of claim 5, further comprising using [Claim 7] [Claim 8] [Claim 9] [Claim 10] [Claim 11] [Claim 12] [Claim 13] [Claim 14] processed phase data for estimate an updated apparent speed and a maximum updated frequency for each of the sections of the optical fiber and thus generate an updated variable reference length profile.
    The method of claim 6, further comprising applying the updated variable reference length profile to the phase data to thereby generate updated processed phase data.
    The method of claim 6, further comprising generating a reference profile which correlates a depth in the wellbore with a location along the length of the optical fiber, and Γ using the reference profile to generate the variable reference length profile.
    Process comprising:
    the deployment of a distributed vibration detection system to detect an incident dynamic stress along the length of an optical fiber; and creating a variable reference length profile to generate adjusted optimal reference length values for corresponding sections of the optical fiber, wherein the variable reference length profile is created by selection, for each section of optical fiber, with the smallest wavelength of the signal causing the dynamic stress experienced by the corresponding section of the optical fiber.
    The method of claim 9, wherein the signals causing the dynamic stress are seismic waves.
    The method of claim 10, wherein the smallest wavelength for each section of the optical fiber is selected by estimating an apparent local velocity of the seismic wave experienced by that particular section of the optical fiber.
    The method of claim 10, wherein the smallest wavelength for each section of the optical fiber is selected by estimating an apparent local bandwidth of the seismic wave experienced by that particular section of the optical fiber .
    The method of claim 11, wherein the apparent local speed is estimated based on prior knowledge of the surrounding geology.
    The method of claim 12, wherein the apparent local bandwidth is estimated based on the bandwidth of a source [Claim 15] [Claim 16] [Claim 17] [Claim 18] [Claim 19] [Claim 20] seismic deployed to carry out seismic prospecting of the surrounding geology.
    The method of claim 14, wherein the optical fiber is deployed in a wellbore which penetrates a region of interest in the surrounding geology.
    The method of claim 10, further comprising applying the variable reference length profile to optical data acquired from the optical fiber which indicates dynamic stress to thereby generate differentiated phase data.
    The method of claim 16, further comprising using the differentiated phase data to estimate an actual apparent local speed and a maximum frequency of the seismic waves experienced by each section of the optical fiber, and creating a length profile of variable reference updated on the basis of the apparent local speed and the maximum frequency.
    The method of claim 17, further comprising further processing the optical data acquired from this optical fiber by applying the updated variable reference length profile to thereby generate updated differentiated phase data. The method of claim 16, further comprising: creating a second profile of variable reference length to generate second optimal reference length values adjusted for corresponding sections of the optical fiber, wherein the second profile of length variable reference is created by the selection, for each section of the optical fiber, of a second wavelength of interest of a second signal causing the dynamic stress undergone by the corresponding section of the optical fiber, in which the profile of variable reference length is adjusted for a first type of seismic wave and the second profile of variable reference length is adjusted for a second type of seismic wave; and applying the second variable reference length profile to the optical data acquired from the optical fiber to thereby generate second differentiated phase data.
    Process, comprising:
    deployment of a distributed vibration detection system to detect an incident dynamic stress along a length of an optical fiber;
    creating a preliminary variable reference length profile [Claim 21] to define preliminary optimal reference length values adjusted for corresponding sections of the optical fiber; and applying preliminary optimal reference length values to optical data acquired from the optical fiber which indicates the detected dynamic stress to thereby generate a set of differentiated phase data.
    The method of claim 20, further comprising: using the set of differentiated phase data to create an updated variable reference length profile; and a new processing of the optical data acquired from the optical fiber by the use of the updated variable reference length profile so as to generate a set of updated differentiated phase data.
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    同族专利:
    公开号 | 公开日
    US20190227184A1|2019-07-25|
    GB201900887D0|2019-03-13|
    GB2573358B|2021-07-28|
    GB2573358A|2019-11-06|
    FR3077142B1|2021-12-17|
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    公开号 | 申请日 | 公开日 | 申请人 | 专利标题
    WO2016112147A1|2015-01-07|2016-07-14|Schlumberger Canada Limited|Gauge length optimization in distributed vibration sensing|CA3047064A1|2017-01-18|2018-07-26|Halliburton Energy Services, Inc.|Gauge length effect and gauge length conversion|
    WO2021086382A1|2019-10-31|2021-05-06|Halliburton Energy Services, Inc.|Locating passive seismic events in a wellbore using distributed acoustic sensing|
    法律状态:
    2019-12-16| PLFP| Fee payment|Year of fee payment: 2 |
    2020-12-10| PLFP| Fee payment|Year of fee payment: 3 |
    2021-06-04| PLSC| Publication of the preliminary search report|Effective date: 20210604 |
    2021-12-17| PLFP| Fee payment|Year of fee payment: 4 |
    优先权:
    申请号 | 申请日 | 专利标题
    US15/876,712|US20190227184A1|2018-01-22|2018-01-22|Gauge length optimization for signal preservation and gauge length processing for distributed vibration sensing|
    US15/876,712|2018-01-22|
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