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WO2025147895A1 - Systèmes et procédés de reconstruction de bandes de fréquences de données sismiques - Google Patents

Systèmes et procédés de reconstruction de bandes de fréquences de données sismiques

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Publication number
WO2025147895A1
WO2025147895A1 PCT/CN2024/071565 CN2024071565W WO2025147895A1 WO 2025147895 A1 WO2025147895 A1 WO 2025147895A1 CN 2024071565 W CN2024071565 W CN 2024071565W WO 2025147895 A1 WO2025147895 A1 WO 2025147895A1
Authority
WO
WIPO (PCT)
Prior art keywords
seismic
window
frequency
seismic data
slowness
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Pending
Application number
PCT/CN2024/071565
Other languages
English (en)
Inventor
Lu Liu
Yue Ma
Yuhan SUI
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Aramco Far East Beijing Business Services Co Ltd
Saudi Arabian Oil Co
Original Assignee
Aramco Far East Beijing Business Services Co Ltd
Saudi Arabian Oil Co
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Aramco Far East Beijing Business Services Co Ltd, Saudi Arabian Oil Co filed Critical Aramco Far East Beijing Business Services Co Ltd
Priority to PCT/CN2024/071565 priority Critical patent/WO2025147895A1/fr
Publication of WO2025147895A1 publication Critical patent/WO2025147895A1/fr
Pending legal-status Critical Current
Anticipated expiration legal-status Critical

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Classifications

    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
    • G01V1/28—Processing seismic data, e.g. for interpretation or for event detection
    • G01V1/36—Effecting static or dynamic corrections on records, e.g. correcting spread; Correlating seismic signals; Eliminating effects of unwanted energy
    • G01V1/364—Seismic filtering
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
    • G01V1/28—Processing seismic data, e.g. for interpretation or for event detection
    • G01V1/36—Effecting static or dynamic corrections on records, e.g. correcting spread; Correlating seismic signals; Eliminating effects of unwanted energy
    • G01V1/364—Seismic filtering
    • G01V1/368—Inverse filtering
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V2210/00—Details of seismic processing or analysis
    • G01V2210/30—Noise handling
    • G01V2210/32—Noise reduction
    • G01V2210/324—Filtering
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V2210/00—Details of seismic processing or analysis
    • G01V2210/40—Transforming data representation
    • G01V2210/43—Spectral
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V2210/00—Details of seismic processing or analysis
    • G01V2210/40—Transforming data representation
    • G01V2210/47—Slowness, e.g. tau-pi
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V2210/00—Details of seismic processing or analysis
    • G01V2210/60—Analysis
    • G01V2210/62—Physical property of subsurface
    • G01V2210/622—Velocity, density or impedance
    • G01V2210/6222—Velocity; travel time

Definitions

  • Seismic imaging is a tool to reveal the structure of rocks within the subsurface.
  • a seismic acquisition system may be used to acquire data with which image the subsurface.
  • a seismic source may be used to send seismic waves through the subsurface which are reflected off of geologic boundaries such as interfaces of different formations and faults.
  • the reflected seismic waves are recorded by seismic receivers and all the recorded seismic traces are formed into a seismic data set.
  • the seismic data set may be processed using various processing steps such as noise attenuation, migration, and stacking.
  • the seismic data set may need an accurate seismic wave propagation velocity model to ensure a seismic image derived from the seismic data is useful.
  • An initial velocity model may be derived using seismic processing steps.
  • Full waveform inversion is a velocity model building process that may provide a detailed velocity model, however, it requires a sufficiently accurate initial velocity model to function effectively.
  • FWI may suffer from cycle-skipping problems, and converge to an inaccurate result, if some of the input frequencies are unreliable. A method to reconstruct the unreliable frequencies would be useful to potentially improve the processed seismic data.
  • the seismic image might be used to identify drilling targets such as hydrocarbon reservoirs.
  • the hydrocarbon reservoirs might be produced for hydrocarbons if they are found.
  • the seismic image might also be used to identify drilling hazards and to plan a well path to avoid such hazards and to penetrate the drilling targets.
  • inventions disclosed herein relate to a method for reconstructing a frequency band of seismic data.
  • the method may include obtaining, using a seismic acquisition system, a seismic data set pertaining to a subterranean region of interest.
  • the seismic data set may include a plurality of seismic traces arranged into a plurality of seismic gathers.
  • the method may include selecting, using a seismic processing system, a plurality of seismic data windows.
  • Each seismic data window may include a portion of the seismic gather lying between a first recording time and a second recording time.
  • the method may include determining a frequency-wavenumber seismic window based, at least in part, on transforming the seismic data window using a first transform.
  • inventions disclosed herein relate to a system for reconstructing a frequency band of seismic data.
  • the system may include a seismic acquisition system and a seismic processing system.
  • the seismic acquisition system may be configured to obtain a seismic data set pertaining to a subterranean region of interest.
  • the seismic data set may include a plurality of seismic traces arranged into a plurality of seismic gathers.
  • the seismic processing system may be configured to, for each seismic gather, select a plurality of seismic data windows. Each seismic data window may include a portion of the seismic gather lying between a first recording time and a second recording time.
  • FIG. 3 illustrates a seismic acquisition system for imaging a subterranean region of interest in accordance with one or more embodiments.
  • FIG. 4A-H illustrates seismic ray paths and traces organized into gathers in accordance with one or more embodiments.
  • FIG. 5A shows seismic waveforms in accordance with one or more embodiments.
  • FIG. 6A shows seismic waveforms in accordance with one or more embodiments.
  • FIG. 6B shows seismic spectra in accordance with one or more embodiments.
  • FIG. 7A shows seismic spectra in accordance with one or more embodiments.
  • FIG. 7B shows seismic spectra in accordance with one or more embodiments.
  • FIG. 8A-8B shows seismic waveforms in accordance with one or more embodiments.
  • FIG. 9A-C shows seismic waveforms in accordance with one or more embodiments.
  • FIG. 10 shows a schematic of portions of a seismic data set in accordance with one or more embodiments.
  • FIG. 11 shows a flowchart in accordance with one or more embodiments.
  • ordinal numbers e.g., first, second, third, etc.
  • an element i.e., any noun in the application.
  • the use of ordinal numbers is not to imply or create any particular ordering of the elements nor to limit any element to being only a single element unless expressly disclosed, such as using the terms “before, ” “after, ” “single, ” and other such terminology. Rather, the use of ordinal numbers is to distinguish between the elements.
  • a first element is distinct from a second element, and the first element may encompass more than one element and succeed (or precede) the second element in an ordering of elements.
  • any component described with regard to a figure in various embodiments disclosed herein, may be equivalent to one or more like-named components described with regard to any other figure.
  • descriptions of these components will not be repeated with regard to each figure.
  • each and every embodiment of the components of each figure is incorporated by reference and assumed to be optionally present within every other figure having one or more like-named components.
  • any description of the components of a figure is to be interpreted as an optional embodiment which may be implemented in addition to, in conjunction with, or in place of the embodiments described with regard to a corresponding like-named component in any other figure.
  • seismic data may often be acquired and processed to generate images of the subsurface.
  • Producing high quality images typically requires an accurate model of the velocity of seismic wave propagation within the subsurface.
  • Full waveform inversion ( “FWI” ) produces some of the most accurate velocity models available, by fitting predicted seismic data to observed seismic data over a range of frequencies.
  • FWI inversion itself requires a good initial velocity model as a starting point from which to produce an accurate and high-resolution result. Precisely how good the initial velocity model needs to be may depend on the lowest useable frequencies present the observed seismic data. Seismic data with good (high signal to noise ratio) low frequency data require less good initial velocity models than seismic data with poor low frequency data for FWI to produce accurate results.
  • FIG. 1 depicts a flowchart (100) in accordance with one or more embodiments.
  • FIG. 1 illustrates the steps of acquiring remote sensing data, processing the remote sensing data, forming a geological model (112) , optionally simulating the flow of fluids, including hydrocarbons, though the geological model (112) , the planning of wellbores including their surface position, trajectories, and targets, and the drilling of those wellbores.
  • steps in flowchart (100) are shown in sequential order, it will be apparent to one of ordinary skill in the art, that some steps may be conducted in parallel, or in a different order than shown, or may be omitted without departing form the scope of the invention.
  • flowchart (100) may begin with the use of a seismic acquisition system (300) to acquire a seismic data set (102) over a subterranean region of interest (222) .
  • the seismic acquisition system (300) will be described in more detail in the context of FIG. 3, and an example of a portion of the seismic data set (102) is shown in FIG. 5A.
  • Other remote sensing data sets may also be collected at this stage to characterize the subterranean region of interest (222) . For example, resistivity, transient electromagnetic, and/or gravitation surveys may be collected.
  • seismic data sets (102) are extremely large, typically occupying hundreds of Terabytes or more than a Petabyte in size, (corresponding to between 10 trillion (10 13 ) and 100 trillion (10 14 ) data samples) and cannot be manipulated or “processed” without the assistance of a purpose configured seismic processing system (105) .
  • the seismic processing system (105) may be configured to determine the seismic velocity model (107) by processes such as performing semblance velocity analysis, tomography, full waveform inversion, or combination thereof on seismic data sets such as a reconstructed seismic data set.
  • the seismic processing system (105) may be configured to determine the seismic image (108) of the subterranean region of interest (222) based, at least in part, on the seismic velocity model (107) and the seismic data set (102) .
  • the seismic image (108) may be a 2D or 3D image of the points within the subsurface that generate a distinctive seismic response.
  • the seismic image (108) may display the points at which seismic energy is reflected, or scattered, within the subsurface.
  • Other seismic characteristic or “attributes” of the subsurface may be displayed as the seismic image (108) .
  • the strength of conversion of energy from one type of seismic wave to another, or the strength of absorption of seismic energy, or the velocity of seismic propagation may be displayed as a function of subsurface position in the seismic image (108) .
  • the examples of seismic attributes given above are purely illustrative, and a person of ordinary skill in the art will appreciate that anyone of dozens of other attributes may be displayed as the seismic image (108) and the examples described should not be interpreted as limiting the scope of the invention in any way.
  • the seismic interpretation workstation (110) is primarily used by geoscientists, seismic interpreters, and exploration teams in the oil and gas industry for analyzing seismic data to understand subsurface geological structures. Seismic interpreters use the workstation to visualize seismic data, including 2D and 3D seismic volumes, cross-sections, time slices, and attribute maps. These visualizations provide insights into subsurface structures, faults, and potential hydrocarbon reservoirs. Additional data may be used within the seismic interpretation workstation (110) to facilitate the interpretation of the seismic data set (102) . Such additional data may include well logs acquired from previously drilled wells and acquired either while-drilling or via wireline conveyed well logging tools after drilling. Such data may also include non-seismic remote sensing data sets such as resistivity, transient electromagnetic, and/or gravitational surveys.
  • Seismic interpretation involves intensive tasks like data visualization, horizon picking, attribute analysis, and 3D modeling.
  • a high-performance seismic interpretation workstation (110) with a powerful processor, ample memory, and a high-resolution display is essential to handle these computationally demanding tasks efficiently.
  • Dedicated GPUs may be crucial for real-time rendering of seismic data, enabling smooth and interactive visualization. GPUs with high memory and parallel processing capabilities accelerate tasks like volume rendering and horizon visualization.
  • the seismic interpretation workstation (110) may be customized to meet the needs of interpreters and the specific requirements of projects.
  • the hardware specifications may vary based on factors like the complexity of interpretations, the size of data sets, and the software tools utilized.
  • the geological models (112) may be used directly to create a well plan (114) using the well planning system (250) .
  • the well plan (114) may contain drilling targets, often geologic regions expected to contain hydrocarbons.
  • the well planning system (250) is configured to design the well plan (114) to penetrate any drilling targets while simultaneously avoiding drilling hazard, such as preexisting wellbores, shallow gas pockets, and fault zones, and not exceeding the constraints, such as torque, drag and wellbore curvature, of the well drilling system (200) .
  • the well plan (114) may include a determination of wellbore caliper, and casing points.
  • the well planning system (250) may include dedicated software stored on a memory of the computer system (1200) .
  • the well plan (114) may be informed by the best available information at the time of planning. This may include models encapsulating subterranean stress conditions, the trajectory of any existing wellbores (which may be desirable to avoid) , and the existence of other drilling hazards, such as shallow gas pockets, over-pressure zones, and active fault planes.
  • While the well plan (114) is formed using the best available information at the time at which it is formed, additional information may become available when drilling the wellbore (217) specified by the well plan (114) .
  • well logs providing new information about the reservoir structure and characteristic may be acquired while drilling (so-called “logging-while-drilling” (LWD) logs or during drilling pauses in, or at the completion of drilling of, the wellbore (217) specified by the well plan (114) .
  • LWD logging-while-drilling
  • These well logs acquired during pauses or at the cessation of drilling may be acquired using wireline or coiled tubing conveyed logging tools. However acquired, these new wells may be used to update the geological models (112) with the aid of the seismic interpretation workstation (110) .
  • a well drilling system for example the well drilling system (200) described in FIG. 2 and accompanying description, is configured to drill the wellbore (217) guided by the well plan (114) .
  • FIG. 2 shows a well drilling system (200) in accordance with one or more embodiments.
  • the well drilling system (200) shown in FIG. 1 is used to drill a wellbore (217) on land, the well drilling system (200) may also be a marine well drilling system.
  • the example of the well drilling system (200) shown in FIG. 2 is not meant to limit the present disclosure.
  • the drillstring (206) may include one or more drill pipes connected to form conduit and a bottom hole assembly ( “BHA” ) (220) disposed at the distal end of the drillstring (206) .
  • the BHA (220) may include the drill bit (204) to cut into subsurface rock (203) , including cap-rock (216) .
  • the BHA (220) may further include measurement tools, such as a measurement-while-drilling (MWD) tool and logging-while-drilling (LWD) tool.
  • MWD tools may include sensors and hardware to measure downhole drilling parameters, such as the azimuth and inclination of the drill bit (204) , the weight-on-bit, and the torque.
  • the well plan may consider other engineering constraints such as the maximum wellbore curvature ( “dog-leg” ) that the drillstring (206) of the well drilling system (200) may tolerate and the maximum torque and drag values that the well drilling system (200) may provide.
  • the well plan may further define associated drilling parameters, such as the planned depths at which drilling may be paused and casing (224) will be inserted to support the wellbore (217) to prevent formation fluids entering the wellbore (217) and the drilling mud weights (densities) and types that may be used during drilling of the wellbore (217) .
  • FIG. 3 shows a seismic acquisition system (300) configured to acquire the seismic data set (102) pertaining to the subterranean region of interest (222) .
  • the subterranean region of interest (222) may be defined based on a coordinate system of one or more spatial dimensions (305) , for example, denoted x, y, and z in FIG. 2.
  • the subterranean region of interest (222) may be made up of layers of subsurface rock (203) separated by geological boundaries (215) or other geological structures, such as faults.
  • the subterranean region of interest (222) may also include complex geological structures other than faults, such as salt domes.
  • the subterranean region of interest (222) may further include a hydrocarbon reservoir (205) .
  • the hydrocarbon reservoir (205) may be subsurface rock (203) filled with fluid such as oil, gas, water, brine, and/or a combination thereof.
  • the seismic acquisition system (300) may utilize a seismic source (306) positioned on the surface of the earth (207) .
  • the seismic source (306) is typically a vibroseis truck (as shown) or, less commonly, explosive charges, such as dynamite, buried to a shallow depth.
  • the seismic source (306) may commonly be an airgun (not shown) that releases a pulse of high-pressure gas when activated.
  • the seismic source (306) when activated, generates radiated seismic waves, such as those whose paths are indicated by the rays (308) .
  • the radiated seismic waves may be bent ( “refracted” ) by variations in the speed of seismic wave propagation within the subterranean region of interest (222) and return to the surface of the earth (207) as refracted seismic waves (310) .
  • radiated seismic waves may be partially or wholly reflected by seismic reflectors, at reflection points such as (324) , and return to the surface of the earth (207) as reflected seismic waves (314) .
  • Seismic reflectors may be indicative of the geologic boundary (215) , such as the boundaries between geologic layers, the boundaries between different pore fluids, faults, fractures, or groups of fractures within the rock, or other structures of interest in the seismic for hydrocarbon reservoirs.
  • Seismic waves may radiate alone the surface as surface waves (318) .
  • the refracted seismic waves (310) and reflected seismic waves (314) may be detected by seismic receivers (320) .
  • the seismic receiver (320) may be a geophone (that records the velocity of ground motion) or an accelerometer (that records the acceleration of ground motion) .
  • the seismic receiver (320) may commonly be a hydrophone that records pressure disturbances within the water. Irrespective of its mechanical design or the quantity detected, the seismic receivers (320) convert the detected seismic waves into electrical signals, which may subsequently be digitized and recorded by a seismic recorder (322) as a time-series of samples.
  • Such a time-series is typically referred to as a seismic “trace” and represents the amplitude of the detected seismic wave at a plurality of sample times.
  • the sample times are referenced to the time of source activation and the sample times are referred to as “recording times” .
  • recording times zero recording time occurs at the moment the seismic source (306) is activated.
  • Each seismic receiver (320) may be positioned at a seismic receiver location that may be denoted (x r , y r ) where x and y represent orthogonal axes, such as North-South and East-West, on the surface of the earth (207) above the subterranean region of interest (222) .
  • the refracted seismic waves (310) and reflected seismic waves (314) generated by a single activation of the seismic source (306) may be represented as a three-dimensional “3D” volume of data with axes (x r , y r , t) where t indicates the recording time of the sample, i.e., the time after the activation of the seismic source (306) .
  • a seismic survey includes recordings of seismic waves generated by one or more seismic sources (306) positioned at a plurality of seismic source locations denoted (x s , y s ) .
  • a single seismic source (306) may be used to acquire the seismic survey, with the seismic source (306) being moved sequentially from one seismic source location to another.
  • a plurality of seismic sources (306) such as seismic source (306) may be used, each occupying and being activated ( “fired” ) sequential at a subset of the total number of seismic source locations used for the survey.
  • some or all of the seismic receivers (320) may be moved between firing of the seismic source (306) .
  • FIGs. 4A-H illustrates some of these methods of arrangement.
  • a seismic data set may include a plurality of seismic traces (413) arranged into a plurality of seismic gathers (416) .
  • FIG. 4A illustrates the spatial geometry of a common-source gather, sometimes called a “shot-gather” .
  • the horizontal axis represents a location of a seismic source (306) and a plurality of seismic receivers (320) on a horizontal plane, such as the surface of the Earth.
  • the vertical axis represents depth below the surface of the earth (207) .
  • Rays (308) emanating from the seismic source (306) , reflecting from a geologic boundary (215) , and propagating as reflected seismic waves (314) indicate the path of seismic waves schematically.
  • a common-offset gather presents data collected when the seismic source (306) location and the seismic receiver (320) locations are at a constant separation (or “offset” ) from one another.
  • the geometry of common-offset gather ray paths are displayed schematically in FIG. 4E and the recorded traces in FIG. 4F.
  • common-offset gathers while the time at which the reflected energy (414) is recorded on each receiver trace is constant the reflection points (324) on the geologic boundary (215) still vary from one receiver to another.
  • FIG. 4G and FIG. 4H illustrate the geometry and recorded data for a common-midpoint gather, respectively.
  • a common-midpoint gather displays traces recorded by seismic sources (306) and seismic receivers (320) arrange with a single ( “common” ) midpoint but varying offset.
  • common-midpoint gathers are preferred because each trace shares (approximately) the same reflection point (324) on the geologic boundary (215) . Consequently, each trace in the common-midpoint gather contains information about the same point.
  • Seismic data arranged in a plurality of seismic gathers may be utilized in seismic processing workflow steps such as migration, and FWI.
  • the seismic processing workflow may use the seismic gathers as input, or may use the seismic gathers after stacking, for example combining seismic traces from separate gathers into a single stacked trace of seismic data.
  • the process of combining may include addition, or a weighted summation calculation.
  • a seismic data set may be obtained by the seismic acquisition system (300) and may be arranged into a plurality of seismic gathers each including a plurality of seismic traces (413) .
  • the seismic gathers may be shot-gathers, common-receiver gathers, common-midpoint gathers, or as stacked seismic data.
  • FIG. 5A displays a seismic gather (416) in accordance with one or more embodiments.
  • the seismic gather (416) is a shot-gather.
  • the seismic processing system (105) may be configured to arrange the seismic data set (102) into the plurality of seismic gathers (416) .
  • the plurality of seismic gathers may include a plurality of shot-gathers.
  • the seismic processing system (105) as described in reference to FIG.
  • the seismic processing system (105) may be configured to perform any process known to a person of ordinary skill in the art which may be used to transform a time-domain seismic wavefield to a frequency-domain seismic wavefield.
  • a Fourier transform may be used, for example discrete-time Fourier transforms, or anti-leakage anti-aliasing Fourier transforms, such as that described in Liu, L., Sindi, G.A., Qin, F., 2023. “Anti-Aliasing and Anti-Leakage Regularization of High-Dimensional Seismic Data” , PCT Application, PCT/CN2023/122098.
  • FIG. 5B shows a frequency domain seismic wavefield (420) transformed from a portion of the seismic gather (416) .
  • FIG. 6A shows a simulated seismic gather (416) with reflected energy (414) in accordance with one or more embodiments.
  • Horizontal axis represents distance such as source-receiver offset, midpoint position, and the like.
  • Vertical axis represents two-way time.
  • the simulated seismic gather traces are irregularly spaced in accordance with one or more embodiments.
  • FIG. 6B displays a portion of a frequency-wavenumber domain seismic wavefield in accordance with one or more embodiments.
  • the frequency-wavenumber domain seismic wavefield may be transformed from the seismic data window (550) .
  • the seismic processing system (105) is configured to determine the frequency-wavenumber seismic window (610) based, at least in part, on transforming the seismic data window (550) using a first transform.
  • the first transform may include, but not limited to, Fourier, sine, cosine, chirplet, and/or wavelet transforms.
  • the Fourier transform may include, but is not limited to, discrete- time Fourier transform, split-step Fourier transform, short-time Fourier, and/or anti-leakage anti-aliasing Fourier transform.
  • the first transform may include, but not limited to, three-dimensional (3D) or two-dimensional (2D) transforms.
  • the recorded seismic traces may be acquired irregularly and sometimes sparsely as shown in FIG. 6A.
  • the first transform may include the anti-leakage anti-aliasing Fourier transform.
  • the anti-leakage anti-aliasing Fourier transform may overcome the spectrum leakage and aliasing issues.
  • Certain methods of seismic processing steps may require a seismic wavefield to be transformed and separated into local plane waves based on the angles at which the radiated seismic waves propagate through the subterranean region of interest (222) .
  • Separation of a seismic wavefield into local plane waves may rely on, but not limited to, a least-squares Radon transform.
  • the Radon transform determines the seismic wavefield to a frequency-slowness domain seismic wavefield with slowness defined as an inverse velocity.
  • the least squares Radon transform may be given by:
  • Equation (1) uses the L 2 norm of the Radon transform result for example. It should be apparent to those skilled in the art that other embodiments may include other L 1 or L 0 norm.
  • FIG. 7A to FIG. 7B display a portion of a frequency-slowness domain seismic wavefield in accordance with one or more embodiments.
  • the frequency-slowness domain seismic wavefield may be transformed from the one of the frequency-wavenumber seismic window (610) .
  • the seismic processing system (105) is configured to determine a frequency-slowness seismic window (700) based, at least in part, on transforming the frequency-wavenumber seismic window (610) using a second transform.
  • the frequency-slowness window may comprise a slowness (750) .
  • the second transform may include, but is not limited to, linear Radon, hyperbolic Radon, parabolic Radon, least-squares Radon, Hough, and/or generalized Radon transforms.
  • the second transform may include, but not limited to, 2D or 3D transforms.
  • the example embodiment shown in FIG. 7A to FIG. 7B utilizes a least-squares Radon transform.
  • the slowness (denoted as p x in equations (1) to (10) ) (750) may represent an inverse velocity.
  • FIG. 7B depicts the frequency-slowness seismic window (700) with seismic data window being acquired irregularly and sparsely in accordance with one or more embodiments.
  • the seismic processing system (105) is configured to update components of the frequency-slowness seismic window (700) in a first frequency band (703) based, at least in part, on the using components of the frequency-slowness seismic window in a second frequency band (705) .
  • the frequencies within the first frequency band (703) may be lower than the frequencies of the second frequency band (705) .
  • the frequencies of the first frequency band (703) may be higher than the frequencies of the second frequency band (705) .
  • the seismic processing system (105) may be configured to update the components using, but is not limited to, b-spline interpolation, or autoregressive processes.
  • the example embodiment utilized a b-spline interpolation process for updating the components of the first frequency band (703) .
  • Each frequency-slowness seismic window (700) may be transformed into a portion of the spatial-time domain seismic wavefield by performing a first inverse transform and a second inverse transform.
  • the first inverse transform may include any inverse form of the first transform described above such as, but not limited to, an inverse Radon transform.
  • the second inverse transform may be any inverse form of the second transform described above such as, but not limited to, a 2D inverse Fourier transform.
  • the frequency-slowness seismic window (700) may include the updated components from the first frequency band (703) .
  • FIG. 8A depicts the seismic gather (416) in accordance with one or more embodiments.
  • FIG. 8B depicts a portion of a filtered seismic data window (810) in accordance with one or more embodiments.
  • the seismic processing system (105) is configured to determine the filtered seismic data window (810) based, at least in part, on performing an inverse Radon transform and an inverse Fourier transform such as a 2D inverse transform.
  • FIG. 9A to FIG. 9C depict a portion of a reconstructed data set (900) in accordance with one or more embodiments.
  • FIG. 9A to FIG. 9C show the reconstructed seismic data set (900) within different frequency bands.
  • FIG. 9A shows reconstructed data set (900) with full seismic bandwidth.
  • FIG. 9B shows reconstructed data set (900) with seismic bandwidth under 6 Hz.
  • FIG. 9B shows reconstructed data set (900) with seismic bandwidth under 10 Hz.
  • Each filtered seismic data window (810) may be used to form the reconstructed seismic data set (900) .
  • the seismic processing system (105) may be configured to form the reconstructed seismic data set (900) from a plurality of filtered seismic data windows (810) .
  • the reconstructed seismic data set (900) may be formed based on the spatial and time dimensions of each filtered seismic data window (810) .
  • the updating method (1100) as described herein may include overlapping portions of the seismic data windows as illustrated in FIG. 10.
  • the seismic processing system (105) may be configured to merge overlapping portions using a weighted stack of each portion of the seismic data windows.
  • one of a plurality of data areas (1010) may include overlapping portions, for example, portions between x 1 -x 2 , x 3 -x 4 , t 1 -t 2 , and t 3 -t 4 as illustrated in FIG. 10.
  • FIG. 11 depicts a method for updating a frequency bandwidth of seismic data (hereafter “updating method” ) (1100) .
  • the updating method (1100) allows for updating components of a frequency bandwidth within the seismic data set (102) , but it should be apparent to those skilled in the art the updating method (1100) may be applied on any data set within a spatial-time domain.
  • the updating method (1100) may include obtaining, using the seismic acquisition system (300) , the seismic data set (102) pertaining to the subterranean region of interest (222) , wherein the seismic data set (102) comprises the plurality of seismic data traces arranged into the plurality of seismic gathers, in accordance with one or more embodiments.
  • the updating method (1100) may be performed utilizing the seismic data set (102) in the arrangement of a seismic gather, for example as a shot-gather, common-receiver gather, common midpoint gather, or as stacked seismic data.
  • the portion of the seismic data shown is arranged into a shot-gather.
  • the updating method (1100) using the processing system (105) , may comprise arranging the seismic data set (102) into the plurality of seismic gathers (416) .
  • the plurality of seismic may comprise a plurality of shot-gathers.
  • the updating method (1100) may comprise, using the seismic processing system (105) , for each seismic gather, selecting a plurality of seismic data windows (550) , wherein each seismic data window (550) comprises a portion of the seismic gather (416) lying between the first recording time (551) and the second recording time (553) , in accordance with one or more embodiments.
  • the updating method (1100) may comprise selecting each sequential window to overlap, at least partially, with the sequential window previously selected. The selected window may overlap in the recording time dimension.
  • the updating method (1100) comprises determining the frequency-wavenumber seismic window (610) based, at least in part, on transforming the seismic data window using the first transform, in accordance with one or more embodiments.
  • the updating method (1100) may utilize the Fourier transform which may include, but is not limited to, discrete-time Fourier, split-step Fourier, and anti-leakage anti-aliasing Fourier transforms, or any other transform as described above.
  • the first transform may also be a three-dimensional (3D) transform or a two-dimensional transform (2D) .
  • the updating method (1100) comprises determining the frequency-slowness seismic window (700) based, at least in part, on transforming the frequency-wavenumber seismic window (610) using the second transform, in accordance with one or more embodiments.
  • the updating method (1100) may utilize the Radon transform which may include, but is not limited to, linear Radon, hyperbolic Radon, parabolic Radon, and least-squares Radon transforms, or any other transform as described above.
  • the updating method (1100) comprises updating components of the frequency-slowness seismic window (700) in the first frequency band (703) based, at least in part, on the using components of the frequency-slowness seismic window (700) in the second frequency band (705) , in accordance with one or more embodiments.
  • the second frequency band may include a frequency bandwidth F such as frequencies lying from f 1 to f 2 .
  • the second frequency band (705) may be used to update components of the first frequency band (703) such as component denoted f 1 - ⁇ f, where ⁇ f is a user-defined increment.
  • the user-defined increment may be, for example, 1 Hz.
  • the frequencies within the first frequency band (703) may be lower than the frequencies of the second frequency band (705) . In other embodiments, the frequencies of the first frequency band (703) may be higher than the frequencies of the second frequency band (705) .
  • the updating method (1100) using the seismic processing system (105) , wherein updating the components of the frequency-slowness seismic window (700) in the first frequency band (703) comprises, but is not limited to, performing the b-spline interpolation, or autoregressive processes. B-spline interpolation utilizes adjacent frequencies to update the components of the second frequency band (705) .
  • the updating method (1100) used to derive the example embodiment performed the b-spline interpolation for updating the components of the frequency-slowness window (700) within the first frequency band (703) .
  • the updating method (1100) may comprise, transforming each frequency-slowness seismic window (700) into the spatial-time domain seismic wavefield by performing a first inverse transform and a second inverse transform.
  • the updating method (1100) may utilize, but not limited to, any inverse form of the first transform such as an inverse Radon transform.
  • the updating method (1100) may also utilize, but not limited to, any inverse form of the second transform such as a 2D inverse Fourier transform, in accordance with one or more embodiments.
  • the updating method (1100) may comprise, at least in part, the updated components from the first frequency band (703) within the frequency-slowness seismic window (700) .
  • the updating method (1100) may comprise, using the seismic processing system (105) , determining a filtered seismic data window (810) based, at least in part, on performing a first inverse transform and a second inverse transform such as an inverse Radon transform and an inverse Fourier transform, respectively.
  • the updating method (1100) may comprise, using the seismic processing system (105) , forming the reconstructed seismic data set (900) from a plurality of filtered seismic data windows (810) , in accordance with one or more embodiments.
  • the updating method (1100) may comprise forming the reconstructed seismic data set (900) based on the spatial and time dimensions of each filtered seismic data window (810) .
  • the updating method (1100) as described herein may include overlapping portions of the seismic data windows as illustrated in FIG. 10.
  • the seismic processing system (105) may be configured to merge overlapping portions using a weighted stack of each portion of the seismic data windows as described above in reference to FIG. 10.
  • Seismic processing may be a series of processing steps that ultimately produce a seismic data set with a higher signal-to-noise ratio than the original seismic data set as well as immediately useful information that may be used to characterize the subterranean area of interest (222) and locate geologic features. Seismic processing may include methods of migration, stacking, filtering, etc.
  • the updating method (1100) may further comprise determining the seismic image (108) of the subterranean region of interest (222) based, at least in part, on the seismic velocity model (107) and the seismic data set (102) .
  • the seismic velocity model (107) may be used to process the seismic data set (102) using the seismic processing system (105) as described in reference to FIG. 1.
  • the seismic image (108) may be obtained by using the seismic velocity model (107) to perform seismic processing steps such as, but not limited to, removing seismic multiples, and migration, on the seismic data set (102) .
  • the updating method (1100) may further comprise identifying, using the seismic interpretation workstation (110) as described in reference to FIG. 1, the drilling target (218) based on the seismic image (108) .
  • the seismic image (108) may be used to image geologic boundaries (215) such as, but not limited to, geologic formations and faults.
  • the seismic image (108) may be used to identify a hydrocarbon reservoir (205) .
  • the drilling target (218) may be within the hydrocarbon bearing formation.
  • FIG. 12 further depicts a block diagram of a computer system (1200) used to provide computational functionalities associated with described algorithms, methods, functions, processes, flows, and procedures as described in this disclosure, according to one or more embodiments.
  • a computer system such as the computer system shown in FIG. 12, may form part of the seismic acquisition system (300) , the seismic processing system (105) , the seismic interpretation workstation (110) , the well planning system (250) , and/or the well drilling system (200) .
  • the illustrated computer (1202) is intended to encompass any computing device such as a server, desktop computer, laptop/notebook computer, wireless data port, smart phone, personal data assistant (PDA) , tablet computing device, one or more processors within these devices, or any other suitable processing device, including both physical or virtual instances (or both) of the computing device. Additionally, the computer (1202) may include a computer that includes an input device, such as a keypad, keyboard, touch screen, or other device that can accept user information, and an output device that conveys information associated with the operation of the computer (1202) , including digital data, visual, or audio information (or a combination of information) , or a GUI.
  • an input device such as a keypad, keyboard, touch screen, or other device that can accept user information
  • an output device that conveys information associated with the operation of the computer (1202) , including digital data, visual, or audio information (or a combination of information) , or a GUI.
  • the computer (1202) can serve in a role as a client, network component, a server, a database or other persistency, or any other component (or a combination of roles) of a computer system for performing the subject matter described in the instant disclosure.
  • one or more components of the computer (1202) may be configured to operate within environments, including cloud-computing-based, local, global, or other environment (or a combination of environments) .
  • the computer (1202) can receive requests over network (1230) from a client application (for example, executing on another computer (1202) and responding to the received requests by processing the said requests in an appropriate software application.
  • requests may also be sent to the computer (1202) from internal users (for example, from a command console or by other appropriate access method) , external or third-parties, other automated applications, as well as any other appropriate entities, individuals, systems, or computers.
  • Each of the components of the computer (1202) can communicate using a system bus (1203) .
  • any, or all of the components of the computer (1202) may interface with each other or the interface (1204) (or a combination of both) over the system bus (1203) using an application programming interface (API) (1212) or a service layer (1213) (or a combination of the API (1212) and service layer (1213) .
  • the API (1212) may include specifications for routines, data structures, and object classes.
  • the API (1212) may be either computer-language independent or dependent and refer to a complete interface, a single function, or even a set of APIs.
  • API (1212) or the service layer (1213) may illustrate the API (1212) or the service layer (1213) as stand-alone components in relation to other components of the computer (1202) or other components (whether or not illustrated) that are communicably coupled to the computer (1202) .
  • any or all parts of the API (1212) or the service layer (1213) may be implemented as child or sub-modules of another software module, enterprise application, or hardware module without departing from the scope of this disclosure.

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Abstract

L'invention concerne des procédés de reconstruction d'une bande de fréquences de données sismiques. Les procédés consistent à obtenir un ensemble de données sismiques concernant une région souterraine comprenant une pluralité de traces sismiques agencées en une pluralité de collectes sismiques et, pour chaque collecte sismique, sélectionner une pluralité de fenêtres de données sismiques. Les procédés consistent également, à partir de chaque fenêtre de données sismiques, à déterminer une fenêtre sismique de nombre d'ondes de fréquence à l'aide d'une première transformée et à déterminer une fenêtre sismique de lenteur de fréquence à l'aide d'une seconde transformée. Pour chaque lenteur, les procédés consistent à mettre à jour des composants de la fenêtre sismique de lenteur de fréquence dans une première bande de fréquences sur la base de composants dans une seconde bande de fréquences et à déterminer une fenêtre de données sismiques filtrées sur la base de la réalisation d'une première et d'une seconde transformée inverse. Les procédés consistent en outre à former un ensemble de données sismiques reconstruites à partir de la pluralité de fenêtres de données sismiques filtrées. L'invention concerne également des systèmes de reconstruction d'une bande de fréquences de données sismiques.
PCT/CN2024/071565 2024-01-10 2024-01-10 Systèmes et procédés de reconstruction de bandes de fréquences de données sismiques Pending WO2025147895A1 (fr)

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US20140188395A1 (en) * 2013-01-02 2014-07-03 Cgg Services Sa System and method for removal of jitter from seismic data
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