• 专利附录
  • 专利说明
  • 权利要求
  • 类似技术
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    • 专利摘要:
    subsurface imaging systems and methods with segregation and redetermination of assessment components from multiple sources. a subsurface imaging method described begins by obtaining initial signals from a geophysical assessment that was acquired with multiple geophysical sources of energy acting on a plurality of trigger sequences, with each sequence having a known time delay between the activation time of each source. the initial signals are grouped into groupings of signals acquired from multiple trigger sequences. for each grouping, the initial estimates of the first and second source wave fields are determined. the signals slowed down to the first source are then generated to represent the initial signals minus a current estimate of the second source wave field. a coherent energy separation operation is applied to the slowed signals to obtain a refined estimate for the first source wave field.
    公开号:BR102012025928B1
    申请号:R102012025928-1
    申请日:2012-10-10
    公开日:2021-04-27
    发明作者:Peter A. Aaron；Stian Hegna；Gregory Ernest Parkes
    申请人:Pgs Geophysical As；
    IPC主号:
    专利说明:

    Background
    [0001] Seismology is used for exploration, archaeological studies, and engineering projects that require geological information. Seismology exploration provides data that, when used in conjunction with other available geological, borehole and geophysical data, can provide information on the structure and distribution of rock types and their contents. Such information helps a lot in water research, geothermal reservoirs, and mineral deposits such as hydrocarbons and ores. Most oil companies rely on seismology exploration to select locations in which to drill for oil wells.
    [0002] Exploration seismology uses artificially generated seismic waves to map subsurface structures. Seismic waves propagate from a source towards Earth and reflect from the boundaries between subsurface structures. The surface receivers detect and record the reflected seismic waves for further analysis. Where seismic waves are considered inadequate, electromagnetic waves can be used in a related way. In both cases, multiple sources can be used to accelerate the evaluation process while still generating overlapping separable wave fields. Brief Description of Drawings
    [0003] A better understanding of the various modalities described can be obtained when the detailed description below is considered in conjunction with the accompanying drawings, in which: Figures 1 and 2 are seen from a marine illustrative system of geophysical evaluation. Figure 3 is a functional block diagram of an illustrative marine geophysical assessment system. Figure 4 shows an illustrative set of recorded signals. Figure 5 shows a pattern illustrating the midpoint obtained by a given source geometry. Figures 6A and 6B show illustrative firing sequences, before and after alignment. Figure 7 is a flow chart of an illustrative imaging method. Figure 8 is a flow chart illustrating a source wave field separation method.
    [0004] It should be understood that the drawings and the corresponding detailed description do not limit the disclosure, but on the contrary, present a rationale for understanding all modifications, equivalents, and alternatives within the scope of the appended claims. Detailed Description
    [0005] Consequently, several subsurface imaging systems and methods that estimate and refine the wave fields for each source in a multiple source evaluation are revealed in this document. In at least some method modalities, the signals are obtained from a geophysical assessment acquired with multiple geophysical sources of energy activated in a plurality of trigger sequences, with each sequence having a different and known delay time between a signal which records the start time and activation time of each source. The evaluation signals are organized into groupings of signals from multiple trigger sequences. Each grouping is then processed to form initial estimates of the wave fields for each source, which are then used to provide softened signals from which refined estimates of the source fields can be obtained. A subsurface image can be derived based on refined estimates of the component's signals.
    [0006] Figure 1 shows an illustrative system of geophysical assessment that, in this case, collects marine seismic assessment data using multiple seismic sources with a variable firing sequence. A seismic analysis vessel 10 moves along the surface 11A of a body of water 11 such as a lake or the ocean. Vessel 10 typically includes equipment that is generally shown at 12 and is referred to for convenience as a "logging system". The recording system 12 can include devices to selectively activate the seismic energy sources 14, 16, to trigger and record the signals generated by the sensors or receivers 20 in response to the seismic energy transmitted in the water 11 and thus, in the rock formations 19, 21 below the aquatic bottom 13, and to determine the vessel's geodesic position 10, the seismic energy sources 14, 16 and each of a plurality of seismic sensors or receivers 20 at any time.
    [0007] Vessel 10 is shown towing two seismic energy sources 14, 16. Seismic energy sources 14, 16 can be from any type of marine energy source including, but not limited to air guns and water guns , or series of such energy sources. In the illustrative system shown in Figure 1, the fountains 14, 16 are towed substantially at the same distance behind the vessel 10 and at different depths in the water 11. In other examples, the fountains 14, 16 can be towed by a different vessel, or can be in a fixed position. Some contemplated systems tow the sources with different vessels, and may also employ more than two sources.
    [0008] Vessel 10 is also shown towing a series of seismic cables 18 (see also Figure 2). The towed seismic cable configuration is shown for illustrative purposes. Other suitable configurations of a set of sensors can also be employed, including, for example, cables on the ocean floor and sensors located in well holes. Any sensors suitable for seismic signals or other geophysical energy signals may be employed, including, but not limited to, pressure sensors, pressure time gradient sensors, speed sensors, accelerometers, and any combination thereof.
    [0009] During operation, the illustrative system of geophysical evaluation, in selected time delays, in relation to the beginning of the seismic record of the acquisition system 12, triggers a first of the seismic energy sources, for example, source 14. The energy of the first source 14 travels out of it as shown in 24. Some of the energy paths down where it is reflected in limits of acoustic impediments, for example, in the aquatic bottom 13 and in limits 15, 17 between different rock formations 19, 21. Only the reflections of the aquatic bottom are shown in Figure 1 for clarity of the illustration. A portion of the energy from the first source 14 travels upwards where it is reflected from the water surface 11A before traveling downwards and interacting with the formation limits, as previously described.
    [00010] The recording system 12 also triggers a second of the seismic energy sources, for example, source 16, in selected time delays in relation to the beginning of the seismic data records, or, alternatively, in time delays selected before or after the activation of the first source 14. The energy from the second source 16 travels out along similar paths as well as the energy from the first source 14, as shown in 22 in Figure 1. Each actuation of both the first and the second source of energy seismic energy with the time delays described above is referred to in this document as a "trigger sequence". Time delays vary from firing sequence to firing sequence in a known random, semi-random, or systematic manner. Typically, time delays of less than a second, but can also be longer. It is also desirable that the trigger time delays of the sources are different in each trigger sequence. The difference in delay time between the firing of the first source and the second source must also vary in a known way that can be random, semi-random or systematic.
    [00011] Figure 2 shows the illustrative geophysical evaluation system of Figure 1 in plan view to illustrate the towing of a plurality of laterally spaced seismic cables 18. Seismic cables 18 can be maintained in their relative lateral and longitudinal positions in relation to to vessel 10 when using towing equipment 23 of types known in the art. What is also shown in Figure 2 is that the first source 14 and the second source 16 can be laterally displaced (and / or longitudinally displaced, in other examples) to avoid, in case the sources 14, 16 are air guns or series thereof, that the air dispersed in the water 11 of the first source 14 affects the seismic energy of the second source 16 and vice versa. The lateral and / or longitudinal displacement is considered to be only in the order of only a few meters so that the sources 14, 16 have an equivalent spatial energy distribution to be that which would occur if the sources 14, 16 were in the same vertical plane and in the same longitudinal distance behind the vessel, or expressed differently, essentially in the same geodesic position. By avoiding having air dispersed above the second source 16 when activated, the effects of the aquatic surface (11A in Figure 1) will be, adjusted for the depth of the water, substantially the same as the effect of the same on the first source 14.
    [00012] A function block diagram of the illustrative geophysical assessment system is shown in Figure 3. This includes receivers 20 coupled to a bus 32 for communicating digital signals to the data record circuitry 36 on the vessel 10. The information of position and other parameter sensors 34 are also coupled to the data logger circuitry 36 to allow the data logger circuitry to store additional information useful for interpreting the logged data. For illustrative purposes, such additional information may include geodetic position information for sources and receivers, as well as climatic and maritime conditions.
    [00013] A general purpose digital data processing system 38 is shown coupled to the data record circuitry 36, and is also shown coupled via bus 32 to positioning devices 28 and seismic sources 14, 16. The system processing 38 configures the operation of register circuitry 36, positioning devices 28, and seismic sources 14, 16. Logging circuit 36 acquires the high-speed data stream (s) from receivers 20 in one non-volatile storage medium such as a series of magnetic or optical disks or tapes. Positioning devices 28 (which include programmable diverters and depth controllers) control the position of receivers 28 and sources 14, 16. The illustrative system also includes a user interface that has a graphical display screen 39 and a keyboard or other mechanism to accept user input. The user interface allows an operator to monitor and control the operation of the evaluation system.
    [00014] The geophysical assessment system may include additional components not shown here. For example, each seismic cable may have an independent bus 32 to couple with the data record circuitry 36. The processing system 38 may also include a network interface for communicating the stored seismic assessment data to a central installation facility. computing that has powerful computing resources to process the seismic assessment data, and to receive the image of subsurface or other representations of the data acquired from the central computing facility.
    [00015] The illustrative geophysical system activates the sources and the recording of signals, as explained above, for a plurality of firing sequences at the same time that the vessel 10, the sources 14, 16 and the seismic cables 18 move through the water 11. Signal recordings made for each trigger sequence by recording system 12 can be referred to as a "capture record" or "capture grouping", and each such capture record will include, for each receiver 20, dashes ( that is, received signals) in response to the seismic energy produced by both the first source 14 and the second source 16.
    [00016] Figure 4 shows illustrative signals (R0, R1, R2, ...) representative of the signals recorded by the receivers in response to an activation of the sources. The signals may be voltages of digitized signals, but they usually represent some geophysical wave attribute, such as pressure, speed, acceleration, electric force field, or magnetic force field. Each signal is associated with the position where the source was activated and the position of the acquisition receiver at the time the source was activated. In other words, each recorded trace has at least three aspects: a source position (for each source), a receiver position, and a time-based signal waveform. From these three aspects, a great abundance of information can be derived.
    [00017] Figure 5 shows a top view of positions 500 of a set of receivers at the time the source was fired at position 504. If the subsurface formation layers are largely horizontal, the seismic energy that reaches the receivers thus reflecting from a point midway between the source and the position of the receivers. Thus, if a ray is plotted over the source for each receiver (for example, rays 506, 508), the intermediate points 502 of those rays represent the approximate position of the reflections that resulted in the recorded signal waveform. With this understanding, it becomes possible to convert the time-based signal waveform into depth-based signal waveforms, using a derived or pre-existing velocity model.
    [00018] Each shot from a source results in a pattern of 502 intermediate points associated with the received signals. (The midpoint pattern for each shot is a half-scale replica of the receiver's position pattern.) As the assessment proceeds, sources are triggered repeatedly and receivers acquire signals associated with the new sets of midpoints that widely overlap the previous sets of intermediate points. All depth-based waveforms associated with a given midpoint can be added or "stacked" to increase their noise ratio to the signal and present a more accurate picture of the sub-surface structure at that point.
    [00019] The systems and methods that employ this processing approach typically group the received signals, according to their intermediate points, thereby forming the "common intermediate groupings" or "CMP groupings". It is clear that other processing approaches are known and used to convert the received signals to the image of the subsurface. Such other approaches may employ other groupings of signals, such as, for example, capture groupings, receiver common position groupings, also known as "common station" groupings, and common compensation groupings also known as common channel groupings. Except for capture clusters, these various types of clusters group together, signals from different shooting sequences.
    [00020] Figure 6A shows an illustrative set of schedules for signals that can be associated with a common channel grouping that has signals from different trigger sequences. The schedules are labeled RiSj, where i is a given receiver number and j is a given trigger sequence number. Each schedule starts at the start recording time and shows a start time T1 for a first source and a start time T2 for a second source. The delay between the trigger times varies so that when signals are processed to align the trigger times for a given source (as shown in figure 6B), the trigger times for the other source remain unrelated. This timing of the trigger sequences makes it possible to separate the wave fields from each source when processing the signals as highlighted below
    [00021] Figure 7 is a flow chart of an illustrative subsurface imaging method that can be deployed by a general purpose processing system 308 or by a separate processing facility that receives the geophysical assessment data from the 308 system. block 702 with obtaining geophysical evaluation data, using multiple sources activated with variable trigger sequences as described above. in block 704, the system pre-processes the data to, for example, suppress certain types of interference and regularize the source and receiver positions associated with the signals. Such smoothing can be completed by, for example, interpolation to replace any missing sensors and compensate for any misalignments. The output of this block is referred to in this document as "initial" reception signals.
    [00022] In block 706, the system processes the initial reception signals to separate contributions from each source. These contributions are referred to in this document as wave fields for a given source, that is, the wave field for the first source (also known as the first source wave field) and the wave field of the second source ( also known as the second source wave field). At least, in some systems, the sources are positioned at different depths in the water to allow the ghosting of wave fields at a later stage. The initial reception signals include the wave fields of each source and a residual component. In this block, the system forms an initial estimate of the source fields, and then refines each estimate based on a combination of the previous estimates with the current residual component. This block will be described in more detail with reference to Figure 8 below.
    [00023] In block 708, the separate components are added again to the appropriate activation time delays and compared to the initial reception signals. A close match indicates that the volume of the receive signal energy has been associated with the source fields, while a breakdown indicates that an insignificant portion of the receive signal energy is not considered. In the later case, block 706 is repeated with different configurations until an adequate separation of the reception signal components is achieved.
    [00024] In block 710, the separate wave fields for those systems that have sources at different depths are combined in a way that eliminates the phantom effect of the source (that is, the portion of the signal attributed to the energy source that reflects from the surface of the source). Water). A suitable technique is described by M. Egan et al., "Full deghosting of OBC data with over / under source acquisition", 2007 Annual Meeting, San Antonio, Texas., Exploration Geophysicists Society, but others exist and can be used. In block 712, the system also processes wave fields with a phantom effect to form images of the sub-surface structure. In some modalities, the system migrates the source with phantom effect downwards (for example, with wave equation propagation) from the receiver's positions to obtain the wave fields of the reflected energy, according to a function of position and time. The wave fields of the reflected energy can then be combined with the associated fields of transmitted energy waves using a correlation function or some other imaging criterion that yields a volumetric map of the subsurface reflectivity. The reflectivity maps of different captures can then be stacked to render an image of the sub-surface structure. The system then creates a visual representation of the subsurface image accessible to a user, usually with instruments that allow the user to interact with the visual representation in order to explore and analyze the subsurface image in detail.
    [00025] Figure 8 is a flowchart of an illustrative method of separating the source wave field that can be implemented by the system in block 706. In block 802, the system arranges the initial reception signals in a multiple cluster domain. catches, that is, grouping the signals into clusters that have signals acquired in response to the different shooting sequences. The appropriate grouping domains are those that allow the energy from a given source to be coherent when the activation times for that source are aligned while the energy from other source (s) becomes incoherent. Suitable cluster domains include, without limitation, common intermediate groupings, common station groupings, and common channel groupings. The system then repeats, through the groupings, the performance of the following operations for each group.
    [00026] In block 804, the system processes the signals in a way that aligns the activation times of a first source, for example, by changing the time of the received signals. Aligning the signals to the activation times of the first source, in this way, makes the energy associated with the source coherent while the energy for the other sources becomes incoherent. On this basis, the system applies a coherent / incoherent separation energy operation to block 806. Techniques suitable for doing this are known include, for example, the methods described by RD Martinez, "Weighted Slant Stack For Attenuating Seismic Noise", from patent application No. US 6,574,567; P. Akerberg, et al., "Simultaneous source separation for sparse radon transform", 2008 Annual meeting, Las Vegas, Nev., Society of Exploration Geophysicists; and S. Spitz, "Simultaneous source separation: a prediction - subtraction approach", 2008 Annual meeting, Las Vegas, Nev., Society of Exploration Geophysicists. Predictive error filtering generates a filter model that minimizes an average quadratic error object to be constrained in the filter design, while the Radon transform approach condenses coherent energy into identifiable peaks in the phase-sluggish domain. Such approaches to separate coherent energy components from incoherent energy components offer relatively low computational complexity and may be preferred for this reason. However, other coherence display operations can also be employed.
    [00027] The coherent energy signals obtained in block 806 serve as an initial estimate of the first source wave field, and this estimate is temporarily stored in block 814 for later use. In block 808, the system takes the inconsistent energy signals and realigns them to synchronize the activation times of the second source. In block 810, the system again applies the coherent / incoherent separation energy operation. The coherent energy signals obtained here serve as an initial estimate of the second source wave field, this estimate being stored in block 816 for later use. In block 812, the system takes the incoherent energy signals from block 810 and realigns them to synchronize the activation times of the first source. These incoherent energy signals are added to the initial estimate of the first source wave field from block 814 to form what is, in the present document, called "softened" signals for the first source, that is, a representation of the initial signals of receipt with the exception of the estimated contribution from the second source.
    [00028] Block 820 represents a group of operations 822 to 834 that can be performed repeatedly on the signals slowed down to the first source in reference to the estimate for the second source wave field. In block 822, the system applies coherent / incoherent separation energy operation to the signals slowed down to the first source. The resulting coherent energy signals form a refined estimate of the first source wave field, and are stored for future use in block 830. In block 824, the incoherent energy signals from block 822 are realigned to synchronize with the activation times of the second source and add them to the current estimate of the second source wave field to form softened signals for the second source, in this case, a representation of the initial reception signals, with the exception of the current estimate of the contribution from the first source. The system applies the coherent / incoherent separation energy operation again in block 826. The coherent energy signals form a refined estimate of the second source wave field and are stored in block 832 for future use.
    [00029] In block 828, the system realigns the inconsistent energy signals from block 826 to synchronize with the activation times of the first source. The realigned incoherent energy signals are added to the current estimate of the first source wave field of block 830 to form an enhanced version of the softened signals for the first source. In block 834, the system tests for inconsistent energy signals to determine whether operations in block 820 should be repeated. Repetition can be considered desirable if, for example, the energy of the incoherent signals is in agreement with the previous incoherent energy signals. Alternatively, if the energy of the inconsistent energy signals is above a predetermined threshold, repetition may be considered desirable. Alternatively, the peak amplitudes of the inconsistent energy signals can be used to create these determinations. Still according to another alternative, a minimum or fixed number of repetitions can be considered desirable. Once the system that determines the source field estimates to be adequate has been obtained for each of the groupings, the process processes block 708 of Figure 7.
    [00030] If, in block 708, it is considered necessary to repeat block 706, the coherent / incoherent separation energy operation in Figure 8 can be applied with different parameters to change the proportion of energy that is found to be coherent to a given source. The repetition criterion in block 834 can also be changed to try to better converge the solution.
    [00031] Due to the fact that there is a certain asymmetry in the determination of the source wave fields (that is, the wave field is estimated first for both the first and the second source), the alternative modalities contemplated in the preceding method will repeat, after the estimated source fields are determined and refined, the estimation process (blocks 804 to 834) with the sources being taken and a different order. The results of the two estimates can be calculated to obtain unbiased estimates of the source wave fields.
    [00032] The preceding modalities of a method for determining which components of a seismic signal are a result of a particular source from a plurality of geophysical sources may take the form of a computer program stored in a computer-readable medium. The medium can be a volatile medium (such as an SRAM or DRAM computer memory) or a non-volatile medium (such as a magnetic disk, optical disk, or a flash memory chip). The program includes operable logic to make a programmable computer perform the operations explained above in relation to Figure 7. The operations can be performed sequentially, as explained above, but they can alternatively be performed in a conduit or parallel format, and do not need be carried out strictly in the order described above. The method can be performed by a single processor, but it is contemplated that, in most cases, it would be performed by multiple processors in a localized or alternatively distributed computing format. The processor (s) employs one or more output devices (such as printers or display screens) to create results that are noticeable to users so that they can monitor the process and evaluate the final product.
    [00033] Numerous other modifications, equivalent, and alternatives, will become evident to those skilled in the art, since the above disclosure is fully verified. The foregoing disclosure can be applied, for example, to systems that have two sources placed substantially at different depths, or systems that have widely separated sources. The techniques can also be applied to systems that have more than two sources. The following claims are intended to be interpreted to cover all such modifications, equivalents, and alternatives where applicable.
    权利要求:
    Claims (18)
    [0001]
    1. Subsurface imaging method, characterized by understanding: obtaining (702) initial signals from a geophysical assessment acquired with multiple geophysical sources of energy (14, 16) activated in a plurality of firing sequences, each sequence having a known and different time delay between a seismic signal recording start time and an activation time for each source; forming (802) clusters of initial signals, each cluster comprising signals acquired from multiple trigger sequences; and for each grouping: determine initial estimates of a first source wave field and a second source wave field; generate (812) first softened signals from the source that represent the initial signals with the exception of a current estimate of the second source wave field; and applying (822) a coherent energy separation operation to obtain a refined estimate of the first source wave field of the first slowed signals from the source.
    [0002]
    2. Method according to claim 1, characterized by the fact that it comprises, additionally, for each grouping: calculating (824) second softened signals from the source that represent the initial signals minus the refined estimate of the first source wave field; and using (826) the coherent energy separation operation to obtain a refined estimate of the second source wave field from the second slowed-down signals from the source.
    [0003]
    3. Method, according to claim 1, characterized by the fact that it also comprises deriving (712) a subsurface image from refined estimates of the first and second source wave fields; and produce the subsurface image in a noticeable way.
    [0004]
    4. Method, according to claim 1, characterized by the fact that the geophysical assessment is a marine seismic assessment, in which the geophysical sources of energy (14, 16) include two marine seismic sources substantially located (14, 16) in different depths, and where the method also comprises processing refined estimates of the component signals to separate the rising and falling wave fields and recombining the rising and falling wave fields in a way that suppresses the phantom effect.
    [0005]
    5. Method according to claim 1, characterized by the fact that the coherence separation operation includes employing a forecast subtraction procedure to spatially separate coherent signal energy from incoherent signal energy.
    [0006]
    6. Method, according to claim 1, characterized by the fact that the coherence separation operation includes transforming the signals into a domain where the peaks spatially represent the coherent signal energy and preferably attenuating non-peak values in the transform domain .
    [0007]
    7. Method, according to claim 2, characterized in that it additionally comprises the steps of generation (812), application (822), calculation (824) and use (826) to also refine the estimates of the first and second fields source wave.
    [0008]
    8. Method, according to claim 2, characterized by the fact that it additionally comprises repeating the determination step with the captured sources in a different order, thereby obtaining additional estimates of the first and second source wave fields.
    [0009]
    9. Method, according to claim 8, characterized by the fact that it additionally comprises providing improved estimates of the first and second source wave fields when averaging the source wave field estimates obtained when taking the sources into different orders.
    [0010]
    10. Method, according to claim 1, characterized by the fact that the operation of formation clusters has common station clusters or common intermediate clusters.
    [0011]
    11. Subsurface imaging system comprises: a computer-readable medium that has subsurface imaging software; one or more processors (38) configured to run the software, and the software configures one or more processors (38) to perform operations characterized by: obtaining (702) initial signals from a geophysical assessment acquired with multiple geophysical sources of energy ( 14, 16) triggered in a plurality of trigger sequences, each sequence having a different and known time delay between a seismic signal recording start time and a trigger time for each source; form (802) clusters of the initial signals, each cluster comprising signals acquired from multiple trigger sequences; and for each grouping: determine initial estimates of a first source wave field and a second source wave field; generating (812) the first slowed signals from the source that represent the initial signals minus a current estimate of the second source wave field; and applying (822) a coherent energy separation operation to obtain a refined estimate of the first source wave field of the first slowed signals from the source.
    [0012]
    12. System, according to claim 11, characterized by the fact that the software also configures the one or more processors (38) for, for each group: calculate (824) the second softened signals from the source that represent the initial less the refined estimate of the first source wave field; and using (826) the coherent energy separation operation to obtain a refined estimate of the second source wave field of the second softened source signals.
    [0013]
    13. System according to claim 12, characterized by the fact that the software also configures the one or more processors (38) to derive (712) a subsurface image from the refined estimates and to produce the subsurface image of in a way that is perceptible to a user.
    [0014]
    14. System, according to claim 11, characterized by the fact that the software also configures the one or more processors (38) to implement the coherent energy separation operation according to a forecast subtraction procedure to spatially separate the energy from coherent signal from the inconsistent signal energy.
    [0015]
    15. System, according to claim 11, characterized by the fact that the software also configures the one or more processors (38) to implement the coherent energy separation operation by transforming the slowed signals into a domain where the peaks represent spatially the coherent signal energy and for preferentially attenuating the non-peak values in the transform domain.
    [0016]
    16. System, according to claim 12, characterized by the fact that the software also configures the one or more processors (38) to repeat the steps of generation (812), application (822), calculation (824) and use ( 826) to also refine the estimates of the first and second source wave fields.
    [0017]
    17. System, according to claim 16, characterized by the fact that the software also configures the one or more processors (38) to repeat the step of determining initial estimates with the captured sources in a different order, thus obtaining Additional refined estimates of the first and second source wave fields.
    [0018]
    18. System according to claim 17, characterized by the fact that the software also configures the one or more processors (38) to obtain improved estimates of the first and second source wave fields when averaging the refined estimates of the first and second source wave fields obtained by taking the sources in different orders.
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    法律状态:
    2013-10-22| B03A| Publication of a patent application or of a certificate of addition of invention [chapter 3.1 patent gazette]|
    2018-12-11| B06F| Objections, documents and/or translations needed after an examination request according [chapter 6.6 patent gazette]|
    2020-06-09| B06U| Preliminary requirement: requests with searches performed by other patent offices: procedure suspended [chapter 6.21 patent gazette]|
    2021-03-09| B09A| Decision: intention to grant [chapter 9.1 patent gazette]|
    2021-04-27| B16A| Patent or certificate of addition of invention granted|Free format text: PRAZO DE VALIDADE: 20 (VINTE) ANOS CONTADOS A PARTIR DE 10/10/2012, OBSERVADAS AS CONDICOES LEGAIS. |
    优先权:
    申请号 | 申请日 | 专利标题
    US13/269,991|2011-10-10|
    US13/269,991|US8982663B2|2011-10-10|2011-10-10|Subsurface imaging systems and methods with multi-source survey component segregation and redetermination|
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