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    • 专利摘要:
    Methods For Seismic Exploration And To Make Seismic Survey Of Mixed Sources Over The Subsurface Region, For Seismic Acquisition With Simultaneous Sources And For Seismic Exploration And Seismic System. In accordance with an embodiment of the present invention, a method is proposed to collect a mixed source seismic survey that uses a new approach to determine a random separation in time between successive shots. The random separation in time can be derived, in some embodiments, from a uniformly distributed number distribution where (Tau) = 1 / (2f), where (Tau) is the half-width of the uniform distribution and f is the lowest frequency of interest in the survey.
    公开号:BR112013017762B1
    申请号:R112013017762-4
    申请日:2012-01-12
    公开日:2020-12-22
    发明作者:Raymond Abma；Gerard J. Beaudoin；Zhiyong Jiang
    申请人:Bp Corporation North America Inc.；
    IPC主号:
    专利说明:

    DESCRIPTIVE REPORT Related Case
    [0001] This Application claims the benefit of US Patent Provisional Application Serial No. 61 / 431,943, filed on January 12, 2011 and incorporates said Application by reference to this disclosure as set out in full in this section. Technical Field
    [0002] In general terms, the present invention relates to the field of seismic exploration and, more specifically, to methods for estimating seismic signals and other signals representative of the subsurface. Background of the Invention
    [0003] A seismic survey represents an attempt to portray or map the earth's subsurface by sending sound energy to the soil and recording the "echoes" that come back from the underlying rock layers. The source of the descending sound energy can come, for example, from explosions or seismic vibrators, on land, or from compressed air weapons, in marine environments. During a seismic survey, the energy source is positioned in several locations close to the earth's surface on a geological structure of interest. Every time the source is activated, it generates a seismic signal that descends through the earth, reflects and, when it comes back, is recorded in a large number of locations on the surface. Then, several source / record combinations are combined to create an almost continuous profile of the subsurface, which can span several miles. In a two-dimensional (2D) seismic survey, the recording sites are generally arranged along a single line, whereas, in a three-dimensional (3D) survey, the recording sites are distributed in a grid along the surface. Roughly speaking, a 2D seismic line can be thought of as a cross-sectional image (vertical slice) of the earth's layers as they are found directly under the recording sites. A 3D survey produces a “cube” or volume of data that is, at least conceptually, a 3D image of the subsurface that lies below the survey area. In fact, however, both 2D and 3D surveys clear some volume of land underlying the area covered by the survey. Finally, a time-lapse survey (also known as a 4D survey) is one made on the same target on the subsurface at two or more different times. This can be done for a variety of reasons, but it usually serves to measure changes in the subsurface's reflectivity over time, which can be caused, for example, by the advancement of a flame flood, displacement of gas / oil or contact with oil / water etc. Of course, when comparing successive images of the subsurface, any changes observed (taking into account differences in the characteristics of the sources, in the receivers, in the recorders, in the conditions of ambient noise, etc.) can be attributed to the progress of the processes underway in the subsurface.
    [0004] A seismic survey consists of a very high number of individual seismic records or traces. In a typical 2D survey, there are usually several tens of thousands of strokes, whereas in a 3D survey, the number of individual strokes can reach several million. Chapter 1, pages 9 to 89, of Ozdogan Yilmaz's “Seismic Data Processing”, Society of Exploration Geophysicists, 1987, contains general information with reference to conventional 2D processing and its presentation is incorporated by reference into this document. General background information regarding the acquisition and processing of 3D data can be found in Chapter 6, pages 384 to 427, of Yilmaz, the exposition of which is also incorporated by reference into this document.
    [0005] A seismic trace is a digital record of the acoustic energy reflected by inhomogeneities or discontinuities in the subsurface; a partial reflection occurring whenever there is a change in the elastic properties of materials on the subsurface. Digital samples are generally acquired at 0.002 second intervals (2 milliseconds or “ms”), although sampling intervals of 4 milliseconds and 1 millisecond are also common. Each individual sample in a conventional digital seismic trace is associated with a travel time and, in the case of reflected energy, a bilateral travel time, from the source to the reflector and back to the surface, provided, of course, that the source and the receiver are both located on the surface. In practice, many variations of the conventional source-receiver scheme are adopted, for example, VSP surveys (vertical seismic profile), surveys of the ocean floor, etc. In addition, the location on the surface of each trace in a seismic survey is carefully monitored and generally constitutes part of the trace itself (as part of the trace's header information). This allows, later on, to correlate the seismic information contained in the traces to specific locations on the surface and subsurface, thus providing a means of launching and constructing seismic data (and attributes extracted from them) in order to generate a map (ie, “map ”).
    [0006] The data in a 3D survey can be viewed in several different ways. First of all, it is possible to extract horizontal “constant time slices” from a stacked or non-stacked seismic volume by collecting all digital samples that occur in the same travel time. This operation results in a horizontal 2D plane of the seismic data. By animating a series of 2D planes, the interpreter is able to move through the volume, giving the impression that several successive layers are being stripped in order to view underlying information. Similarly, a vertical plane of seismic data can be extracted from an arbitrary azimuth through the volume by collecting and displaying the underlying seismic traces along a specific line. This operation, in practice, extracts an individual 2D seismic line from within the 3D data volume. It is also worth mentioning that it is possible to think of a 3D data set as being composed of a 5D data set that were reduced in terms of scalability when stacking them in a 3D image. The dimensions are usually time (or depth “z”), “x” (ie, north-south), “y” (ie, east-west), source-receiver shift in the x direction and source-receiver shift in the direction y. Although the examples in this document focus on 2D and 3D cases, the extension of the process to four or five dimensions is evident.
    [0007] Seismic data properly acquired and processed can provide a variety of information to the explorer, an employee of an oil company whose function is to locate possible drilling sites. For example, a seismic profile gives the explorer a broad view of the structure of rock layers in the subsurface and generally reveals important characteristics regarding the trapping and deposit of hydrocarbons such as faults, folds, anticline, non-conformities and domes and salt banks in the subsurface, among many others. During the processing of seismic data in a computer, estimates of the speed of the rocks in the subsurface are routinely generated and inhomogeneities are detected and displayed. In some cases, seismic data can be used to directly estimate the porosity of rocks, water saturation and hydrocarbon content. Less obviously, attributes of the seismic waveform, such as phase, peak amplitude, peak-to-valley ratio and several others, can generally be empirically correlated to known hydrocarbon occurrences, and this correlation applied to seismic data collected on new exploration targets.
    [0008] Certainly, a well-known problem with seismic data is that it can be expensive to acquire. Indeed, in some cases, the cost of the survey can determine whether the proposed target is economically viable or not. Therefore, techniques that tend to reduce the cost of these surveys are always welcome.
    [0009] Spacing firing from two or more sources is seen as a strategy to decrease the cost of acquiring seismic data. The basic concept behind this approach is to use a receiving line or layer and activate multiple sources in sequence or at the same time during a single registration period. In this way, it is possible to combine the subsurface reflexes due to an anterior source stimulus to posterior reflexes, that is, a “mixed source” survey is obtained. Note that this represents a total departure from conventional survey techniques, in which the reflections of the subsurface of one source would never be allowed to overlap the reflections of another.
    [0010] Although the mixed source approach has the potential to dramatically decrease time in the field, thereby decreasing the cost of the survey by the same proportion, an obvious problem is that it can be difficult to separate individual shots later. In other words, the depth of each reflector is of paramount importance in interpreting the seismic data. In general terms, the depth of a reflector is determined by the bilateral seismic travel time. Therefore, in a survey with several sources, it is of the utmost priority to determine which of the observed subsurface reflexes is associated with each source, otherwise, it is not possible to determine its bilateral travel time safely.
    [0011] In addition to planned mixed source surveys, in some cases, records from several unplanned sources can be acquired. For example, in areas of intense exploration activity, there may be multiple teams firing in the same general area. This may be of particular concern in offshore areas, where several seismic vessels can be active at the same time. Traditionally, when a seismic record contains energy from a third-party source, attempts are made to silence the part of the signal that contains the unwanted source so that it does not spread to adjacent records using multi-trace processing algorithms such as migration. However, this silencing eliminates both interfering noise and useful reflections that may occur at or near the same reflection time. Although it is known how to try to replace the silenced regions by interpolation from non-silenced data, this is, at best, an approximation of the lost data.
    [0012] The separation of two or more shots from a single seismic record is predictably problematic. The timing of shots during acquisition has shown some potential in terms of improving the separability of shots acquired at the same time, which is especially true when the time interval between successive shots is at least somewhat random. However, this approach has not proved so useful, at least in part because to date there is no reliable way of determining how much “randomness” in time separations would produce an ideal result (or even a good result). Further improvements to this approach are clearly needed.
    [0013] For a long time, as is well known in the fields of seismic acquisition, processing and interpretation, there is a need for a method to separate two or more seismic sources that were activated during a single record. Therefore, it must now be recognized that there is, and has been for some time now, a palpable need for a method for the processing of seismic data that addresses the problems described above and solves them.
    [0014] Before proceeding with the description of the present invention, however, it is worth emphasizing and remembering that the description of the invention below, together with the accompanying drawings, should not be interpreted in a way that limits the invention to the illustrated examples (or embodiments) and described. This is so, as those skilled in the art to which the invention concerns will be able to deduce other forms of the present invention within the scope of the appended Claims. Summary of the Invention
    [0015] In accordance with an aspect of the present invention, a system and method is proposed to operate several seismic sources at the same time during an acquisition in such a way that the separation of the post-survey shots can be performed more expeditiously. In particular, in one variation, the present invention makes use of the measurement of the lowest expected or desired frequency in the survey to determine a minimum acceptable random component for the separation in time between successive trigger activations. In some embodiments, the distribution of the evenly distributed firing time separations is selected so that T = 1 / (2 /), where T is the half-width of the uniform distribution and / is the lowest frequency of interest. In some embodiments, the half-width is centered around zero (or else includes zero) so that both positive and negative values are potentially obtained. In other words, the uniform distribution can only cover positive values.
    [0016] During acquisition and according to an embodiment, source stimuli that occur in the same register can be separated by random time intervals, in which the time interval between successive shots corresponds to some function of the expected frequency content of the data . When acquiring overlapping sources according to the method's embodiments, the energy of practically coincident shots is less likely to contain coherent energy, making them more prone to further separation. By activating the shots at random times, by correcting them to their individual zero times, they will have coherent signals from point to source to point to point, whereas interfering shots will tend to be inconsistent and can be separated, for example , by an inversion process. This reinforces the operation of coherence measures in the present separation process.
    [0017] Therefore, in one embodiment, the application of this acquisition method provides sensibly clean sets of shots that can be used in imaging and pre-stack analysis, such as an AVO (Amplitude vs. Deviation) analysis.
    [0018] The acquisition of seismic data with shots in which the recorded information of a shot overlaps other shots in time has the potential to significantly decrease the time (and cost) to make a seismic survey. This approach also allows firing point intervals that are closer together (for example, during a marine survey), which would provide potentially better seismic images that would increase the chances of discovering economically interesting amounts of oil and / or gas.
    [0019] In one embodiment, a method of seismic exploration over a subsurface region that contains structural or stratigraphic characteristics conducive to the presence, migration or accumulation of hydrocarbons comprises (a) determining the lowest frequency of interest in a mixed source seismic survey. The method also comprises (b) using said lower frequency of interest to determine a value representative of a variability in a probability distribution. The method also comprises (c) initiating the recording of at least one seismic receiver positioned close to the subsurface region. In addition, the method comprises (d) activating a first seismic source. In addition, the method comprises (e) recording the first seismic source by means of at least one seismic receiver. The method also comprises (f) determining a random period of time using the probability distribution and the determined variability. The method also comprises (g) waiting a period of time at least approximately equal to the random period of time after activating the first seismic source and then activating a second seismic source. In addition, the method comprises (h) recording the second seismic source by means of at least one seismic receiver. The method also includes performing at least the steps from (d) to (h) several times, thus conducting a mixed source seismic survey; and use the mixed source seismic survey to explore hydrocarbons in the subsurface region.
    [0020] In one embodiment, a method for making a mixed source seismic survey over a subsurface region that contains structural or stratigraphic characteristics conducive to the presence, migration or accumulation of hydrocarbons comprises (a) determining the lowest frequency of interest in the seismic survey mixed source. The method also comprises (b) using the lowest frequency of interest to determine a representative value of at least one parameter of a probability distribution. The method also comprises (c) initiating the recording of at least one seismic receiver located close to the subsurface region. In addition, the method comprises (d) activating a first seismic source. The method also comprises (e) using at least one seismic receiver to register one or more reflexes resulting from the activation of the first seismic source. In addition, the method comprises (f) using the probability distribution and the representative value of at least one parameter of the probability distribution to determine a delay. The method further comprises (g) waiting a period of time at least approximately equal to the delay after activating the first seismic source and then activating a second seismic source. The method comprises (h) recording the second seismic source by means of at least one seismic receiver. In addition, the method also comprises performing at least steps from (d) to (h) several times, thus conducting a seismic survey from a mixed source; and use at least part of the mixed source seismic survey to explore hydrocarbons in the subsurface region.
    [0021] In another embodiment, a method for seismic acquisition with simultaneous sources comprises placing several seismic sources close to one or more underground formations. The method also comprises determining a pseudo-random distribution of time intervals between the initiation of each seismic source based on the lowest frequency of interest. The method also comprises triggering the seismic sources according to the pseudo-random distribution over time. In addition, the method comprises recording several seismic signals reflected by one or more underground formations; and forming a visually intelligible image from any of the said several recorded seismic signals.
    [0022] In yet another embodiment, a seismic exploration method comprises (a) accessing at least part of a mixed source seismic survey carried out on a subsurface region that contains structural and stratigraphic characteristics conducive to the presence, migration or accumulation of hydrocarbons, in that the mixed source seismic survey is carried out by (1) determining the lowest frequency of interest in the mixed source seismic survey; (2) use the lowest frequency of interest to determine a value representative of a variability in a probability distribution; (3) start recording at least one seismic receiver positioned close to the subsurface region; (4) activate a first seismic source; (5) recording the first seismic source using at least one seismic receiver; (6) determining a random period of time using the probability distribution and the determined variability; (7) wait a period of time at least approximately equal to the random period of time after activating the first seismic source and then activating a second seismic source; (8) registering the second seismic source by means of at least one seismic receiver; and (9) carry out at least the steps from (d) to (h) several times, thus conducting a mixed source seismic survey. The method also comprises (b) using at least part of the mixed source seismic survey to explore hydrocarbons in the subsurface region.
    [0023] In one embodiment, a seismic system comprises several seismic sources and a controller operationally connected to each one. The controller is programmed to trigger the seismic sources according to a pseudo-random distribution of time intervals between the initiation of each seismic source. The pseudo-random distribution over time is selected based on the lowest frequency of interest.
    [0024] The provisions above outlined in general terms the most important characteristics of the invention disclosed in this document so that the following detailed description is more clearly understood and that the present inventor's contribution to the technique is better appreciated. The application of the present invention is not limited to the details of construction or the schematics of the components set out in the description below or illustrated in the drawings. Instead, the method revealed is susceptible to other embodiments and can be practiced or performed in a variety of ways not specifically listed in this document. Finally, it should be understood that the phraseology and terminology used in this document are for the purpose of description, and should not be interpreted as limiting the invention, unless otherwise specified. Brief Description of Drawings
    [0025] Other objectives and advantages of the invention will be apparent from reading the following detailed description and with reference to the drawings, among which:
    [0026] Figure 1 illustrates the general environment of the embodiments of the revealed method.
    [0027] Figure 2 illustrates a seismic processing sequence suitable for use with the method embodiments.
    [0028] Figure 3 shows a graph of resistance to cross interference versus TW for a simple frequency.
    [0029] Figure 4 shows a generalized graph of T = 1 / (2 /) that represents the limits of separation in relation to frequency and tau.
    [0030] Figure 5 shows the results of a numerical simulation to determine the resistance to cross interference as a function of t and /. The curve shown in Figure 4 is superimposed on this figure. Residues are represented by DB.
    [0031] Figure 6 shows a schematic plan view of a typical mixed source survey.
    [0032] Figure 7 illustrates schematically how different shots can be identified and extracted from the mixed source survey. DETAILED DESCRIPTION
    [0033] Although the present invention is capable of being realized in several different forms, some embodiments of it are illustrated in the drawings, and will be described in detail below. It should be understood, however, that the present disclosure should be considered as an example of the principles of the invention, not intending to limit the invention to the specific embodiments or algorithms thus described. GENERAL ENVIRONMENT OF THE INVENTION
    [0034] Figure 1 illustrates the general environment in which the embodiments of the present invention can typically be practiced. Explorers plan a 110 seismic survey to cover an area of economic interest. Field acquisition parameters (for example, shot spacing, line spacing, folding, etc.) are typically selected along with this step, although it is common to modify the ideal planning parameters slightly (or substantially) in the field to accommodate them to the realities of conducting the survey.
    [0035] Seismic data (ie, seismic traces) are collected in the field 120 on a target on the subsurface of possible economic relevance and then typically sent to a processing center 150, where they will be subjected to various algorithms to make them most suitable for use on the farm. In some cases, there may be a certain level of initial data processing performed while they are still in the field, which is becoming more and more common and feasible given the computing power now available to teams in the field.
    [0036] Note that the method achievements can be practiced during step 110 (that is, during survey planning) or during acquisition (step 120) depending on whether the time separations between successive shots are determined at the office explorer, in the field or in a combination of both.
    [0037] At the processing plant, several preparatory processes 130 are typically applied to the seismic traces to prepare them for use by the explorer. After that, the processed traces are made available for use by embodiments of the method and can be stored, by way of example only, on a hard disk, magnetic tape, magneto-optical disk, DVD disk or other mass storage media.
    [0038] The methods disclosed in this document would be best implemented in the form of a computer program 140 installed on a programmable computer 150 accessible by an interpreter or seismic processor. Note that a computer 150 suitable for use with the method embodiments typically includes, in addition to mainframes, servers and workstations, supercomputers and, more broadly, a computer or network of computers that enable parallel and massively parallel computations, where the computational load is distributed between two or more processors. As Figure 1 also illustrates, in a schematic, some type of digitized area of interest model 160 can be specified by the user and inserted as input into the processing computer program; in the case of a 3D seismic section, the area of interest model 160 typically includes details regarding the lateral extent and thickness (which can be variable and can be measured in terms of time, depth, frequency, etc.) of a target on the subsurface. The exact means by which these areas are created, selected, digitized, stored and later read during the execution of the program are irrelevant to the present invention and those skilled in the art will realize that it is possible to do so in several ways.
    [0039] A program 140 that incorporates embodiments of the method can be transmitted to the computer that is going to execute it by means of, for example, a floppy disk, magnetic disk, magnetic tape, magneto-optical disk, optical disk, CD-ROM, DVD disc, RAM card, RAM card, RAM flash card, PROM chip or network transfer. In a typical seismic processing environment, the methods of the present invention would be part of a larger package of software modules developed to perform many of the processing steps listed in Figure 2. After processing by the present methods, the resulting traces would then typically be organized in sets, stacked and displayed or on a computer monitor in high resolution 170 color or in the form of a hard copy, such as a printed seismic map or section 180. Then, the seismic interpreter would use the displayed images to help you identify subsurface characteristics conducive to hydrocarbon generation, migration or accumulation.
    [0040] As indicated above, the embodiments of the method may, without being restricted, be part of and be incorporated into a conventional seismic processing sequence of the type widely described in Figure 2. Those skilled in the art will realize that the steps processors illustrated in Figure 2 are representative only in general lines of the types of processes that can be applied to this data, in addition to the selection and order of the processing steps, and that the specific algorithms involved may vary notably depending on the seismic processor in question , the signal source (dynamite, vibrator, Sosie ™, mini-Sosie ™ etc.), the data collection location (land, sea etc.), the company that processes the data, etc.
    [0041] As a first step, and as Figure 2 illustrates in general lines, a 2D or 3D seismic survey is carried out on a specific volume of the earth's subsurface (step 210). The data collected in the field constitute non-stacked (ie, non-summed) seismic traces that contain digital information representative of the volume of the land underlying the survey. Any methods known to those skilled in the art can be used to obtain and process data in a form suitable for use by seismic processors and interpreters. Note that, for the purposes of this disclosure, the seismic survey “may be a mixed source survey in which reflections from a later source activation may interfere (for example, may overlap or overlap) with reflections from a previous source activation . After separating the shots according to the present invention, the non-stacked seismic traces resulting from this operation are used just like any other collection of seismic traces would be used.
    [0042] The purpose of a seismic survey is to acquire a collection of spatially related seismic traces on a subsurface target of some possible economic importance. Adequate data for analysis obtained by the methods disclosed in this document may consist, for illustrative purposes only, of a 2D non-stacked seismic line, a 2D non-stacked seismic line extracted from a 3D seismic survey or a 3D non-stacked portion of a 3D seismic survey. The invention disclosed in this document is more efficient when applied to a group of stacked seismic traces with an underlying spatial relationship to some other geological feature of the subsurface. Once again for illustrative purposes only, the following discussion will be expressed in terms of features contained in a 3D survey (whether stacked or non-stacked, as the discussion guarantees), although any assembled groups of spatially related seismic features can be used conceivably.
    [0043] After acquiring seismic data (step 210), these are typically taken to a processing center, where some initial or preparatory processing steps are applied to them. As Figure 2 illustrates, a common initial step 215 is developed to edit the incoming seismic data to prepare it for subsequent processing (eg demultiplexing, gain recovery, wavelet formation, removal of low quality traces etc.). This can be followed by specifying the survey geometry (step 220) and storing a number of shots / receivers and a location on the surface as part of the header of each seismic trace. After specifying the geometry, it is customary to perform a speed analysis and apply an NMO correction (normal overtime correction) to correct each trace in time in order to compensate for the signal arrival delays caused by the deviation.
    [0044] In some schemes, the method can be used in conjunction with the preprocessing step 215, that is, in conjunction with or in place of the wavelet forming / Vibroseis® correlation steps, although it can certainly be used elsewhere within that generalized processing scheme.
    [0045] After completing the initial pre-stacking processing, it is customary to condition the seismic signal in the non-stacked seismic traces before creating stacked (summed) data volumes (step 230). In Figure 2, step 230 contains a typical processing sequence “signal processing / conditioning / imaging”, but those skilled in the art will realize that many alternative processes can be used in place of those listed in the figure. In any case, the explorer's ultimate goal is to produce a stacked seismic volume or, in the case of 2D data, a stacked seismic line for use in hydrocarbon exploration on the earth's subsurface.
    [0046] As Figure 2 also suggests, any digital sample within a stacked seismic volume is uniquely identified by a triplet (X, Y, TEMPO), where the X and Y coordinates represent a certain position on the earth's surface and the coordinate time measures the arrival time recorded within the seismic trace (step 240). For the purpose of specificity, measure X corresponds to the “in line” direction and measure Y corresponds to the “in cross line” direction, since the terms “in line” “in cross line” are widely understood in the technique. Although time is the most common vertical axis unit, those skilled in the art envision that other certainly possible units may include, for example, depth or frequency. In addition, it is possible to convert seismic traces from one axis unit (for example, time) to another (for example, depth) using any standard mathematical conversion techniques known to those skilled in the art.
    [0047] The explorer can make an initial interpretation 250 of the resulting stacked volume, in which it locates and identifies the main reflectors and faults wherever they occur in the data set. This can be followed by the further improvement 260 of the stacked or non-stacked seismic data and / or the generation of attributes (step 270) from these. In many cases, the explorer will revisit its original interpretation in the light of the additional information obtained in the data improvement and attribute generation steps (step 280). As a final step, the explorer normally uses information collected from seismic data along with other types of data (magnetic surveys, gravity surveys, LANDSAT data, regional geological studies, well records, well cores, etc.) to locate structural or stratigraphic features. subsurface conducive to the generation, accumulation or migration of hydrocarbons (that is, generation of prospectus 290). EMBODIMENTS OF THE PRESENT INVENTION
    [0048] Turning to Figures 6 and 7, a terrestrial survey of a mixed source is typically collected, firstly, having a number of 610 receivers in a 2D configuration on a target of exploratory interest. In some embodiments, there can only be at least or at most several thousand 610 receivers in the survey. The 610 receivers can be connected by cables to a central recording unit, make use of wireless transmission to it or each receiver can contain a certain amount of internal data storage where to record the seismic signals received by it. Those skilled in the art are fully familiar with these types of receiver variation and how this approach can be modified for a marine survey.
    [0049] In one embodiment, 610 receivers will register continuously for an extended period of time; in some variations, receivers can register for a few hours, half a day, an entire day, several days, several months, etc. The register can capture at least two source stimuli. This differs from the typical seismic survey, in which the receivers register for just a few seconds after activating a source.
    [0050] During the period of time that the receivers register, several seismic sources 620 are activated at different locations within the survey area 600. In one embodiment, two or more sources are used. In the case of a marine survey, it is possible to use two different sources (usually suspended by two different vessels), but, of course, this is at the discretion of the survey planner. In addition, in some embodiments, the activation of the sources can be separated in time by random periods of time selected according to the methods discussed in this document. In some variations, sources can be activated close enough in time for there to be some overlap or blending between shots. That is, for example, in the case of a land survey where each 620 source is a Vibroseis® unit, it is expected that, in some cases, the activation of the sources will be separated by a few seconds. Note that Figure 6 is not intended to suggest that each source 620 be activated at the same time, but instead indicates that each source is positioned in a different place within survey area 600. During some surveys, it is possible to use ten or more different sources. More specifically, it is possible to use fifteen or more fonts; alternatively, twenty or more.
    [0051] When data are acquired in a maritime scenario, the time intervals between successive shots can typically be designed to be random. More specifically, a certain amount of randomness can be introduced by firing at the position (that is, activating the source when the vessel reaches a predetermined position), since the exact time of arrival at a trigger point is at least a little random . However, this may not be the most reliable way of introducing randomization to activation times because the speed of the vessel tends to be relatively constant and the trigger points are typically evenly spaced. That said, firing exclusively in position can introduce enough randomness when the distance between the trigger points is large. As will be explained in more detail below, and according to a variation of the present invention, some parameter associated with the distribution, by which randomness is introduced in the timing of the shots, can be controlled by the lower frequency of interest in the survey, and the expected variation of the shots from a regular interval must be at least one or more of these wavelengths. Thus, if the lowest frequency of interest produces a seismic wave of the order of 200 ms in length, the separation in time of the shots can be a constant plus some random value that can be, again, in the order of 200 ms or more .
    [0052] In some embodiments, positions and firing times spaced at random can be programmed with the firing vessel accelerating or decelerating according to what is necessary to be in the selected location at the indicated time. In other embodiments, the vessel can fire in position with firing times being monitored for randomness. In this scenario, the vessel may approach a specified position and then, instead of firing at exactly the position, it may add or subtract some time (for example, a randomly generated time setting) from the expected arrival time for it to fire intentionally a little sooner or later. The time setting can be selected to ensure that the distribution of the trigger times is at least approximately random. In addition, the random differential can be selected so that the vessel is within a specified distance tolerance in relation to the intended trigger point. Finally, the differential can be selected so that the maximum delay does not interfere with the movement of the other sources to the next short position. For this purpose, for example, the delay of the last shot is verified in order to ensure that it is not too close to the delay between the previous shots or the distribution of the trigger times is monitored to check and correct non-random patterns.
    [0053] In some cases, the software that controls compressed air weapons or other seismic sources (for example, compressed gas weapons, marine vibrators, etc.) may need to determine the vessel's location (for example, by GPS), its expected arrival time and the time since one or more previous shots in order to create a distribution of trigger activation times (or trigger time intervals) with a component that is at least pseudo-random. Alternatively, this can be done without allowing more than two shots to overlap. That said, the method's embodiments are entirely general and can accommodate multiple overlapping shots.
    [0054] Turning to Figure 7, it suggests, in general terms, what the data from a mixed source survey might look like. Note that although the source activations in Figure 7 are illustrated as distinct signals, in fact each of the successive shots would overlap to some extent. However, the sources have been separated here to clarify the concepts discussed below.
    [0055] Each 610 receiver generates a seismic trace (for example, trace 705) that can potentially be tens of minutes or several hours (or days, months, etc.) in length. In this figure, trace 705 is illustrated schematically containing signals recorded from four different source stimuli in a mixed source survey. It is possible to associate to each 610 receiver a location on the earth's surface. When the signals recorded by each receiver 610 are properly organized and displayed, in one embodiment, a 3D volume is produced with each receiver 610 associating a “X” location and a “Y” location to include locations based on latitude and longitude etc.
    [0056] During a mixed source survey according to an aspect of the revealed method, the time that each 620 source is activated can be demarcated and recorded; said sources may be located within or outside the receiver's field. In Figure 7, T1 and T2 represent the known times (as measured from an arbitrary zero time) at which two sources were activated, in which the parameter “N” indicates, in general lines, the length of the time (number of samples) after activating a source, during which reflections of the subsurface from a source can be detected. Time separations between successive shots are indicated by TI, T2 etc.
    [0057] Turning now to a discussion on how to determine random spacing according to a first embodiment of the present invention, a method for seismic exploration with activated seismic sources is proposed at the same time that they can be separated from more accurately and immediately afterwards. In summary, the revealed method creates a time spacing between overlapping sources, in which the spacing is done randomly based on the expected frequency content of the data.
    [0058] Although there has been much discussion as to which magnitude of random separations over time would produce the best results, there is little quantitative guidance regarding the level of randomness that should be implemented. However, the embodiments of the revealed method, without attaching to the theory, demonstrate that the quality of separation of the shots depends to a large extent on the lower desired frequency and the size of the random shifts between shots within a given analysis window.
    [0059] It has been shown that, in the case of data mixing in order to accelerate the generation of images by migration, there is a concept of resistance to cross interference that varies depending on the frequency (w) and the separation in time between lines ( T): sin2 (or) '(('> T) 2, Figure 3 shows a graph of resistance to cross interference versus wt. In it, resistance to cross interference is given by the vertical axis and wt is given by the horizontal axis. it is assumed that the first zero of this equation occurs when wt = π. This value of wt represents a sensible limit value for the force of the cross interference in relation to a and t. Since f = 2 π w, it is deduced that the theoretical value of π to obtain a zero cross interference for a given frequency is T = 1 / (2 /) .This equation is represented in Figure 4.
    [0060] This equation defines a quantitative model to select a verifiable separation in time between successive / overlapping shots in a mixed source survey. As can be seen in Figure 4, for a given frequency, a uniform random distribution with a half-width of at least T is generally a very good or practically ideal choice for a good separation between sources. The area below the curve shows where the combination of w and T is expected to produce poor quality results. The area on the curve is where the combination of w and T is expected to produce good results.
    [0061] For example, if a very good separation is desired, the value of T must be selected well above the curve. If a lower separation is acceptable, the tau value is selected just below the curve to allow for a more flexible acquisition schedule. The disadvantage, of course, is that the higher the tau the longer the withdrawal will take and the more it will cost. Thus, the maximum acceptable value of tau can, in practical terms, be limited by economic considerations, and there may typically be an incentive to select tau as close to the curve in Figure 4 as possible for a given data set.
    [0062] Figure 5 shows the result of some numerical experiments in which synthetic data were created with a frequency range and these data merged with a shift range with uniformly distributed half-width T. An inversion was calculated for each combination of tau and frequency, and the residual, which is the measure of the difference between the calculated data and the data before mixing, is illustrated in this figure. It can be seen that, in general terms, the quality of separation closely follows the limits above (for example, the lowest values tend to be found in the upper right corner, whereas the highest values tend to be found in the lower left corner. ). This observation is consistent with the discussion on Figure 4, in which it was shown that the best results tended to be found above and / or to the right of the plotted curve. To help understand Figure 5, the curve of Figure 5 was superimposed on it. The residues in Figure 5 are represented by DB.
    [0063] In practice, there is likely to be some randomness in the trigger time that allows separation based on a coherence criterion, but, in view of the above, a purely random sequence is unlikely to be ideal, especially with the large number of shots used in a typical seismic survey. Random sequences can contain unwanted random regularities that can impair the quality of the separation. Since coherence is calculated within a limited space window, a series of random numbers of only a limited length is required. In some embodiments, this set of random numbers can be selected from a large sample of sequences of series of uniform random numbers (or generated using, for example, a pseudo-random number generator) to produce the best separation.
    [0064] As an example of how to do this, a series of random numbers, say with 101 numbers, can be taken from a collection with 100,000 sets of series with 101 random numbers. Each of the 100,000 series with 101 random numbers would be examined for the quality of separation it produces. The best series would be used to create the random time shifts used to perform the survey with simultaneous sources.
    [0065] Returning to the previous example, in the case of 2D data sets, the series would be reused along the line, circulating through 101 numbers along the firing line. In the case of 3D data sets, using the same set of random numbers on each firing line would create unwanted regularities in the transverse line direction. One method to avoid this regularity would be to create a random set of indexes in the series with 101 random numbers. These indexes would be used to select a starting random number within the series for each row. One method for avoiding unwanted regularities in the random set of indexes would be to force each index to be outside a given range of the last several lines. For example, if the coherence window has 8 dashes in the transverse direction and 10 in the inline direction, each index would be required not to repeat within 8 lines and each index would not be 10 elements away from the other. Another method for selecting indexes would be to select a set of random numbers and simply test a large number of random sets of indexes to see which would produce the best separation. Although computationally expensive, this would only need to be done once.
    [0066] In practice, when the random adjustment value, or obtained in some other way, is negative, the operator can fire before planned. For example, in a marine scenario, if the setting is prescribed to -0.2 seconds, you can lightly accelerate the vessel to reach the next trigger point before its programmed 5-second firing interval (for example). Alternatively, firing can be done earlier, for example, before reaching the actual trigger point. Given that the maritime location / positioning technology is accurate in only about 1 meter, the trigger just before (or after) could very well still be seen as at the trigger point for the purpose of positioning the registered traces. Finally, delays and early arrivals due to wind, waves etc. they can overwhelm the small time adjustments of the present methods, but in some embodiments, the crew can be instructed to fire as close to the prescribed time as possible.
    [0067] As an alternative to the programmed times, random times can be obtained by adding randomness to the actual trigger positions. Considering, in the case of a marine survey, that the speed of the vessel is constant, the randomness in the times could be controlled by the randomness of the position. An advantage of this approach is that the survey could be reacquired, say, for time-lapse measurements, with the same random trigger positions. It tends to be easier to repeat trigger positions than random times. Another advantage of this method is that it would not require any changes to the weapon control software, as it would be necessary to introduce random times.
    [0068] After acquiring the data, the records can be separated into individual lines typically by inversion using the method disclosed in United States patent application 12 / 542,433, “Method for separating independent simultaneous sources”, filed on August 17 of 2008, the disclosure of which is incorporated into this document as set out in full in this section, although other methods of separation or stacking interferences require limits similar to disturbances in random time.
    [0069] In some embodiments, the method can be adapted for use with a VSP survey, verification shot or similar downhole. By way of explanation, those skilled in the art can understand that the acquisition of VSP can be very costly due to the probe's idle time. The faster firing of VSPs with overlapping sources could be used to significantly lower the costs of these surveys. Therefore, when the phrase “mixed seismic survey” is used in this document, it should be interpreted in the broad sense, to include 2D and 3D surveys both on land and at sea, as well as VPSs, cross-hole tests, etc.
    [0070] Note that when phrases such as "lower frequency of interest", "lower frequency desired" etc. are used in this document, they must be interpreted in the broad sense, so as to mean a frequency that is within the seismic source and / or that registers bandwidths and, in practical terms, tends to be the lowest useful frequency returned by the survey seismic.
    [0071] In addition, although the preferred embodiment uses the ratio T = 1 / (2 /) as a means to define the separation in the minimum acceptable time as a function of frequency, it must be kept in mind that there are several other curves that can approximate this relationship over some frequency range. For example, between 1 Hz and 6 Hz, the tau / frequency ratio equation can be approximated in an acceptable way by a second polynomial degree, or higher polynomial degree, in frequency (for example, obtained by the standard least squares technique or other techniques adjustment). Larger polynomials (or other functional forms such as exponentials, logs, etc.) can provide a better fit. At other frequency ranges (for example, 3 Hz to 6 Hz), even a linear approximation could provide useful information. Therefore, it should be borne in mind that, for the purposes of the present invention, when it is said that the equation identified above is used to find an acceptable tau, it must be interpreted in the broadest sense, to include circumstances in which approximations Functional or numeric values for that curve (over short intervals or its total length) are used instead.
    [0072] Furthermore, it should be kept in mind that the figures and examples included with this document were produced considering that the random separations in time between successive source activations were derived from a uniform probability distribution centered around zero with a half-width tau. The fact that the distribution was centered around zero (that is, the uniform distribution has an expected value equal to zero) is only one approach and the distribution could certainly be changed (either towards positive or negative values) by centering it around a non-zero value, thus producing random time separations prone to positive (or negative) values.
    [0073] In addition, note that different probability functions could be used in place of uniformity to generate random separations over time. In these circumstances, it may be advantageous to select a distribution parameter, such as the standard deviation (or variance, or another measure of variability or spread, or some other measure of central tendency such as mean, median, etc.), to be a function of ( 1//). In the case of the example discussed previously, a uniform distribution centered around zero with half-width equal to tau can have a variance s2 equal to:

    [0074] In other words, this equation indicates that, if tau is selected to be on the 1/2 / curve, the variance of the associated uniform distribution will be 1 / (12f2).
    [0075] This suggests that, in general terms, the lowest frequency of interest must be related to a parameter of the probability distribution from which random time differences are deducted. More specifically and by way of example, in some embodiments, the variability of the distribution from which random times are deducted must be related (in proportion to this, depending on this etc.) to the inverse of the lower frequency of interest in the survey (for example , [1 / C /], where C is a constant). An acceptable relationship between variability and frequency possibly needs to be determined for each case depending on the choice of the probability density function and according to economic disadvantages. By way of example only, one way to develop the curve of Figure 5 for a non-uniform distribution would be to calculate the surface of Figure 4 and identify an isoresidual curve that more or less divides acceptable and unacceptable residues. That said, those skilled in the art will readily be able to deduce other ways to obtain this curve (for example, by Monte Carlo simulation).
    [0076] In the preceding discussion, jargon was expressed in terms of operations carried out on conventional seismic data. However, those skilled in the art will realize that the invention described in this document can be advantageously applied to other areas and used to locate other minerals on the subsurface in addition to hydrocarbons.
    [0077] Although the inventive device has been described and illustrated in this document with reference to certain embodiments in relation to the attached drawings, various changes and other modifications, in addition to those illustrated or suggested in this document, can be carried out by those skilled in the art without leaving the essence nor of the inventive concept, the scope of which the following Claims will determine.
    权利要求:
    Claims (13)
    [0001]
    1. Method for Seismic Exploration on the Subsurface Region, which contains structural or stratigraphic characteristics conducive to the presence, migration or accumulation of hydrocarbons, the method being characterized by comprising: a. determine the lowest frequency of interest in a mixed source seismic survey; B. use said lower frequency of interest to determine a value representative of a variability in a probability distribution; ç. start recording at least one seismic receiver positioned close to the subsurface region; d. activate a first seismic source; and. registering the first seismic source by means of said at least one seismic receiver; f. determining a random period of time using said probability distribution and said determined variability; g. wait a period of time at least equal to that random period of time after activating said first seismic source and then activating a second seismic source; H. recording said second seismic source by means of said at least one seismic receiver; i. perform at least steps from (d) to (h) several times, thus conducting a mixed source seismic survey; and j. use the aforementioned mixed source seismic survey to explore hydrocarbons in the referred subsurface region.
    [0002]
    2. Method for Seismic Exploration over the Subsurface Region, according to Claim 1, characterized in that said probability distribution is a uniform probability distribution.
    [0003]
    3. Method for Seismic Exploration over the Subsurface Region, according to Claim 2, characterized in that said uniform probability distribution has a half-width tau, wherein said tau is said value representing a variability of said distribution of uniform probability and in which
    [0004]
    4. Method for Seismic Exploration Over the Subsurface Region, according to Claim 3, characterized in that said uniform probability distribution is centered around zero.
    [0005]
    5. Method for Seismic Exploration Over the Subsurface Region, according to Claim 1, characterized in that said at least one seismic receiver comprises a plurality of seismic receptors.
    [0006]
    6. Method for Seismic Exploration Over Subsurface Region, according to Claim 1, characterized in that both the first and second seismic sources are impulsive sources.
    [0007]
    7. Method for Seismic Exploration of the Subsurface Region, according to Claim 1, characterized in that both the first and second seismic sources are marine sources.
    [0008]
    8. Method for Seismic Exploration Over Subsurface Region, according to Claim 1, characterized in that both the first and second seismic sources are terrestrial sources.
    [0009]
    9. Method for Seismic Exploration Over the Subsurface Region, according to Claim 7, characterized in that the first and second seismic sources are selected from a group consisting of a compressed air gun, a compressed gas gun and a vibrator.
    [0010]
    10. Method for Seismic Exploration over the Subsurface Region, according to Claim 8, characterized in that the first and second seismic sources are selected from a group consisting of a source of dynamite and a source of vibration.
    [0011]
    11. Method for Seismic Exploration of the Subsurface Region, according to Claim 1, characterized in that said first and second seismic sources are the same seismic source.
    [0012]
    12. Method for Making Seismic Survey of Mixed Sources on the Subsurface Region, which contains structural or stratigraphic characteristics conducive to the presence, migration or accumulation of hydrocarbons, the method being characterized by understanding: a. determine the lowest frequency of interest in said mixed source seismic survey; B. use said lower frequency of interest to determine a representative value of at least one parameter of a probability distribution; ç. start recording at least one seismic receiver located close to the subsurface region; d. activate a first seismic source; and. use said at least one seismic receiver to record one or more reflexes resulting from the activation of said first seismic source; f. using said probability distribution and said representative value of at least one parameter of said probability distribution to determine a delay; g. wait a period of time at least equal to said delay after activating said first seismic source and then activating a second seismic source; H. registering the second seismic source by means of said at least one seismic receiver; i. perform at least steps from (d) to (h) several times, thus conducting a mixed source seismic survey; and j. use at least part of the aforementioned mixed source seismic survey to explore hydrocarbons in the referred subsurface region.
    [0013]
    13. Seismic Exploration Method, characterized by understanding: a. access at least part of a mixed source seismic survey carried out over a subsurface region with structural or stratigraphic characteristics conducive to the presence, migration or accumulation of hydrocarbons, in which the referred mixed source seismic survey is collected by: (1) determining the lower frequency of interest in the mixed source seismic survey; (2) use said lower frequency of interest to determine a value representative of a variability in a probability distribution; (3) start recording at least one seismic receiver positioned close to the subsurface region; (4) activate a first seismic source; (5) recording said first seismic source by means of said at least one seismic receiver; (6) determining a random period of time by means of said probability distribution and said determined variability; (7) wait a period of time at least equal to said random period of time after activating said first seismic source and then activating a second seismic source; (8) registering the second seismic source by means of said at least one seismic receiver; and (9) carry out at least the steps from (4) to (8) several times, thus leading to said seismic survey of mixed source; and b. use at least part of the aforementioned mixed source seismic survey to explore hydrocarbons in said subsurface region.
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    AU2012205525A1|2013-08-01|
    CN103314310A|2013-09-18|
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    法律状态:
    2018-12-18| B06F| Objections, documents and/or translations needed after an examination request according art. 34 industrial property law|
    2019-12-24| B06U| Preliminary requirement: requests with searches performed by other patent offices: suspension of the patent application procedure|
    2020-10-20| B09A| Decision: intention to grant|
    2020-12-22| B16A| Patent or certificate of addition of invention granted|Free format text: PRAZO DE VALIDADE: 20 (VINTE) ANOS CONTADOS A PARTIR DE 12/01/2012, OBSERVADAS AS CONDICOES LEGAIS. |
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    US61/431,943|2011-01-12|
    PCT/US2012/021031|WO2012097122A1|2011-01-12|2012-01-12|Shot scheduling limits for seismic acquisition with simultaneous source shooting|
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