EA040720B1 - SURVEY WITH INDEPENDENT SIMULTANEOUS EXCITATION AND RECORDING OF A VERTICAL SEISMIC PROFILE - Google Patents

Description

This application claims internal priority under U.S. Patent Classification Index 35 §119(e) under Provisional Application No. 62/057320, filed September 30, 2014. No. 13/867705, which is called Seismic Survey Method filed April 22, 2013 on behalf of David John Howe, and is a continuation of U.S. Patent Application No. 12/310204 Seismic Survey Method filed August 30, 2007 on behalf of David John Howe, and is now retired. All applications are owned by the same copyright holder and are hereby incorporated by reference for all purposes as if they were set forth verbatim herein.

The field of technology to which the present invention relates

The method disclosed herein relates to vertical seismic profiling in seismic exploration and, in particular, to the collection (survey) and processing of seismic profiling data.

Background of the Invention

Seismic survey, sometimes also referred to as geophysical surveys, is a field of technology that deals with indirect recognition of the structure, composition and content of subterranean formations. This usually involves the transmission of acoustic signals with specific characteristics into the interior of the Earth. The specific characteristics of the acoustic signals are tuned because not all acoustic signals are suitable for this purpose. These tuned acoustic signals are commonly referred to as seismic signals. Different features in the subterranean strata (thickness) will reflect these seismic signals, which are then recorded at the surface of the earth, at the seabed, or in a well/wells drilled in the underground strata. The recorded reflections can then be analyzed to obtain information about the subterranean strata.

The process of transmitting acoustic signals and recording their reflections is often referred to as seismic surveying; There are countless modifications in this field of technology. For example, depending on spatial and temporal coverage, there are 1D (1D), 2D (2D), 3D (3D) and 4D (4D) surveys. Similarly, depending on whether the survey is on land, in the water, or in a land-to-water transitional zone (e.g., tidal zones, intermittent flooding, swampy areas, etc.), there are terrestrial, marine, and shooting in the transition zone.

These modifications often have significant technological differences. For example, in land surveys, the energy of a seismic signal propagates in the form of both transverse and longitudinal (elastic) waves. However, due to the differences between land and water, energy will only propagate in water in the form of longitudinal waves. Therefore, different information is recorded in terrestrial and marine (under- or surface) surveys. As a result, the types of sensors that are used in terrestrial surveys are different from the sensors that are used in marine surveys. To the extent that the same types of sensors can be used in marine surveys as in land surveys, they are used to determine the direction of propagation of P waves, but not S-waves. For this reason, technologies and methods of different types of surveys cannot necessarily be transferred from one type of seismic survey to another.

One type of seismic survey is a borehole seismic survey. In such a seismic survey, seismic sensors are located in a borehole or boreholes drilled in subterranean formations. These surveys are usually used to clarify or additionally study the characteristics of underground strata not over a vast area, but in the immediate vicinity of the wellbore. A particular type of borehole seismic survey is known as vertical seismic or VSP survey. A VSP survey differs from most other types of seismic surveys in several ways. Perhaps most unusual is that the receivers are positioned vertically downhole, while on land or sea they are positioned horizontally.

3D VSP seismic surveys have found their way into the industry and continue to receive attention in the art. Many methods have been developed for use in 3D VSP seismic surveys. Many of them have been shown to serve their intended purpose. However, this technical field is always open to improvements or alternative means, methods and configurations. Therefore, the method described herein will be carefully considered in the art.

Brief description of the figures

The accompanying figures, which are incorporated in and form part of this document, illustrate embodiments of the present invention and, together with the description, serve to explain the principles of the present invention. The figures show the following:

in fig. 1 depicts one particular embodiment of a marine VSP survey in accordance with one aspect of the method disclosed herein;

in fig. 2A-2C show data acquisition in the survey of FIG. 1, while in FIG. 2A is a plan view of the device and marine profiles, and FIG. 2B-2C depict alternative actuation patterns;

in fig. 3 for the present embodiment shows a seismic transmission scheme.

- 1 040720 data from the point of collection to the point of processing;

in fig. 4 is a schematic representation of the individual parts of the software and hardware architecture as they may be used in some aspects of the method disclosed herein;

in fig. 5 schematically shows separate parts of the software and hardware architecture of one particular computing device that is used to process seismic data in the present embodiment.

Description of Embodiments

The following is a detailed description of the embodiment(s) of the present invention, an example(s) of which(s) are shown(s) in the accompanying drawings. Wherever possible, the same numerals will be used to refer to the same or like parts in the figures.

In FIG. 1 depicts one specific embodiment of a VSP seismic survey device 100 in accordance with one aspect of the method disclosed herein. On the receiving side, the apparatus typically includes a number of seismic receivers 105 (only one indicated) that are located in the borehole 110 drilled from the bottom 115 of the sea into the subsurface 117. The seismic receivers 105 are suspended from a cable 120 that extends from the drilling rig 125 into the underground 117.

The VSP seismic survey 100 is a VSP marine seismic survey because it is performed in a marine environment. Those skilled in the art will appreciate that the term marine does not necessarily imply that the water column 130 is salt water. The water column may consist of fresh and slightly mineralized water. Thus, although the water in the embodiment of FIG. 1 is truly marine, in other embodiments it may be fresh or brackish. However, the term marine actually distinguishes the present seismic survey from, for example, a VSP land seismic survey or a VSP seismic survey in the transition zone. In one embodiment, a VSP survey employs three-dimensional (3D) imaging using downhole receiver arrays and a two-dimensional (2D) grid of seismic source (or seismic source) locations at the surface; such a survey is referred to as a 3D VSP survey. Accordingly, in embodiments, the survey may be a 2D or 3D VSP survey, but the following description will refer to a 3D VSP survey.

The type of drilling rig 125 may be any known in the art and will depend on well-known considerations such as cost, location, and depth of operation. Depending on these factors, various drilling rigs are currently used in the industry, such as drilling ships, semi-submersible drilling platforms, jackup floating drilling rigs and submersible drilling rigs. The drilling rig 125 in the present invention is semi-submersible, but for the practical use of the method disclosed here, the type of drilling rig does not matter. In other embodiments, any of the above (drill ship, jackup floating drilling rig, submersible drilling rig) or any other type of drilling rig known in the art for offshore use may be used.

Those skilled in the art will appreciate that many wellbore applications use casing to maintain the integrity and structure of the wellbore walls. The wellbore 110 is shown without casing, so such a well is known as an open well. This is done for simplicity and clarity. In most embodiments, the wellbore 110 will typically be cased. However, for the method disclosed here, it does not matter if the wellbore 110 is cased or not. Moreover, other embodiments may also include a number of wellbores 110, each containing a number of sensors 105.

Fig. 1 was also simplified by the lack of subsea wellhead equipment. Depending on the implementation, such equipment may include, for example, a bottom conductor, a low pressure casing, a high pressure casing, a casing hanger, a metal-to-metal annulus seal, protective sleeves, and replaceable liners. Those skilled in the art who understand the benefits of the present disclosure will appreciate that specific implementation details will include not only such equipment, but also how it interacts with the method disclosed herein.

It is shown that the wellbore 110 is drilled and passes in the underground strata 117 in a strictly vertical direction. Those skilled in the art who understand the benefits of the present disclosure will appreciate that wellbores are often drilled in such a manner that they deviate from vertical. Sometimes this deviation can be quite significant. It is widely known in the art that a wellbore can be deviated from vertical in a variety of ways, and thus the method disclosed herein is not limited to using wellbores that run vertically without being deviated.

- 2 040720

In the present embodiment, the receivers are seismic receivers 105. 3D VSP techniques theoretically assume that sensors located in the wellbore may not be receivers, but sources. However, this is rarely the case due to the danger that the operation of the sources may compromise the integrity of the wellbore. In the illustrated embodiment, each receiver includes three geophones (one for each of the x, y, and z axes in Cartesian coordinates) and a P-wave transducer for use in p-z (pressure and z-axis) stacking. Other embodiments of the invention may use different configurations of geophones, hydrophones (transducers of transverse waves), or both. Other embodiments of receivers include, but are not limited to, fiber optics, microelectromechanical systems (MEMS), accelerometers, rotation sensors, or any combination of the receivers listed above.

Let's return to Fig. 1; on the source side, the device includes a number of seismic sources 135 (only two are shown), a number of towing boats 145 towing them over the surface 140 of the water. The sources may be of any type known in the art. In the embodiment shown, the seismic sources 135 are of the type of impulsive sources known in the art. Or, more precisely, the seismic sources 135 are air guns. However, other types of sources may be used in other embodiments. For example, some embodiments may use impulsive sources such as seismic sweep generators (sweep sources).

Those skilled in the art will appreciate that airguns are typically deployed in groups rather than single sources. This is also true for the presented embodiment. Each of the seismic sources 135 is deployed in a group 150, which consists of identical seismic sources 135. The number of airguns (i.e., seismic sources 135) in the group will be a specific implementation detail and will depend on factors that are well known to those skilled in the art. Groups 150 are shown to contain eight airguns, but this is for illustrative purposes only.

In the illustrated embodiment, two towing boats 145 are involved. As shown in FIG. 2A, the shooting area 200 is divided into two shooting areas 205, 210. In the illustrated embodiment, the two survey areas 205, 210 are equal half of the survey area 200. In other embodiments of the present invention, the two survey areas 205, 210 may divide the area into unequal portions. The image in FIG. 2A is also simplified in various ways. For example, the survey area 200 does not need to be a regular geometric shape, and may be much larger than the towing vessels 145 and the drilling rig 125.

The method disclosed here uses at least two seismic sources 135 at two survey sites 205, 210 on the surface 140 and, respectively, two towboats 145. In other embodiments of the invention, a different number may be used, such as three or four seismic sources groups) in three or four shooting areas. Theoretically, in any particular embodiment, there is no limit to the number of survey sites, towing vessels 145, and seismic sources 135 or arrays 150. However, from a practical point of view, their number will be limited by economic considerations.

The marine seismic survey 100 is performed in accordance with a predetermined survey project, in which each of the towing vessels 145 and the drilling rig 125 are assigned respective parts. Each of the two vessels 145 and the drilling rig 125 is equipped with a computing device (not shown) into which this information is downloaded and stored. For tugboats 145, this information is a sea profile chart 155, and for a drilling rig 125, this is a registration chart 160.

Conducting a 3D VSP marine seismic survey 100 differs from the state of the art at least in that it uses independent simultaneous source excitation, i. in the embodiment shown, the seismic sources 135. This may be called independent simultaneous excitation of the sources. As used herein, the term independent simultaneous source firing may refer to a plurality or number of seismic sources or source groups that are divided into at least two groups. The sources in each group operate independently, i.e. without coordination or with very weak coordination with the triggering of seismic sources in another group (other groups). While the seismic sources in these groups fire independently, they fire at the same time or in the same firing window as the seismic sources in the other group(s). In the illustrated embodiment, each of the two vessels 145 tows its own group 150 in a pattern that is both spatially and temporally independent of the others, which operate in accordance with their own sea profile patterns 155. Similarly, while following their sea profiles 215, shown in FIG. 2A, the seismic sources fire regardless of what is happening in the other survey area.

The term simultaneous is used in the sense that the recorded information from excitations (explosions) actually interfering with each other is superimposed, and not in the sense that

- 3 040720 that the excitations occur at the same time. For example, the first source may fire at the first time, and the second source may fire at the second time, with at least a portion of the initial pulse from the firing of the first source superimposed on the pulse of the second source. Another common industry name for this type of excitation is mixed excitation, a name that emphasizes that the explosions simply interfere with each other.

This independent simultaneous firing of sources introduces a certain degree of randomness into the seismic record. This is an expected feature of the present shooting method. For example, this eliminates the need to match excitations from different sources, as well as the location of these sources during their excitation. This greatly reduces the functional limitations during shooting. Independent simultaneous firing is not entirely new in the art of seismic surveys, which are performed both onshore and offshore. One example can be found in US Patent Application No. 12/310204, filed Aug. 30, 2007 on behalf of David John Howe (application 204).

The method disclosed here also differs from application 204 in that it describes the use of a plurality of vibratory seismic signal sources, with each of the sources having a characteristic waveform. In the method disclosed here, it is desirable that all seismic sources have the same waveform. Differences in the pulse shapes of the sources can be tolerated if they are small enough and can be corrected during processing, as described below. However, in some embodiments, seismic sources with different sweep signals may be used. And as described below, the illustrated embodiments use pulse sources rather than sweep sources.

Another difference between the method disclosed here and conventional 3D VSP marine seismic surveys is continuous acquisition. In conventional practice, the times and locations of the excitations are known, so the arrival time of the reflections at the receivers can be predicted. Therefore, in traditional practice, registration is usually performed in the time window within which the arrival of reflections is expected. In the method disclosed here, the random nature of independent simultaneous excitations of sources makes such a priori knowledge impossible, so registration is performed continuously.

Let's return to Fig. 2A; each of the towing vessels 145 tows its respective seismic sources 135 along sea profiles 215 independently of the others and in accordance with its sea profile patterns 155. As mentioned above, those skilled in the art will appreciate that the tugboats 145 carry computing resources. Among other tasks, they can implement the sea profile scheme 155, including automatic posting along the sea profiles 215 and excitation of sources. However, those skilled in the art will also appreciate that it is not uncommon for various reasons to stop filming using the towboat 145 or otherwise disable the auto-guidance. One of the advantages of independent simultaneous excitation of sources in the method disclosed here is that when one tugboat 145 stops working, it is not necessary to stop the work of others.

Starting points 220 and ending points 225 for each of the tugboats 145 on the respective sea profiles 125 are indicated by dotted leader lines. Start points 220, end points 225, and sea profiles 215 may be designed to provide specific coverage of the subterranean 117 in accordance with conventional practice. The marine profiles 215 of the present embodiment are in the form of a racing track or an elongated oval with flattened ends. In other embodiments, other forms may be used.

In the most common embodiment, a regular rectangular grid of shot points is created in the study area, while the movement between profiles on a regular grid of shot points during the survey occurs along curvilinear trajectories. Curvilinear trajectories between the ends of the profiles may or may not have active burst points, but the racing track configuration allows for efficient surveying by minimizing turnaround time, allowing for smooth turns and avoiding entanglement (overlapping) of source groups or reducing the effectiveness of paravanes , which maintain the correct position of the airgun groups.

Each towing vessel 145 advances along segment 230, reaches its end 235, after which the towing vessel 145 passes to segment 240 and follows it to segment 245. The towing vessel 145 then proceeds in the opposite direction along segment 245, from which it passes to segment 230. Then, at end 250 of leg 240, tugboat 145 transitions along leg 252 and enters the start of the next leg 230. This process is repeated until the last leg 245 has been passed and towboat 145 has reached end point 225.

As the tugboat 145 passes through the legs 230, 245, it excites the seismic sources. These excitations are random compared to other towing vessel(s) 145 as described above. In this case, this means that between the operation of two

- 4 040720 groups of seismic sources there is no consistency or it is very weak. Therefore, it is not necessary to synchronize or coordinate the activation of seismic sources towed by one of the towing vessels 145 with the activation of seismic sources towed by another towing vessel 145.

The triggering in each group of seismic sources does not necessarily occur randomly within the respective own scheme 155 sea profiles. That is, within each group of seismic sources towed by the respective towing vessel 145, the firing pattern is scheduled such that each actuation is consistent with the actuation of another seismic source in that group. The seismic sources (ie, in the present embodiment, the seismic sources 135) fire sequentially, averaging every 5-10 seconds. Note that other embodiments may use different excitation schemes, in particular, they may use different types of seismic sources.

Generally, there are three ways to ensure that explosions from one set of sources are close to random compared to another set of sources. The first way is to have the source vessels move at different speeds and the time interval between the explosion points is sufficiently regular, and the interval with which the interference repeats is long enough so that the interference can be considered random. The second way to make the two source vessels work randomly is to make the distance between the explosion points irregular. In the third method, the distance between burst points is regular, but a small (±250 ms) random perturbation is added to the expected arrival time at each source location. While the ship speed mismatch usually makes the time between bursts random enough to give a good separation at the processing stage, the additional introduced randomness ensures that when natural randomness becomes insufficient, the bursts are at least random in time. Taken together, the randomness of explosions from different ships provides significant randomness in the times of explosions from interfering ships.

Although the two groups of seismic sources fire independently of each other, they also fire at the same time, i.e. simultaneously. In particular, two groups of seismic sources are triggered within the same trigger/registration window. This does not mean that individual seismic sources fire at the same time or at the same time, although this may happen by chance. In contrast, the seismic sources in each group fire at the same time period with no relationship to the exact firing time of the seismic sources in the other group. Another common industry name for this type of excitation is mixed excitation, a name that emphasizes that the explosions simply actually interfere with each other.

While shooting in this way can be done using conventional airgun firing, in which all airguns in a group fire simultaneously, the present embodiment uses a popcorn firing method similar to that disclosed in U.S. Patent Application No. 13/315947, issued December 9, 2011 on behalf of Alan Ross and Raymond Lee Abma (application 947). With this approach, seismic sources in a group of seismic sources fire individually in time in order to reduce the maximum power of the group. Seismic excitations in a circuit can result in lower peak sound pressure levels than conventional marine airgun arrays and still retain approximately the same energy.

In the illustrated embodiment, the air guns in groups 150 are three different sizes. Many different sizes of air guns are known in the art. Known sizes include, for example, 40, 70, 80, 100, 120, 140, 175, 200, 250, and 350 cubic inches. In some embodiments, groups of air guns of the same size or groups of air guns of different sizes may be used. For the purposes of the present invention, the dimensions of the air guns should be classified as large, medium and small, since there are three of them, and the numerical values will depend on the specific implementation.

The seismic sources are triggered in accordance with a trigger plan 250 pre-loaded onto the towing vessels 145 and defining a trigger pattern for the sources. The firing pattern depends on several factors such as the time period from the firing of the first seismic source to the firing of the last seismic source, the firing order of the sources, the time intervals between firings, and the amplitude required from each individual group in the scheme. The specific values of these factors in any given embodiment will depend on the particular implementation.

For example, the length of the actuation pattern may be in the approximate range of 1 to about 4 seconds, or 0.5 to 2 seconds, or 3 to 10 seconds. The time interval between firings may be in the approximate range of 50 to 500 ms, or 150 to 250 ms, or 250 ms to 1 s. The method disclosed herein allows for greater flexibility in these factors.

However, the period of time during which the excitations are carried out depends on the maximum amplitude that is expected from the pulse shape of the excitation circuit, and on the expected

- 5 040720 excitation resolution. A very short period of actuation time will result in single actuations of the guns, whose peak amplitudes tend to add up by design, as well as the maximum amplitude of the actuation pattern, which amplitude will be insignificantly lower than that of a conventional group of airguns. A circuit with a long response time will give recovered excitations that are blurred in space due to the movement of the vessel. The balance of these factors will depend on the particular implementation and may well be achieved by those skilled in the art who understand the benefits of the present disclosure. The firing order of the guns and the spacing between firings can be used to separate the largest guns in the sequence so as to minimize the summation of the powers of the individual guns and to prevent minimization of the amplitudes when firing the pattern.

In the embodiment shown, the excitation in each of the groups 150 in each of the sections 205, 210 will occur according to the corresponding trigger pattern. Triggering schemes should be different so that the dips in the spectrum of neighboring explosion points do not strongly overlap each other. For example, at least one trace in a processing window should produce significant energy in the expected bandwidth, where a typical processing window width is between 5 and 40 traces. The concept of significant energy will depend substantially on the environment in which the survey is being conducted, as will be understood by those skilled in the art who understand the benefits of the present disclosure. For low interference data, getting even 5% of the expected output will be enough to accurately reconstruct the desired signal. With highly noisy data, it may take 50% of the expected output to accurately reconstruct the signal.

In order for neighboring circuits to have a significant degree of randomness, it is necessary to create a sufficient number of circuits. That is, sequential operation schemes can all differ from each other. Any number of trigger patterns can be created and used within the disclosed methods. This number may be limited by the number of sources in the group and also by the limits and parameters chosen for the trigger patterns.

The firing order of the guns in any particular source circuit is related to the dips in the spectrum of the individual circuits. It is desirable that the notches in the spectrum cover a wide range of different frequency ranges. Because the firing order of the individual sources in any given circuit is an important factor for the maximum amplitude of any single circuit, the timing of each source must be carefully calculated and controlled.

In the embodiment shown, the excitation can occur either in continuous mode (as shown in FIG. 2B) or in a time-lag mode (as shown in FIG. 2C). Explosion icons in these drawings show the triggering of the corresponding source from S1 to S ₈ and their relative sizes reflect the relative sizes of the sources.

The continuous drive mode, which is shown in FIG. 2B may also be referred to as continuous circuit excitation or continuous actuation circuits. The continuous drive mode in FIG. 2B includes one drive circuit 255. With regard to FIG. 2C, the time lag mode may also be referred to as discrete circuit drive or discrete actuation circuits. Each source S1-S ₈ drives two operation circuits 255, 260, which are separated in time by a delay t _D . Schemes 255, 260 operation are not the same.

These two modes of excitation primarily differ in the presence of a delay time t _D . We can assume that the continuous mode of excitation is the same as the mode with a delay and a delay value t _D =0. When pattern or sequential excitation is used with a continuously varying source pattern as it moves along the excitation line, bursts can be divided into reconstructed bursts of either large or small spatial extent. The recovered burst intervals are then used as a processing parameter.

Let's return to Fig. 1; the transmitted seismic signals 165 travel through the water column 130, meet the seabed 115, and continue to propagate to a reflector 170 that reflects a portion of the seismic signals 165. Those skilled in the art will appreciate that, for the purposes of this disclosure, this description and depiction are simplified. For example, the sea floor 115 is also a reflector, but the reflections (not shown) from it are unimportant because they do not contain information about the subsurface layer 117. In addition, any stratum studied will typically include many reflectors, and these reflective horizons will be more complex than what is shown. Such details will be understood by those skilled in the art, who will appreciate the benefits of using the present invention.

While the seismic sources are fired, the seismic receivers 105 record reflections 175. The receivers digitize the received reflections 175 for digital recording. There are many approaches to registering and collecting the resulting data. In the embodiment shown, the received data is transmitted for recording via cable 120 to a computing device (not shown) that is located on board the vessel 125.

Unlike conventional marine seismic surveys, 3D VSP in the presently disclosed

- 6 040720 document method uses continuous recording of the received reflections. In conventional marine seismic surveys, 3D VSP shots are accurately timed and matched so that acquisition can only occur at times where reflections are expected to be received. The randomness of independent simultaneous excitation of the sources makes this unusable. Therefore, continuous recording is used in the method disclosed herein, since the time of arrival of reflections 175 is not exactly known.

As used herein, the term continuous acquisition may refer to acquisition of seismic data during breaks (in time) between acquisitions of seismic data in conventional surveys. The digital data samples will typically be recorded as received at a regular sampling rate, such as 4 ms, along with a time measurement of each digital data sample. However, the recording is continuous, so the readings are recorded when they are received, since there are no breaks in time in the recording. On the other hand, with traditional excitation, a record of a fixed length is usually recorded, depending on the required depth of the resulting image, this record is from 300 ms to 20 s. With conventional excitation, overlapping output records usually does not occur, and there is always a time gap between adjacent records.

One continuous record is as long as many conventional seismic records and thus contains seismic wave arrivals generated by triggering multiple seismic sources. A continuous record may be many hours or days long (even in geological settings where a seismic record of a few seconds is required). It may, but need not, be divided into many shorter records adjacent to or overlapping with each other, or even excluding some time windows from the continuous record.

Registration scheme 160 will include the time at which the excitation is to start and at which it is expected to end; thus, the time during which the registration is performed is obtained. Each digitized sample is typically recorded in 2 or 4 ms sampling steps, as discussed above, firing times and locations are recorded for each seismic source until the source vessels cease firing. This completes the acquisition of seismic data.

To perform the analysis, the seismic data is processed after the survey is completed. Theoretically, this processing could take place in whole or in part on board the drilling rig 125 or elsewhere. The recorded data is very large and its processing requires intensive calculations. Not many field entities, such as the drilling rig 125 and towboats 145, have sufficient computing resources to perform such processing in a reasonable amount of time. Accordingly, for this reason, the recorded reflections (ie, seismic data) 300 are transmitted to the computer center 305, which is shown in FIG. 3.

Those skilled in the art will appreciate that seismic data 300 is arrays of ordered digital data that reside in a persistent storage medium. The received reflections are converted from an analog form, which is perceived by receivers, into a digital signal, which is then recorded. Seismic data 300 is typically stored in a persistent storage medium from which it can later be processed.

The seismic data 300 may be transmitted to the data center 305 in any suitable manner known in the art. For example, in some embodiments, seismic data 300 may be transmitted over wireless links 310 via satellite 315. In other embodiments, seismic data 300 may be recorded to tape 320 or disk and delivered to computer center 305 by air or sea, and then by land transport (not shown).

Computing center 305 will have a computing system suitable for the required processing. In FIG. 4 schematically shows portions of the software and hardware architecture 400 as they may be used in some aspects of the present invention. Depending on the particular implementation, computing device 400 may be a general purpose computing device or a special purpose computing device. Computing device 400 includes at least an electronic processor 403 that interacts with storage 406 via communication channels 409 .

The electronic processor 403 may be any suitable processor or group of processors known in the art. It will be appreciated by those skilled in the art that certain types of processors will be preferred in various embodiments, depending on known implementation details. Typically, factors such as processor power, speed, cost, and power consumption are encountered during the design process, and they are highly dependent on the specific implementation. Since they are ubiquitous in the art, such factors will be easily reconciled with one another by those skilled in the art who understand the benefits of using the present disclosure. The electronic processor 403 could theoretically be an electronic microcontroller, an electronic controller, an electronic microprocessor, a group of electronic processors, or a properly programmed application specific integrated circuit (ASIC), programmable logic array (FPGA), or graphics processing unit (GPU). In some embodiments, some combination of these types of processors may be used.

Those skilled in the art will also appreciate that datasets such as seismic data 110 are quite large and that the processing described here is computationally intensive. Therefore, conventional implementations of the electronic processor 403 actually comprise several groups of electronic processors distributed among several cooperating computing devices. One such embodiment is discussed below. These considerations also affect the implementation of storage 406 and communication channels 409 .

Storage 406 may include persistent storage media such as a magnetic hard drive and/or random access memory (RAM) and/or removable media such as USB magnetic disk 412 and optical disk 415. Storage 406 contains a number of software components. These components include the operating system (OS) 418, application (application program) 421, data structures, including seismic data (SDATA) 300. Storage 406 may be distributed among multiple computing devices, as described above.

As well as electronic processor 403, design constraints in all particular embodiments may affect the design of storage 406 depending on the particular implementation. For example, as noted above, the disclosed technology operates on large data arrays, which is typically facilitated by the use of different storage media, such as a redundant array of independent disks (RAID). Those skilled in the art are also aware of other types of storage media that can be used in addition to or instead of RAID. As with the electronic processor 403, these types of factors are well known during the design process, and those skilled in the art who understand the benefits of using the present disclosure will easily find the optimum balance between them depending on the constraints of a particular implementation design.

The electronic processor 403 operates under the control of the operating system 418 and executes the application 421 using the communication channel 409 . This process can start automatically, for example, at startup, or at the user's command. The user command can be issued directly using the user interface. The exemplary computer system 400 also uses a user interface 442 to this end.

The user interface 442 includes a user interface (UIS) program 445 and a display 440. It may also include input/output (I/O) peripherals such as a keypad or keyboard 450, a mouse 455, or a joystick 460. Such implementation details are not values for the technology disclosed here. For example, some embodiments may not contain I/O peripherals if the display 440 is equipped with a touch screen. Accordingly, the technology disclosed herein allows variations on this aspect of computer system 400, and any conventional implementations known in the art may be used.

In addition, there is no requirement that the functionality of the computer system 400 described above be implemented as described herein. For example, application 421 may be implemented as other software components such as a service process or utility. The functionality of the application 421 need not be combined into one software component and may be distributed between two or more software components. In the same way, data structures may be implemented using any suitable data structures known in the art.

As with the electronic processor 403 and storage 406, the implementation of the communication channel 409 will depend on the particular implementation. If the computer system 400 is installed on a single computing device, the communication channel 409 may be, for example, the bus system of that single computing device. If computer system 400 is implemented on a plurality of networked computing devices, then communication channel 409 may use wired or wireless communication between computing devices. For this reason, the implementation of the communication channel 409 will depend substantially on the particular implementation, as far as it is obvious to those skilled in the art who understand the benefits of using the present invention.

As can be seen from the description in this document, some parts of the detailed description presented here are set forth in terms of a software-implemented procedure containing symbolic representations of operations on data bits in the memory of a computer system or computing device. These descriptions and representations are the means that those skilled in the art use to more effectively communicate the content of their work to others in the field.

- 8 040720 of this field of technology. The procedure and operation require specific manipulations of physical quantities that will result in physical changes to the specific device or system on which these actions are performed or on which the results are stored. Typically, but not necessarily, these quantities take the form of electrical, magnetic, or optical signals that can be stored, transmitted, combined, compared, or otherwise manipulated. It is sometimes considered convenient, especially for purposes of general use, to refer to these signals as bits, values, elements, symbols, terms, numbers, and so on.

However, it should be remembered that all these named and similar terms are to be associated with the corresponding physical quantities and are simply convenient designations that are used for these quantities. Unless otherwise noted in this disclosure or otherwise apparent from it, these descriptions refer to the actions and procedures of an electronic device that performs actions and converts data represented in the form of physical (electronic, magnetic or optical) quantities into the storage of some electronic device, into other data, also represented in the form of physical quantities in storage or on transmitting or displaying devices. Typical terms in such a description, among others, may be: processing, calculation, calculation, finding, display, and the like.

In addition, the execution of software functions changes the computing device on which it occurs. For example, the collection of data will physically change the contents of the store in the same way as the subsequent processing of the data. A physical change is a physical transformation that results in a change in the physical state of a computing device's data store.

Note that the software-implemented aspects of the invention are typically recorded on some form of storage media, or implemented using some form of communication medium. The program storage device may be magnetic (eg, a floppy disk or hard disk) or optical (eg, CD-ROM or CD-ROM read-only storage) and may be read-only or unrestricted. In the same way, the communication medium may be coaxial cable, twisted pairs, optical fiber, or some other communication medium known in the art. The invention is not limited to these aspects of any implementations.

In FIG. 5 depicts an example of a portion of a computer system 500 that performs such processing in the present embodiment. Computer system 500 is connected to a (computer) network, but connecting computer system 500 to a network is not a requirement. Other embodiments may involve, for example, a peer-to-peer architecture or some hybrid of a peer-to-peer and client/server architecture. For the practice of the present invention, the size and location of the computer system 500 is not critical. The size and scale can vary from a few local area network (LAN) devices located in a single room to many hundreds or thousands of devices distributed around the world as a corporate computer system.

The illustrated portion of computer system 500 includes a server 510, a storage device 520, and a workstation 530. Each of these components may be implemented in hardware in a conventional manner. Other embodiments of the invention may also include various computing devices that are used to implement computer system 500. In addition, those skilled in the art will appreciate that computer system 500, and even that part of it as shown, will be much more complex. However, such details are common, and we will not discuss or demonstrate them, so as not to obscure the understanding of the claimed subject matter below.

In FIG. 5 shows that the application 421 resides on the server 510 and the seismic data 300 resides on the storage device 520. This is just one way of hosting different software components, ours is independent of their location. While in some embodiments performance issues at certain locations may be mitigated, in other cases the location of the software component is not relevant.

The method disclosed here allows some variation in processing depending on the way the data is collected and the implementation of specific goals for the final product. It will be apparent to those skilled in the art that regardless of the processing approach, there will usually be some level of pre-treatment. Such pre-processing will typically be used in various embodiments of the method disclosed here. However, due to the ubiquity in the art and the familiarity of those skilled in the art with such pre-processing, we will not discuss it further for the sake of clarity and not to detract from the subject matter of the invention claimed below.

In the embodiments shown, the processing includes at least a technique known as separation of signals (from adjacent sources). The signal separation procedure extracts individual shots from the seismic record and is combined in some embodiments with other methods to mitigate interference from other shots. Examples of signal separation according to the method disclosed herein include combing (performing comb filtering) of a record, combing and then filtering the record, and a sparse inversion method known as burst separation by SSI inversion.

In one particular embodiment, the processing includes a procedure known in the art as combing (one way of sorting data, in particular by applying a special comb function). Although firing occurs randomly as described above, the burst times are part of the seismic record as they are known in fact. This knowledge can then be used to comb through the seismic record in order to find explosions among the noise associated with other explosions. This method allows you to extract explosions without additional efforts aimed at eliminating interference. Combing results in recordings from which relatively less noisy images can be obtained.

In another embodiment, carding is combined with filtering to eliminate interference. Carding in this embodiment may be performed as described, and then a filter is applied to the carded data. The combed data can then be sorted into gathers in which the noise appears random and the signal appears coherent. For example, in some embodiments, common-receiver gathers may be used, although other types of gathers may be used. The seismograms are then filtered. Filtering can be performed, for example, by applying a Fourier transform, a Radon transform, a wavelet transform, a curvlet transform, or a seismlet transform.

However, in the present embodiment, the third processing method is used. Because the present embodiment uses the popcorn excitation method described in the 947 application, it is particularly suitable for sparse inversion processing. This sparse inversion method is also described in the 947 application and is based on known methods described, for example, in Abma R.L. et al. High Quality Separation of Simultaneous Sources by Sparse Inversion (Extended Abstracts of the 72nd EAGE Annual Conference and Exhibition, 2010) and in US Patent Application No. 12/542433, amended as described in application 947.

The propagation of seismic waves through the subterranean layer usually creates continuous wave fields. This continuity can be used to constrain solutions in traditional approaches. Thus, the conventional inversion method is modified by imposing spatial continuity constraints on the data d A C t where d is the survey data, A is the convolution operator, C is the continuity operator, m is the desired data.

The continuity operator C ensures that the given m is spatially continuous. To calculate the continuity operator, multidimensional Fourier transforms with thresholds can be used.

In other embodiments, other coherence criteria may be used. One of these alternative criteria is the curvelet method proposed by Lin, Tim and Felix J. Herrmann Designing Simultaneous Acquisitions with Compressive Sensing (Extended Abstracts of the 71st Annual Conference and EAGE exhibitions, 2009). With a sufficient number of iterations, curvlet thresholding can give similar results to the method described above, but thresholding in FK space (in the frequency and wavenumber domains) can be more efficient and faster than the corresponding curvelet approach. Examples of other ways to incorporate the assumption of a coherent wavefield into the inversion may include various Radon transforms and prediction error filters.

There are several inversion methods known in the art that are suitable for finding the required data m. In one particular embodiment, the inversion method is similar to the method of interpolation by projection onto convex sets (POCS), which is described in the work of Abma R. and Kabir N. 3D interpolation of irregular data with a POCS algorithm (3D interpolation of irregular data using the POCS algorithm) ( Geophysics, Issue 71, E91-E97, 2006) and US Patent Application No. 12/464,907, filed May 13, 2009. In other embodiments, other methods may be used. Any suitable solution methods known to those skilled in the art may be used.

In general, in order to ensure consistency in the model m, which is found using the inverse for the following expression, the method of processing the data obtained by the disclosed method to ensure consistency may include using a Fourier transform method, such as Fast Fourier Transform (FFT) d ~ A C t

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Claims (14)

The desired result m is found in an iterative manner which includes sorting the data d to obtain an NPP gather, combing the difference between the data d and the estimated data d', adding this combed difference to the computed model m, obtaining the Fourier transform of the model in windows, applying thresholds to the transformed data to eliminate the weakest reflections in the Fourier domain, inverse Fourier transform in the windows, merge the windows into a complete model m, calculate the data estimate d' from the new model, and repeat this process until an acceptable result m is obtained. In the case of a popcorn survey, the steps of removing popcorn patterns from the survey data and adding popcorn patterns to the computed model m to obtain a data estimate d' will be added. The articles, applications, and patents listed below are incorporated by reference for the purposes indicated: Abma R. and Kabir N. 3D interpolation of irregular data with a POCS algorithm (Geophysics magazine, issue 71, E91-E97, 2006) - principles of the method of interpolation by projecting onto convex set (POCS). US Patent Application No. 12/310204 Seismic Survey Method, filed August 30, 2007 in the name of David John Howe (Application 204) and having the same rightholder as the present application, are all principles set forth therein. U.S. Patent Application No. 12/464,907 Method for interpolating seismic data by projecting onto convex sets, filed May 13, 2009 on behalf of inventor Raymond L. Abma, published Nov. 26, 2009 as Patent Publication 20090292476 A1, and with the present application - all the principles concerning the method of interpolation by projection on convex sets (POCS). Lin, Tim and Felix J. Herrmann Designing Simultaneous Acquisitions with Compressive Sensing (Extended Abstracts of the 71st Annual EAGE Conference and Exhibition, 2009) - principles of the curvelet method. U.S. Patent Application No. 12/542433 Independent Synchronous Source Separation Method, filed Aug. 17, 2009 on behalf of inventor Raymond L. Abma and having common title with the present application - principles relating to sparse inversion method. Abma R.L. et al. High Quality Separation of Simultaneous Sources by Sparse Inversion (Extended Abstracts of the 72nd EAGE Annual Conference and Exhibition, 2010) - principles relating to the sparse inversion method. U.S. Patent Application No. 12/851,590 Separation Method for Independent Synchronous Sources, filed Aug. 6, 2010 on behalf of inventor Raymond L. Abma, and having common title with the present application, principles of a sparse inversion method for independent synchronous excitation sources. U.S. Patent Application No. 13/315,947 Seismic Survey System and Method, filed December 9, 2011 on behalf of Allan Ross and Raymond Lee Abma, and having common title with the present application, principles relating to a method of firing popcorn seismic sources. US Patent Application No. 13/867705 Seismic Survey Method, filed on April 22, 2013 on behalf of David John Howe and having common title with this application, are all principles set forth therein. To the extent that any incorporated article, appendix or reference to this disclosure conflicts, the present invention shall prevail. Other embodiments of the present invention will be apparent to those skilled in the art upon consideration of the description of the invention disclosed herein and the practice of the invention. It is intended that the description of the invention and examples will be considered only as an illustration, and the true essence and scope of the invention are given in the following claims. CLAIM 1. A method of marine seismic exploration, including vertical seismic profiling, which provides for the independent and simultaneous excitation of a plurality of seismic sources grouped into a plurality of groups, operating in a corresponding manner at a plurality of different survey sites, to transmit seismic signals to the seabed, and the seismic sources of each group emit signals spatially and temporally independent of the seismic sources of any other group through the following: movement at different speeds of a plurality of ships associated respectively with a plurality of groups, so that the time interval with which the interference between the signals emitted is repeated - 11 040720 different groups, is random; introducing irregular distances between seismic source firing points in each of the groups, so that the time interval between seismic source firing points in each of the groups is random; receiving reflections of seismic signals from underground strata that are under the seabed, on a plurality of seismic receivers; and recording seismic reflections to obtain a seismic record. 2. The method of claim 1, wherein the plurality of survey sites includes two survey sites. 3. The method of claim 1, wherein the plurality of seismic sources are organized into arrays. 4. The method of claim 3, wherein independently and simultaneously firing a plurality of seismic sources comprises firing according to a firing pattern that includes a time lag between two different firing patterns, wherein the seismic sources of a first group of the plurality of groups are fired according to a first firing pattern of two different blast patterns, and the seismic sources of the second group of the plurality of groups are fired according to the second blast pattern from two different blast patterns. 5. The method according to claim 1, wherein the independent and simultaneous excitation of a plurality of seismic sources comprises excitation of each seismic source of the first group of the plurality of groups according to the first excitation scheme and excitation of each seismic source of the second group of the plurality of groups according to the second excitation scheme, and the first excitation scheme and the second drive circuit are different. 6. The method of claim 5, wherein a time lag is present between the first drive circuit and the second drive circuit. 7. The method of claim 1, wherein the acquisition of seismic reflections is a continuous acquisition of seismic reflections. 8. The method of claim 1, further comprising processing a seismic record that consists of reflections of the seismic records by separating the signals of the seismic record to extract individual shots from the seismic record. 9. The method of claim 8, wherein separating the seismic record signals includes at least one of performing comb filtering of the seismic record to search for explosions, removing noise from the seismic record by filtering, and performing a sparse inversion of the seismic record. 10. The method of claim 8, wherein seismic signal separation includes performing a sparse inversion that uses a Fourier transform method d ~ AC t to ensure consistency in the model where d is the survey data, A is the convolution operator, C is the operator continuity, m - required data. 11. The method according to claim 10, in which finding a solution for m sequentially includes ordering the received data d into seismograms of a common receiving point; comb filtering of the difference between the received data d and the estimated data d'; adding the difference between the received data d and the estimated data d' to the calculated model m; Fourier transform of model windows; setting the thresholds of the transformed data to eliminate weak waves in the Fourier region; inverse Fourier transform windows; combining the windows into a full model m and calculating the second estimated data d' on the new model until an acceptable result m is obtained. 12. The method of claim 8, which further includes mitigating interference by filtering the seismic record. 13. The method of claim 12, wherein the filtering includes applying a Fourier, Radon, wavelet, curvlet, or seismlet transform. 14. A method of marine seismic exploration, including vertical seismic profiling, which provides for the collection of vertical seismic profiling data, which includes independent and simultaneous excitation of a plurality of seismic sources grouped into a plurality of groups operating on a plurality of survey sites, to transmit seismic signals to the seabed , and the seismic sources of each group emit signals spatially and temporally independently of the seismic sources of any other group through the following: movement at different speeds of a plurality of vessels associated, respectively, with a plurality of groups, -