EA045222B1 - 4D JOINT TIME SHIFT AND AMPLITUDE INVERSION FOR VELOCITY CHANGE - Google Patents

Description

State of the art

This application claims priority to provisional patent application US 62/842286, filed with the United States Patent Office on May 2, 2019, entitled 4D Coupled Time Shift and Amplitude Inversion for Velocity Variation, the disclosure of which is incorporated herein by reference in its entirety.

The present disclosure generally relates to identifying changes in the Earth's subsurface over time using seismic data. The present disclosure also relates to the fusion of seismic images representing the same subsurface area during a seismic acquisition.

This section is intended to familiarize the reader with various aspects of the prior art that may relate to the various features of the present invention described and/or claimed below. It is believed that the present discussion will be useful in familiarizing the reader with information regarding the subject matter of the invention and will provide a better understanding of the various features of the present invention. Accordingly, this information should be perceived from this point of view, and not as a description of the achievements of the state of the art.

Seismic imaging typically involves generating an image or map of the Earth's subsurface by sending sound energy into the geologic environment and recording the reflected sound energy returning from the geologic layers in the subsurface. During a seismic survey, an energy source is placed at various locations on or above the Earth's surface in areas where hydrocarbon deposits may be located. Each time a source is activated, it generates a seismic signal (eg, a sound wave) that travels down underground, is reflected, and, upon return, is recorded using one or more receivers located at or above the Earth's subsurface. The seismic data recorded by the receivers can then be used to create an image or profile of the corresponding subsurface zone.

Over time, as hydrocarbons are extracted from the Earth's subsurface, the location, saturation, and other characteristics of the hydrocarbon reservoir (eg, cap rock, wellbore interval) within the subsurface may change. Therefore, it is useful to determine how the image or map of the subsurface changes over time in order to introduce changes in hydrocarbon recovery activities to improve the efficiency of hydrocarbon recovery from the Earth's subsurface.

The essence of the invention

The following is a summary of the substance of certain embodiments disclosed herein. It should be understood that the specifications provided serve as a summary of the spirit of these particular embodiments and are not intended to limit the scope of the disclosure. In fact, the present disclosure may cover various features that may not be mentioned below.

A single-track inversion method is presented to estimate velocity changes from a set of 4D seismic data from the subsurface. A 4D seismic dataset includes data from two 3D surveys of the same area, taken at two different points in time - a reference survey, or baseline survey, and a control survey. The reference survey and control survey each have seismic traces showing how seismic waves are reflected within the subsurface. Changes in the speed of seismic waves used for 3D acquisition result in a time shift in the seismogram tracks. Changes in amplitude between the reference and reference survey tracks may be the result of a change in speed and/or a change in density. In some cases, if the change in density is negligible, the cause of both the time shift and the changes in amplitude will be the change in speed.

The single-track inversion method, in one or more embodiments, uses two sets of 3D seismic data (including a reference survey gather track and a reference survey gather track) and a seismic wavelet estimate for a subsurface reservoir. The objective function used for the inversion process is determined by least squares minimization. Specifically, in one or more embodiments, the least squares difference between the predicted control gather track (control gather) and the observed control gather track (where the difference is expressed by an objective function) is minimized. The velocity change expressed in the objective function is determined by iterating to minimize the least squares difference between the predicted reference gather track (generated from the reference gather track) and the observed reference gather track. The generated forecast gather track typically has two parts. One part imparts a time shift (arising from the change in predicted velocity) to the reference gather track (reference gather), and the other part compensates for the change in amplitude from the baseline gather track to the control gather track with the predicted change in velocity. Temporary correction

- 1045222 shift also applies to amplitude change.

Once the estimated velocity change reaches a point where the difference between the predicted reference gather track and the observed reference gather trace reaches or becomes less than a threshold value, the predicted velocity change can be used to estimate changes in the subsurface region of interest. In particular, a map of velocity changes in the subsurface zone can be generated to estimate changes in that zone between the time when the reference survey was taken and the time when the control survey is taken.

Brief description of drawings

Various features of the present disclosure will be better understood by reference to the following detailed description and reference to the drawings, in which:

in fig. 1 is a flow diagram of various processes that can be carried out based on the analysis of seismic data acquired by a seismic acquisition system in accordance with the illustrated embodiments;

in fig. 2 is a schematic side view of an example implementation of a marine survey system in a marine environment;

in fig. 3 is a schematic side view of an example embodiment of a terrestrial survey system in a terrestrial environment;

in fig. 4 is a block diagram of an example implementation of a computing system suitable for performing the operations described herein based on data acquired by the marine survey system shown in FIG. 2, and/or the ground survey system shown in FIG. 3;

in fig. 5 is a flow diagram of an embodiment of a method for determining changes in the subsurface by inverting a single track performed on a 4D seismic dataset;

in fig. 6 illustrates in schematic form an example of a method in the present disclosure for using an objective function to generate a predicted reference gather track from a reference gather track, using the predicted velocity change;

in fig. 7A-7B show a comparison between the true velocity model and the model obtained in accordance with single track inversion according to the present disclosure;

in fig. 8A and 8B provide a comparison of velocity models when amplitude changes are not time-shifted and when amplitude changes are time-shifted;

in fig. Figure 9 shows a graph of changes in density and changes in velocity as a function of the materials of the productive formation;

in fig. Figure 10 compares the results obtained in examples of inversion using an objective function, where a scalar multiplier is not used to account for changes in density, and inversion using an objective function, where a scalar multiplier is used to account for changes in density.

Detailed Description of the Invention

The following is a description of one or more particular embodiments. In an effort to provide a brief description of these embodiments, not all practical implementation features are described herein. It should be understood that the development of any such practical implementation, whether in any engineering project or development work, to achieve specific development goals requires the resolution of numerous implementation-specific challenges, such as compliance with various system or commercial constraints, which may vary from one performance to another. Moreover, it should be understood that such development activities may be complex and time-consuming, but will represent a standard set of design, manufacturing, and mass production processes carried out by those skilled in the art with knowledge of this disclosure.

As shown above, seismic data processing can provide valuable information related to the Earth's subsurface, such as the location and characteristics of hydrocarbon deposits. Seismic data acquired over time can also be processed to assess how these zones may change (transform) over time, for example due to hydrocarbon production. Based on changes over time in the Earth's geological horizon and the location and characteristics of hydrocarbon reservoirs, hydrocarbon production activities can be adjusted to more efficiently extract hydrocarbons.

One method for obtaining more accurate data representative of geological pay horizons involves performing, in accordance with the present disclosure, a single-track inversion method to estimate velocity based on a 4D seismic dataset. In general, a 4D seismic dataset according to the present disclosure includes at least two 3D surveys of the same area/section at two or more different points in time. For simplicity of presentation, two 3D surveys taken at different points in time are considered. As used herein, the term inversion refers to the process by which a subsurface model is evaluated on

- 2 045222 based on the obtained seismic data (for example, the results of seismic surveys).

One of the 3D surveys (eg, the first survey) may be considered a reference seismic survey, or reference survey, and another of the 3D surveys (eg, the second survey) may be considered a control seismic survey, or control survey. The reference survey and control survey both include corresponding sets of gather tracks, and the gather tracks of each survey represent the subsurface zone being analyzed at the corresponding point in time (or time period). According to the present embodiments, a reference survey is performed before a reference survey. Thus, differences between surveys indicate changes in the subsurface of interest, and a control survey can be performed to assess changes in the subsurface over a period of time after the reference survey, for example, to assess how hydrocarbon production has affected the subsurface.

More specifically, changes in the subsurface zone between the time of the reference survey and the time of the control survey will entail changes in the propagation of seismic waves through this zone. For example, changes in the subsurface zone may include changes in the materials in that zone, which can affect the speed of seismic waves through the zone and the reflection patterns of seismic waves. Accordingly, the seismogram tracks of the reference survey and the control survey may differ with respect to the amplitude of the various seismic wave peaks, and may differ in the time at which these peaks are received by the receivers that generate each individual seismogram trace. Each seismogram track may include a sequence of points, and each of these points may correspond to the seismic wave velocity for that point. The difference in velocity at a given point between the reference gather track and the control gather track can be assessed to determine, for example, changes in the subsurface at the location corresponding to that point.

In accordance with the present embodiments, the reference gather tracks may be shifted to coincide with the control gather tracks to estimate local velocity changes. As illustrated herein, the velocity changes are considered to represent, at a given point on the seismic trace, the change in seismic wave velocity between the reference seismic survey and the reference seismic survey at that point. The change in velocity at a point on a gather trace can be expressed mathematically as the difference in velocity between the reference survey and the control survey at that point divided by the velocity in the reference survey at that point.

Local velocity changes can be used together to estimate changes in the subsurface. In particular, local changes in velocity can generally be considered to result from changes in the seismic reflector at that location. This can produce a map of velocity changes in the subsurface zone to show changes in materials in the zone over time. This, in turn, will allow production processes to be adjusted to improve the efficiency of underground operations, such as hydrocarbon recovery.

Shifting the reference gather track to align with the reference gather track can be accomplished using a process in which the velocity changes between individual point data in the reference and reference gathers are estimated through an iterative process. Iterations are carried out until the difference between the reference and control tracks is reduced to a given threshold value. Once a minimum difference has been achieved in this way, the velocity changes can be used to construct the velocity map mentioned above.

In one or more embodiments, minimization of the difference (expressed in terms of an objective function) may be performed by implementing a least squares optimization algorithm. This optimization algorithm can account for changes between the reference survey and the control survey due to time shift and due to amplitude changes.

In particular, to update various seismic wave velocity models, seismic images, reservoir characteristic maps, etc., the computing system can use the characteristics of velocity changes to more accurately determine the locations and properties of various geological horizons within the Earth's subsurface. As such, exploration for hydrocarbon reservoirs (eg, drilling, siting, production) can be improved by modifying the activities in accordance with updated locations and properties of hydrocarbon reservoirs within the subsurface, in accordance with updated velocity models or updated seismic images.

It should be immediately noted that seismic data can be acquired using a large number of different seismic survey systems and techniques, two of which are discussed with reference to FIG. 2 and 3. Regardless of the seismic data acquisition method used, once the data is acquired, the computing system can analyze the data, and can use the results of the seismic data analysis (e.g., seismograms, geological reservoir map) to perform various operations in hydrocarbon exploration and production sectors. For example, in FIG. 1 is a flow diagram of method 10 illustrating various processes that can be carried out based on analysis of acquired seismic data. Although the method is described in a specific order, it is noted that the implementation of method 10 may be carried out in any suitable order.

In fig. 1 in step 12, based on the analysis of seismic data, the locations and properties of hydrocarbon deposits in the Earth's subsurface associated with the corresponding seismic survey can be determined. In one embodiment, seismic data acquired using multiple sources and receivers or at different points in time can be analyzed to construct a map or profile illustrating various geological formations in the subsurface.

Based on the identified locations and properties of hydrocarbon deposits, specific locations or portions of the subsurface zone may be explored in step 14. In other words, hydrocarbon exploration organizations can use the locations of hydrocarbon deposits to select drilling sites in the subsurface. In doing so, hydrocarbon exploration organizations can use the locations and properties of hydrocarbon deposits and associated caprock to determine drilling routes, drilling parameters, etc.

After exploration equipment has been installed within the subsurface zone, in step 16, the hydrocarbons stored in the hydrocarbon reservoir can be produced through natural flow wells, artificial lift wells, etc. At step 18, the produced hydrocarbons may be transported to refineries and the like, via vehicles, pipelines, etc. At step 20, the produced hydrocarbons may be processed through various processing processes to produce various hydrocarbon-using products.

It is noted that the processes discussed with reference to method 10 may include other suitable processes, which may be based on the location and properties of hydrocarbon deposits as determined by seismic data collected through one or more seismic surveys. It should be understood that the processes described above do not in themselves imply the existence of an exhaustive list of processes that can be performed after determining the locations and properties of hydrocarbon deposits in the subsurface zone. For example, the actions represented by step 12 may also include acquiring and analyzing additional seismic data, eg, acquired later, to assess changes in a given subsurface reservoir (eg, based on estimating velocity changes) to more efficiently recover hydrocarbons).

With that said, consider in FIG. 2, a marine survey system 22 (eg, for use in conjunction with pitch 12 of FIG. 1) that can be used to collect seismic data related to the Earth's subsurface offshore. In general, marine seismic surveys using the marine survey system 22 may be conducted in the ocean 24 or other body of water above the Earth's subsurface zone 26 underlying the seafloor 28.

The marine survey system 22 may include a vessel 30, a seismic source 32, a seismic streamer 34, a receiver 36, and/or other equipment that may be useful in collecting seismic images representing geological horizons in the Earth's subsurface zone 26. Vessel 30 may tow a seismic source 32 (e.g., an array of air guns) that may generate energy, such as acoustic waves (e.g., seismic vibrations) directed at the seabed 28. Vessel 30 may also tow a seismic streamer 34 having a receiver 36 (e.g., hydrophones) that can receive seismic vibrations (waves) representing the output vibration energy of seismic sources 32 after they are reflected from various geological formations in the subsurface zone 26. Although the receiver 36 is described as towed by the vessel 30, in some embodiments, the receiver 36 may also be located on the surface of the seabed 28. In addition, although the described marine survey system 22 includes one seismic source 32 (represented as an array of air guns in FIG. 2) and one receiver 36 (represented as a plurality of hydrophones in FIG. 2), it is noted that that the marine survey system 22 may include a large number of seismic sources 32 and a large number of seismic receivers 36. Likewise, although the marine survey system 22 is described above in relation to a single seismic streamer 34, it will be appreciated that the marine survey system 22 may include a large number of seismic cables 34. In addition, additional vessels 30 may have additional sources 32, seismic streamers 34 and the like, to operate the survey system.

In fig. 3 illustrates an embodiment of a terrestrial survey system 38 (eg, for use in conjunction with pitch 12 of FIG. 1) that can be used to obtain information related to the Earth's subsurface zone 26 for non-marine environments. The surface acquisition system 38 may include a surface seismic source 40 located on the Earth surface 42 and one or more surface receivers 44 also located on the surface 42 (or other suitable location). In some embodiments, the ground survey system 38 may include

- 4 045222 more than one seismic sources 40 and first and second receivers 44 and 46. For purposes of discussion, FIG. 3 shows one surface seismic source 40 and two seismic receivers 44 and 46. The surface seismic source 40 can generate energy (eg, acoustic waves, seismic vibrations) directed toward a subsurface zone 26 of the Earth. Upon reaching various geological formations (eg, salt domes, fractures, folds, etc.) in the subsurface zone 26, the output vibration energy of the surface seismic source 40 may be reflected from these geological formations (particularly, interfaces between different rock materials) and collected or recorded by one or more ground receivers (eg 44 and 46) as source signals.

In some embodiments, ground receivers 44 and 46 may be distributed over surface 42 to form a grid structure. Each surface receiver 44 or 46 may receive a signal corresponding to a reflected seismic wave in response to energy directed into the subsurface zone 26 from the seismic source 40. In some cases, a single seismic wave generated by the seismic source 40 may be reflected from different geological formations. and can be received by different receivers. For example, as shown in FIG. 3, the seismic source 40 may generate an output wave whose energy is directed to the subsurface zone 26 in the form of a seismic wave 48. The first receiver 44 may receive the reflection of the seismic wave 48 from one geological formation, and the second receiver 46 may receive the reflection of the seismic wave 48 from another geological formation. education. Thus, the first receiver 44 may receive the first reflected waveform 50, and the second receiver 46 may receive the second reflected waveform 52.

The received data for each of these channels (first and second receivers 44, 46) may be processed to produce a set of seismogram traces. The set of gather tracks across all receivers used in the system 38 at a given time (eg, the first time period) can be considered the collection of gather tracks corresponding to a given seismic survey. Seismic surveys can be conducted at various points in time to assess changes in the subsurface reservoir.

Regardless of how the seismic data was collected, the computing system (for example, for use in conjunction with step 12 in FIG. 1) can perform analysis of the signals (seismic vibrations) received by the sea-based receivers 36 and the land-based receivers 44 and 46 , to determine information related to the geological structure, location and properties of hydrocarbon deposits, etc. within the subsurface zone 26. In FIG. 4 provides an example of such a computing system 60 that can perform various data analysis operations to examine the seismic data collected by the receivers 36, 44, 46 to determine the structure and/or evaluate changes in the seismic properties of geological formations in the subsurface zone 26. In fact, in the present discussion the computer system 60 is programmed to perform seismic adjustments, seismic trace inversions, and the described analysis procedures.

As shown further in FIG. 4, computing system 60 may include a communications component 62, a processor 64, a memory device 66, a storage device 68, input/output (I/O) ports 70, a display 72, and the like. Communications component 62 may be a wireless or wired component that may provide communication between receivers 36, 44, 46, one or more databases 74, other computing devices, and other devices having communication capabilities. In one embodiment, the computing system 60 may receive data 76 (e.g., waveforms, seismic data, gathers, gather traces) that may previously have been received by seismic receivers through a network component, database 74, or the like. The processor 64 of the computing system 60 may analyze or process the receiving data 76 to determine various features related to geological formations in the subsurface zone 26 of the Earth.

Processor 64 may be a computer processor or any type of microprocessor capable of executing a computer program. Processor 64 may also include multiple processors that may perform the operations described below. The memory device 66 and data storage device 68 may be any suitable off-the-shelf product that can serve as a storage medium for processor-executable computer-readable code, data, etc. These finished products may be a computer-readable medium (eg, any suitable form for storing and storing data) that can store a processor-executable program used by the processor 64 to implement the methods disclosed herein. In general, processor 64 may execute software applications that include programs for processing seismic data collected through seismic system receivers, in accordance with the embodiments described herein.

Memory device 66 and data storage device 68 may be used for data storage, data analysis, software applications, etc. Memory 66 and data storage 68 may be a non-volatile computer-readable medium (e.g., a memory or data storage device in any suitable form) that may store a program executable by processor 64 for implementing various techniques described in the present disclosure. It should be kept in mind that non-volatility simply means that the medium is a material carrier and not a signal.

The I/O ports 70 may be interfaces that may connect to other peripheral components, such as input devices (eg, keyboard, mouse), sensors, input/output (I/O) modules, and the like. The I/O ports 70 may allow the computing system 60 to communicate with other devices in the marine survey system 22, land survey system 38, or others through the I/O ports 70.

The display 72 may display images associated with software or executable programs that are processed by the processor 64. In one embodiment, the display 72 may be a touchscreen display allowing input by the user of the computing system 60.

The display 72 may also be used to view and examine the results of an analysis of the collected seismic data to determine the geological formations within the subsurface zone 26, the location and properties of hydrocarbon deposits in the subsurface zone 26, and the like. The display 72 may be any suitable type of display, such as a liquid crystal display (LCD), plasma display, or organic light-emitting diode (OLED) display. It should also be noted that in addition to the display 72 mentioned herein, the computing system 60 may also display through other media, such as paper (printing), etc.

With that said, the method described herein can also be implemented using a supercomputer using multiple computing systems 60, a cloud computing system, or other means to distribute processes across a large number of computing systems. In this case, each computing system 60 operating as part of a supercomputer may not include every component referred to as part of the computing system 60. For example, each computing system 60 may not include a display component 72 because a large number of display components 72 may not be useful. for a supercomputer designed for continuous processing of seismic data.

After performing various processing on the seismic data, the computing system 60 may store the analysis results in one or more databases 74 . Databases 74 may be coupled by signaling to a network that may communicate with computing system 60 via communications component 62. Additionally, databases 74 may store information related to subsurface zone 26, such as previously acquired seismograms, geological sample data, seismic images, seismic traces, etc., obtained during surveying of the subsurface zone 26.

Although the components described above have been discussed in relation to the computing system 60, it should be noted that the computing system 60 may be composed of similar components. Moreover, the computing system 60 may be part of a marine survey system 22 or a terrestrial survey system 38 and may monitor and control certain operations of sources 32 or 40, receivers 36, 44, 46, etc. Additionally, it should be noted that the components listed are as an example, and the embodiments described herein are not limited to the components described with reference to FIGS. 4.

In some embodiments, the computing system 60 may generate a two-dimensional representation or a three-dimensional representation of the subsurface zone 26 based on seismic data acquired through the above-mentioned receivers. In addition, seismic data associated with multiple source/receiver combinations may be combined to create a nearly continuous profile of the subsurface region 26 that may extend over some distance. In a two-dimensional (2-D) seismic survey, receiver locations may be located along a single line, while in a three-dimensional (3-D) survey, receiver locations may be distributed across the surface in a grid pattern. In this case, 2-D seismic imaging can provide a cross-sectional picture (vertical slice) of the layers of the Earth located directly below the recording points. A 3-D seismic survey, in contrast, can produce a cube or volume of data that can correspond to a 3-D picture of the subsurface zone 26.

In addition, a 4-D seismic survey (periodic survey) may include seismic data acquired by multiple 3-D surveys. Using different seismic images acquired at different points in time, the computing system 60 can compare the two images to detect changes in the subsurface zone 26.

In any case, a seismic survey may be composed of a very large number of individual seismic records or seismic traces. In this case, the computing system 60 may be used to analyze the collected seismic data to obtain an image representing the subsurface zone 26 and to determine the location and properties of hydrocarbon deposits, as well as changes occurring over time in the subsurface zone 26 (for example , due to hydrocarbon production).

Various seismic data processing algorithms may be stored and used by the computing system 60, for example, to remove noise from acquired seismic data, transfer preprocessed seismic data, identify offsets between a large number of seismic images, register a large number of seismic images, etc.

After the computer system 60 has analyzed the collected seismic data, the results of the seismic data analysis (eg, seismograms, seismic images, geological formation maps, etc.) can be used to perform various operations in hydrocarbon exploration and production. For example, as described above, collected seismic data may be used to implement method 10 of FIG. 1, which details the various processes that can be performed based on the analysis of the collected seismic data.

Thus, it is found that using any system or combination of systems described above in relation to FIG. 2-4, single-track inversion techniques can be applied in estimating velocity changes for a 4D seismic dataset. A 4D seismic dataset generally includes at least two 3D seismic datasets acquired in the same field at two different times. In fig. 5 shows an embodiment of a method 80 of performing a single track inversion to estimate velocity changes and then determining characteristics of the Earth's subsurface based on these estimates. As an example, method 80 may be implemented in part or entirely by the computing system 60 shown in FIG. 4.

The method 80 generally includes obtaining a 4D subsurface seismic dataset, illustrated by obtaining (step 82) a reference survey with seismic data at a first time and obtaining (step 84) a control survey with seismic data at a second time, later than the first time. moment. In particular, a reference survey can be carried out before the production of hydrocarbons from the subsurface zone, and a control survey after the production of a certain amount of hydrocarbons. The present disclosure, however, is not limited to such cases, and reference and control surveys can be conducted at any of at least two points in time relative to the process of hydrocarbon production from the subsurface zone.

As illustrated in the present disclosure, seismic data acquired for reference and control surveys generally involves collecting and/or processing seismic data to form a sequence of seismic traces. In other words, a reference seismic survey is associated with a set of reference gathers, and a reference seismic survey is associated with a set of reference gathers. It should be noted that obtaining such data as per steps 82 and 84 may involve performing the measurements themselves (e.g., sending vibrations into the subsurface and collecting the resulting vibrations) or, in some cases, may involve sampling the data (e.g., using a computer system 60) from the database 74. Additionally, in some embodiments, the actions of steps 82 and 84 may simply represent receiving collected reference and control seismic data. Reference gather tracks and control gather tracks typically represent the geologic characteristics of the subsurface at the time of the corresponding survey. More specifically, seismic traces show how seismic vibrations are distorted from their original state due to changes in reflection coefficient as the vibrations propagate along the subsurface path from source to detector. Changes in reflectivity are usually associated with changes in the material through which seismic waves travel, or the interfaces where reflection or refraction of the seismic wave occurs.

Thus, in accordance with the present embodiments, the actions represented by steps 82 and 84 can generate reference gather tracks and control gather tracks. As discussed above, the present disclosure includes a single track inversion technique where individual traces of reference gathers are modified to obtain corresponding trace estimates of reference gathers. The difference between the corresponding control gather track estimates and the control gather tracks is then minimized until it reaches a threshold to produce a sequence of velocity change estimates for the subsurface.

Thus, according to method 80, the actions presented in steps 82 and 84 are followed by a process in which the computing system 60 performs a single track inversion (step 86), described in more detail below. The output of computer system 60 after performing the single-track inversion process may include, but is not limited to, a sequence of velocity change estimates for each track of the reference gather and the corresponding track of the reference gather.

In this case, the reference seismic survey includes a plurality of such reference seismogram tracks, and the control seismic survey includes a plurality of such control seismogram tracks. In some embodiments, the reference seismic survey and the control seismic survey are typically performed in the same manner, such that the sources and receivers used for the surveys are typically located at the same locations on the ground (e.g., relative to the target

- 7 045222 subsurface zone). If they are not located primarily in the same locations, then according to a known technique, the computer system 60 can perform a corrective match, allowing the results of the reference and control seismic surveys to be compared.

With respect to single-track inversion performed by computer system 60, each reference gather track may be represented by a series of amplitude values as a function of time b(t), and each reference gather track may have a similar representation m(t). The number of amplitude values for the reference and control gather tracks varies depending, in part, on the sampling frequency of the track data acquisition and the total acquisition time. Thus, the reference gather track b(t) can be considered to include a number of different amplitude values b(ti), where b(ti) represents the amplitude value for the reference gather track at some time ti of the sampling time. The reference gather tracks are represented similarly by m(ti) and thus there are times ti corresponding to samples of the reference gather track and the reference gather track.

In addition, for each reference gather track, there is one corresponding control gather track. In other words, for each track b(t) of the reference seismogram there is a track m(t) of the control seismogram corresponding in position to this seismogram track. Differences between the respective traces of the reference and reference seismograms, which may be determined by the computing system 60, may include, but are not limited to, waveforms having different peaks, the respective peaks having different amplitudes, and the respective peaks occurring at different times relative to the time of recording of the corresponding seismogram tracks (for example, one track is shifted in time relative to the other). Such differences can be viewed in relation to the reference gather track and the reference gather track, shown as outer tracks in FIG. 6 and described in more detail below. Comparison between the two tracks, for example, on a point-by-point basis or even on an accumulated difference basis, by the computing system 60, can provide an estimate of the changes occurring in the subsurface region of interest.

In accordance with the present embodiments, the single track inversion process of step 86 may be performed by a process in which the computing system 60 takes into account changes between a particular reference gather track and its corresponding reference gather track, in accordance with the time shift of the amplitude values, and changes in amplitude, both of which can be expressed as results of changes in speed. These velocity changes are then used by the computing system 60 to estimate changes in the subsurface zone.

The present embodiments use a relationship related to the impedance of a seismic pulse propagating through the earth. In particular, the change in impedance between the reference seismogram track and the corresponding control seismogram track can be represented as an approximation function of the sum of the density change P and the velocity change Δν ν:

Δ/ρ Δρ Δρ

Ip ν ρ

IPb- 'Pm where 'p is described by the expression , Ip _b is the impedance at some point in time for the reference seismogram track, and Ip _m is the impedance at the time point corresponding to the control track

Pb~ Pt seismogram. y is equal to ^v b, and P is equal to ^pb . v _b represents the velocity at time for the reference gather track, and v _m represents the velocity at time for the reference gather track; p _b is the density at some point in time for the reference gather track, and p _m is the density at some point in time corresponding to the reference gather track.

In the present embodiments of the computing system 60, an approximate relationship between the change in speed and the change in density is established, expressed by the following equation:

Δρ /Δν\ where α can be considered a scalar factor. If α = 0, then the change in velocity is the main cause for the change in impedance from the reference gather track to the reference gather track. However, even in circumstances where changes in density are responsible for changes in impedance, the difference between the traces of the reference gather and the reference gather can be pronounced

- 8 045222 only in terms of changes in speed, with the change in density being taken into account by the computing system 60 through different values of the scalar factor α in the manner described below.

Computing system 60 minimizes the difference between the reference and control gather tracks, for example, by performing a least squares search for the minimum of the following objective function:

= ^{t(D) - {b(t _f ) + [ι/ΖΔΛΟί}} ² where the function is represented by the sum over all sample points (i = from 1 to N) of the squared difference between the amplitude values for the control track m(ti) seismogram and the amplitude values of the track {^(6)+^^^(6)1^ of the predicted control seismogram. This predicted reference gather track may be generated based on the reference gather track, and the predicted reference gather track may be generated based on the estimated velocity changes. More specifically, the first term of the predicted reference gather track, ^^), represents the amplitude value of the reference gather track at a shifted time p determined by the computer system 60 as follows:

tt = ti - dt A yj where the time shift is represented as an integral function of the velocity changes from the first time sample in the acquisition of the reference seismogram track, j = 1, to the corresponding time instant i. In this equation, yj denotes the change ν in speed, and dt denotes the time interval between adjacent sampling instants (ie, the sampling interval determined by the sampling frequency). Thus, when the computing system 60 calculates the time offset at a given time, a new time value for that time is output. In conventional hydrocarbon production, the velocity slows down from the reference gather track to the control gather track, so the time shift is usually positive. When the computing system 60 imparts a time offset to a point on a reference gather track, it may be considered a time-shifted point, and when the computing system 60 imparts time offsets to points on a reference gather track, the track is said to be a time-shifted track.

The second term of the predicted reference gather track, A^COT, corresponds to the amplitude change that the computing system 60 performs on the time-shifted reference gather track at time point i. In accordance with the present embodiments, the computing system 60 time-shifts this amplitude change so that the amplitude changes are properly accounted for in the time-shifted reference gather track. In this expression, ψ denotes the estimate of the wavelet, such as the Ricker wavelet, used by the computing system 60 to estimate the wavelet generated by the seismic source. Other wavelets and various well-known methods for estimating seismic waves can be used. It has been found that in some embodiments, deviations in the amplitude and phase of the seismic wavelet within 20% of the true value are acceptable for the objective function.

Computing system 60 convolves wavelet ψ with ^D representing the change in local reflectivity associated with time instant i of the time-shifted reference gather track. In particular, while the reference gather track would be represented by the convolution of the reflectivity with the wavelet estimate, in this case, the change from the reference survey to the control survey is represented by the change in the convolution of the reflectivity with the wavelet estimate.

In embodiments where the computing system 60 determines that a change in velocity is the primary cause of the change in impedance from the reference survey to the control survey, for example, by executing a program stored in memory 66, the computing system 60 may consider the local change in reflectance through the change in velocity as follows:

△^di+i<=w - 2^+1 ^- Ft) where ΔR _N = 0, y _i+1 represents the change in speed in the sample at the time immediately following time point i (following the end of the sampling interval), a yi is the change in speed at time i. Thus, the change in the local reflection coefficient for time instant i is proportional to its local change in the velocity change. Situations where changes in density are identified by the computing system 60 as significant will be discussed in more detail below.

- 9 045222

In accordance with the present embodiments, the computing system 60, when performing a single track inversion process, may, in some circumstances, account for density changes using a scalar multiplier based on the assumption that

Δο /Δν\ - ~ a - p \ ν / where the scalar factor α can be chosen depending on the percentage of the change in density in the change in impedance from the reference survey to the control survey. Based on the above assumption, a scalar factor α is introduced by the computing system 60 into the objective function through the following equation:

+ os △A I ί+κ=Ν = (Υί+ι - Yi) where γ, as before, is the change in speed. Circumstances where the use of a scalar multiplier may be appropriate include cases where the relationship between the change in velocity and the change in density is approximately linear.

Thus, in one or more embodiments of a computing system, the objective function can be represented only as a function of one type of variable—speed change. Accordingly, the initial operations performed by the computer system 60 as part of the single track inversion process in step 86 may include obtaining an initial estimate of the speed changes (step 88). Initial estimates may be made, for example, based on previously generated models (eg, previously generated velocity models) related to the subsurface. The presented embodiments, however, are not limited to these estimation methods, and initial estimates of speed changes may be performed by the computing system 60 in any suitable manner.

After the system 60 has generated the initial rate change estimate according to step 88, the computing system 60 generates an initial track of the predicted reference survey, and calculates the difference 2C (or variations thereof, eg, C) in accordance with the objective function. If it is detected that the difference exceeds the convergence threshold, the computing system 60 iteratively calculates the change in speed (step 90). Computer system 60 may perform this procedure until the difference C is below a predetermined threshold. When performing the actions of steps 88 and 90, the computing system 60 may linearize the gradient associated with the objective function using linear interpolation to determine how the velocity changes should be modified. The performance of the linearized gradient can be improved by sampling more frequently (e.g., at 1 ms intervals). When it is determined that the objective function has reached a value C equal to or less than the set threshold, the computing system 60 (performing method 80) can be considered to have a final estimate of the rate changes, meaning that no further iterations are required.

Computing system 60 may produce a number of different outputs using the velocity changes generated by the single track inversion process in step 86, for example, to determine possible subsurface development paths. For example, computing system 60 may use the output of velocity changes to characterize (at step 92) changes in the subsurface, by constructing a 3D map of velocity changes or subsurface velocity, or by updating an existing velocity, impedance, density, or other models. Computing system 60, for example, in addition to the systems described in FIGS. 2 and/or 3 may also use these characteristics as part of the mining process (step 94).

In fig. 6 is a diagram 100 of various relationships showing how an objective function used by computing system 60 can be considered to perform in the time domain. In particular, chart 100 shows functions that are graphs of different types of quantities versus time, in which negative values for each track are shown to be directed to the left and positive values for each track are shown to be directed to the right. In chart 100, a reference gather track 102 and a control gather track 104 corresponding to the reference gather track 102 are shown as functions of amplitude (waveforms). As shown above, the control gather track 104 corresponds to the reference gather track 102 because the control gather track 104 was obtained by sending a seismic wave through the subsurface zone at the same point on the ground for which the reference gather track 102 was obtained.

The target function generally starts with the reference gather track 102 as the source track. The rate change function 106 is determined (eg, estimated) by the computing system 60 either as a sequence of discrete rate change values based on previously obtained speed models, or is modeled by the computer system 60 as a function (eg, an equation). In shown in FIG. In example 6, the speed change function 106 is approximated by the signal 10 045222

Δν is rectangular in shape and has the form ν as a function of time. As can be seen from the diagram in Fig. 6, since the reference gather track 102 is offset (i.e., side-transformed) in a manner similar to the reference gather track 102, the rate change function 106 includes negative rate change values indicating that the seismic waveform used to generate the track reference gather propagates through the subsurface at a lower velocity than the seismic wave used to generate the reference gather track.

The computing system 60 generates a time shift function 108 via an objective function based on an estimate of the rate change function 106 . More specifically, the computing system 60 may generate a time shift function 108 as a weighted sum of the change in speed over the sampling period. As shown, the time shift tends to shift toward positive values over time, causing the times of reference gather track 102 observed later in the exposure period to be shifted such that they appear to have been received even later. The result of the time shift is illustrated by the time shifted reference gather track 110. In the objective function formula, the time-shifted seismogram track 110 is designated as GG

As discussed above, there are essentially two changes expected to occur between the reference gather track 102 and the reference gather track 104—a time shift (or change in the propagation time of the seismic wave used to construct the gathers) and an amplitude change. The change in amplitude from the reference survey to the control survey, which in this case is an estimate of the convolution of the seismic wave with the change in reflectivity, is shown by the amplitude change function 112. However, taking into account the diagram in FIG. 6, it should be understood that if the amplitude change function 112 is used to modify the time-shifted reference gather track 110, there will be a mismatch between the peak value 114 of track 110 and the amplitude change peak 116 of the amplitude change function 112. This occurs because peak 114 occurs at offset time 118, while peak 116 of the amplitude change of amplitude change function 112 has not been shifted and corresponds to unshifted time 120.

As shown in FIG. 6, in accordance with the present embodiments, the computing system 60 applies a time shift function 108, through an objective function, to an amplitude change function 112 to generate a time shifted amplitude change function 122. Reporting the amplitude change in this manner by time shifting ensures that the amplitude change in the time-shifted reference gather track 110 is properly accounted for. The objective function represents the values of the time-shifted amplitude change function 122 as ΔΥ9)]ί. in this regard, the objective function combines the time-shifted amplitude change 122 and the time-shifted reference gather track 110 to produce a predicted reference gather track 124.

It should be noted that while the present disclosure primarily relates to shifting a reference gather track to align with a corresponding reference gather track, the present disclosure is not necessarily limited to such a technique. In particular, the reference seismic trace is selected as the shear trace primarily because the reference seismic volume typically has a reservoir with a shallow bottom compared to the reference seismic volume. Indeed, linear interpolation has been found to be better suited for calculating the inversion gradient and performing the inversion when a relatively high sampling rate is used (eg, 1 ms) and when the time offset from the velocity change will move the reservoir bottom lower.

As shown above, the computing system 60 may use the single track inversion estimate of speed changes in a variety of ways. In a particular example, computing system 60 may apply the velocity change estimate to the subsurface velocity model for the reference survey to generate an estimated or updated subsurface velocity model for the reference survey. In addition, it should be noted that the single track inversion techniques implemented by the computing system 60 can be used not only in cases where the timing offsets are small (eg, less than 2 sampling intervals), but also when the timing offsets are relatively large (eg , 2 or more quantization intervals). Indeed, in cases where the time offsets are relatively large, it is believed that it becomes more important for the computing system 60 to apply the time offset to the amplitude change, in addition to applying the time offset to the original track (eg, the seismogram reference track).

Fig. 7A-7B in particular illustrate the accuracy of the described single track inversion method for cases where the time offset is relatively small. In fig. 7A shows a true model of the velocity change 150 occurring between the synthesized reference survey velocity model and the

- 11 045222 speed of the synthesized control survey of the subsurface zone, where the position along the seismic array is plotted along the horizontal axis, and time is plotted along the vertical axis. The true velocity change model 150 reflects the actual (ie, ground control data) magnitude of the velocity change between the synthesized reference survey and the synthesized reference survey velocity models (ie, the amount of velocity change caused between the synthesized reference survey and the synthesized reference survey).

Velocity models were generated using the Data Dictionary System (DDS) data input/output system offered by BP America Inc. Such models can be called 2D synthetics. A true velocity change pattern 150 involves relatively constant velocity changes represented by a ribbon-like shape. On the left side of the belt shape, the speed changes are a relatively constant -5%, and on the right side of the belt shape, the speed changes are a relatively constant +5%.

In fig. 7B shows the raw inversion output 152 of a single track inversion process in one or more of the embodiments described herein. In particular, in FIG. 7B is the raw output of the single track inversion process described, for example, with reference to step 86 in FIG. 5 are applied to the synthesized reference survey and the synthesized control survey to calculate the velocity changes between the synthesized reference and control surveys. It can be seen that the raw inversion output 152, without further processing, is generally consistent with the true rate variation model 150. The accuracy of the present embodiments can be further assessed from the depiction in FIG. 7B, which shows the regularized inversion output 154 after regularizing the raw inversion output 152. As shown in FIG. 7B, after removing distortions by regularization, the simulated speed changes match the ground truth model of speed changes 150 even better.

In fig. 8A and 8B show velocity models for the reference and control synthetics generated in a manner similar to that described in relation to FIGS. 7A-7B. In particular, in FIG. 8A and 8B provide a visual comparison of the inversion results in the case where the change in the amplitude of the target function (corresponding to the unshifted inversion output 160 shown in FIG. 8A) is not time shifted and in the case where the change in the amplitude of the target function (corresponding to the shifted output 162 inversion shown in Fig. 8B) received a time shift. It can be seen that if the time shift from the reference to the reference survey is relatively large (e.g., 2 or more sampling intervals), significant error is introduced into the model when the time shift is not reported to the amplitude change. Both models are shown without regularization, and the shifted 162 inversion output was found to have the same reservoir thickness in time as the actual model.

As discussed above, in some embodiments it may be assumed that for purposes of the single track inversion process of the present disclosure, the change in density is negligible because the major change in the reservoir from a reference survey to a reference survey is a change in velocity. As one example, if hydrocarbon production results in a relatively small amount of gas coming out of solution, the change will predominantly be in velocity. However, in other cases, changes in density have a noticeable effect. Indeed, it is now established that the percentage error in estimating impedance change increases exponentially with the percentage contribution of density change to the impedance change. Accordingly, as discussed above, the computing system 60 can account for changes in density using a scalar factor a, which can be selected depending on the percentage contribution of the density change to the change in impedance from the reference survey to the reference survey. Conditions under which this scalar factor may be applicable include situations where the relationship between the change in velocity and the change in density is approximately linear.

In fig. 9 is a chart 170 providing an example of how materials in a reservoir can influence changes in density and velocity, and the ratio thereof, for a particular reservoir. As shown in FIG. 9, there are a number of scenarios presented in the box at the top of the diagram that serve as examples of processes that can occur between the time points when the reference and control surveys are performed. Specifically, the options shown in the box include the first scenario 172, the second scenario 174, the third scenario 176, the fourth scenario 178, the fifth scenario 180, the sixth scenario 182, the seventh scenario 184, and the eighth scenario 186. These scenarios are accompanied by example water, oil saturation values and/or gas (respectively, S _w , S _o and Sg). It should be noted that in diagram 170 of FIG. 9 it is assumed that the pressure remains relatively constant.

The four sectors highlighted in diagram 170 are divided according to the presence of gas and the injection of water or gas. Specifically, based on the presence of gas in the reservoir, the first trend line 188 corresponds to the absence of gas in the reservoir, and the second trend line 190 corresponds to the presence of gas in the reservoir. The first and second trend lines 188, 190 correspond to positive values of the speed change and negative values of the speed change, respectively. With respect to fluid injection into the reservoir, the third trend line 192 corresponds to water injection into the reservoir, and the fourth trend line 194 corresponds to gas injection into the reservoir. The third and fourth trend lines 192, 194 correspond to positive values of density changes and negative values of density changes, respectively.

For the first, second, third and fourth scenarios 172, 174, 176, 186, the density increases as water is supplied and the change in speed has a negative sign since the changes in impedance are mainly determined by the change in density. In particular, the bulk modulus K of the fluid is mainly determined by the bulk modulus of the gas, and the p-wave velocity Vp is related to the bulk modulus of the fluid by the following equation:

where K usually does not change any noticeably, but as the density ρ increases, the velocity Vp of the fluid will fall. The velocity Vp in the rock will also decrease accordingly, with a decrease in Vp resulting in a negative value for the velocity change.

In fig. Figure 10 shows an example of the inversion results obtained by the objective function when the density change accounts for 60% of the impedance change. In particular, the left diagram presents a set of first inversion results 200 showing that when the computing system 60 does not use a scalar factor α to account for density changes, there is an obvious error in both the speed change and the time shift produced by the objective function. However, when the computing system 60 assigns an appropriate value to the scalar multiplier a, in this example equal to 1.5, more accurate velocity change and time shift inversion results are apparently obtained, as shown in the second inversion result set 202.

With that said, the 4D joint inversion processes performed by the computing system 60 can be considered an adaptive method, introducing the ability to adjust a scalar parameter to account for changes in the rate of change in density without introducing an additional variable into the objective function. Examples of values for the scalar factor are given in the table below. 1.

According to an embodiment, according to the table, three areas of the graph of the relationship between the values of change (dv/v) of speed and change (dp/p) of density, such as the graph shown in FIG. 9, divided equally depending on the angle. Alpha values corresponding to angles less than 180° are assumed to be used in the inversion value base. It is noted that some of the values stand out sharply. For example, the values for 90 and 270° are unrealistic, and the value for 180° corresponds to a negligible contribution from the density change.

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Claims (16)

Table. Examples of values for α Angle (Degrees) dp/p dv/v A 0 0 1 0.00 10 0.173648175 0.984807754 0.18 20 0.342020138 0.939692623 0.36 thirty 0.499999992 0.866025408 0.58 40 0.642787601 0.766044451 0.84 50 0.766044434 0.642787621 1.19 60 0.866025395 0.500000015 1.73 70 0.939692614 0.342020163 2.75 80 0.984807749 0.173648201 5.67 90 1 2.67949E-08 100 0.984807758 -0.173648148 -5.67 BY 0.939692632 -0.342020113 -2.75 120 0.866025422 -0.499999969 -1.73 130 0.766044468 -0.64278758 -1.19 140 0.642787642 -0.766044416 -0.84 150 0.500000039 -0.866025381 -0.58 160 0.342020188 -0.939692604 -0.36 170 0.173648228 -0.984807744 -0.18 180 5.35898E-08 -1 0.00 190 -0.173648122 -0.984807763 0.18 200 -0.342020087 -0.939692641 0.36 210 -0.499999946 -0.866025435 0.58 220 -0.64278756 -0.766044485 0.84 230 -0.766044399 -0.642787662 1.19 240 -0.866025368 -0.500000062 1.73 250 -0.939692595 -0.342020213 2.75 260 -0.98480774 -0.173648254 5.67 270 -1 -8.03847E-08 The specific embodiments described above have been presented by way of example, and it should be understood that these embodiments may be subject to various modifications and implementation in other forms. It should also be understood that the claims are not intended to be limited to these specific forms disclosed, but rather are intended to cover all modifications, equivalents and alternatives that fall within the spirit and scope of the present disclosure. The methods presented and claimed herein relate to and are applicable to tangible objects and specific examples of a practical nature that obviously advance the technical field and, for this reason, are not abstract, intangible or purely theoretical. In addition, if the appended claims at the end of this specification contain one or more elements identified as means for [performing] [function] or a step for [performing] [function], it is intended that such elements are to be construed under 35 U.S.C. steam. 112(f). However, for any claims containing elements designated in any other way, it is intended that such elements shall not be construed under 35 U.S.C. par. 112(f). CLAIM 1. A method for assessing changes in a hydrocarbon reservoir, which involves receiving a reference seismogram track from a reference seismic survey and a control seismogram track from a control seismic survey, associated with a hydrocarbon reservoir and obtained at corresponding different times by exposure to a seismic vibration at approximately the same location on the ground, directed along the corresponding paths of propagation of seismic vibrations through the rock at corresponding different points in time; generating a predicted control gather track based on a reference gather track and a control gather track, wherein generating the predicted control gather - 14 045222 gathers from a reference gather track includes estimating the initial velocity changes occurring between the reference gather trace and the control gather trace, wherein the estimated initial velocity changes are associated with variations in the velocity of propagation of seismic vibration through a hydrocarbon reservoir; communicating to the reference gather track a time offset based on the estimated initial velocity changes, and compensating for amplitude changes between the reference gather track and the reference gather track, wherein the amplitude changes are communicated with said time offset to generate a predicted reference gather track, wherein the reference gather track, the reference gather track, and the predicted The control seismogram track represents different seismograms; minimizing, until a predetermined convergence is achieved, the difference between the predicted control gather track and the control gather track by iteratively estimating the estimated initial velocity changes to obtain the final estimated velocity changes; and generating, based on at least the final estimated velocity changes, a velocity change map showing changes in geological characteristics of the hydrocarbon reservoir between the reference seismic survey and the control seismic survey. 2. The method of claim 1, wherein, in compensating for changes in amplitude between the reference gather track and the reference gather track, applying to each sample point of the time-shifted reference gather track an estimate of the convolution of the seismic wavelet with the time-shifted local change in reflectivity. 3. The method of claim 2, wherein the time-shifted local change in reflectivity corresponds, for each sample point, to a difference in velocity change between the corresponding sample point and an adjacent sample point on the reference gather track. 4. The method of claim 3, wherein the adjacent sample point is a sample point taken one sample interval from the corresponding sample point. 5. The method of claim 4, wherein the reference gather track and the reference gather track are sampled at a sampling interval of 1 millisecond (ms) or less. 6. The method of claim 3, wherein when generating a predictive reference gather track, assigning a scalar multiplier to the local change in time shift in reflectivity based on the assumed linear relationship of the density change between the reference gather track and the reference gather track, and the change in velocity due to fluid changes in hydrocarbon productive formation. 7. The method of claim 6, wherein when assigning a scalar multiplier, a scalar multiplier value is determined that is proportional to the percentage of impedance change between the reference gather trace and the reference gather trace caused by the density change. 8. The method of claim 1, wherein the time shift is calculated as a weighted sum of the velocity change, wherein the weighted summation is performed over sampling points of the reference gather track from the first sampling point of the reference gather track to the corresponding sampling point of the reference gather track for which the time shift is calculated . 9. The method of claim 1, wherein by minimizing, until a predetermined convergence is achieved, the differences between the predicted control gather track and the control gather track, minimizing at least the least squares difference between the predicted control gather track and the control gather track. 10. The method of claim 1, comprising estimating the estimated initial change in velocity γ in accordance with the equation Δν where Δν represents the difference in velocity at the sampling point of the reference gather trace and the velocity at the corresponding sampling point of the reference gather trace, and ν represents the velocity at the sampling point of the reference gather trace. 11. A non-volatile, tangible, computer-readable storage medium containing commands recorded on it that, when executed by a computer, invert one track to determine a change in a hydrocarbon reservoir, and which include commands for receiving a reference gather track and a reference gather track associated with the hydrocarbon reservoir and obtained at corresponding different points in time by exposure to a seismic vibration at approximately the same place on the earth, directed along the corresponding paths of propagation of the seismic vibration through the rock at corresponding different points in time; generating a predicted control gather track based on the reference gather track - 15 045222 seismograms and control gather tracks through a procedure in which an estimate of initial velocity changes occurring between a reference gather trace and a control gather trace is performed, wherein the estimated initial velocity changes are related to variations in the velocity of propagation of a seismic vibration through a hydrocarbon reservoir; providing the reference gather track with a time offset based on the estimated initial velocity changes, and compensating for amplitude changes between the reference gather track and the reference gather track, wherein said time offset is imparted to the amplitude changes to generate a predicted reference gather track, wherein the reference gather track, the reference gather track, and the predicted The control seismogram track represents different seismograms; minimizing to a predetermined convergence the difference between the predicted control gather track and the control gather track, iteratively estimating the estimated initial velocity changes to obtain the final estimated velocity changes, and determining the changes in at least a portion of the hydrocarbon reservoir using the final estimated velocity changes. 12. The storage medium of claim 11, wherein compensating for amplitude changes between the reference gather track and the reference gather track comprises applying to the time-shifted reference gather track an estimate of the seismic convolution of the time-shifted reflection coefficient change. 13. The storage medium of claim 12, wherein compensating for changes in amplitude between the reference gather track and the reference gather track includes assigning a scalar multiplier to the time-shifted change in reflectivity based on a linear relationship of the density change between the reference gather track and the reference gather track, and the change in velocity when there are changes in the fluid in the hydrocarbon reservoir. 14. The storage medium of claim 12, wherein the instructions for determining changes in at least a portion of the hydrocarbon reservoir using the final estimated velocity changes comprise instructions for updating at least a portion of the velocity map in the hydrocarbon reservoir. 15. A system for assessing changes in a hydrocarbon reservoir, comprising a memory device for storing commands and a processor connected to the memory device and configured to execute said commands configuring it to receive a reference seismogram track of a reference seismic survey and a reference seismogram track of a control seismic survey, associated with a hydrocarbon reservoir and obtained at appropriate different times by exposure to seismic vibration at approximately the same location on the earth, directed along the corresponding propagation paths of seismic vibration through the rock at corresponding different times; generating a predicted reference gather track based on the reference gather track and the reference gather track, wherein generating the predicted reference gather from the reference gather track includes estimating initial velocity changes occurring between the reference gather track and the reference gather trace, wherein the estimated initial velocity changes are associated with the velocity variations propagation of seismic vibrations through a hydrocarbon productive formation; communicating to the reference gather track a time offset based on the estimated initial velocity changes, and compensating for amplitude changes between the reference gather track and the reference gather track, wherein the amplitude changes are communicated with said time offset to generate a predicted reference gather track, wherein the reference gather track, the reference gather track, and the predicted The control seismogram track represents different seismograms; minimizing to a specified convergence the difference between the predicted control gather track and the control gather track, iteratively estimating the estimated initial velocity changes to obtain the final estimated velocity changes and production based on at least the final estimated velocity changes of a velocity change map showing changes in the geological characteristics of the hydrocarbon reservoir formation between the reference seismic survey and the control seismic survey. 16. The system of claim 15, wherein said commands configure the processor to apply to each sample point of a time-shifted reference seismogram track an estimate of the convolution of the seismic wavelet with the time-shifted local change factor -