Seismic attribute map for gas detection

Abstract

A method of obtaining a relative amplitude preserving seismic volume acquired in time domain for a subsurface region of interest and transforming it into a low frequency monopolar amplitude volume. The method also determines a seismic attenuation volume from the relative amplitude preserving seismic volume acquired in time domain. Further, the method generates a low frequency monopolar amplitude map of a surface of interest by averaging the low frequency monopolar amplitude volume over a depth window around the surface of interest and generates a seismic attenuation map of the surface of interest by averaging the seismic attenuation volume over the depth window around the surface of interest. The method also determines an attribute map of the surface of interest based on the seismic attenuation map and the low frequency monopolar amplitude map and determines a presence of a gas in the subsurface region of interest based on the attribute map.

Description

Background Technology

[0001] In some cases, a portion of a reservoir within an area of ​​interest may contain gas deposits. In some cases, it may be desirable to use seismic surveys to detect these gas deposits. The influence of a portion of the reservoir containing gas deposits on the characteristics of reflected and refracted seismic waves can differ from that of a portion of the reservoir containing fluids (whether oil or water). In some cases, it may be desirable to drill a wellbore into the gas deposits to produce gas at the surface. This wellbore can be a vertical wellbore or a horizontal wellbore constructed using geosteering methods. Summary of the Invention

[0002] This summary is provided to introduce the selection of concepts that will be further described in the following detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid to limit the scope of the claimed subject matter. Generally, in one aspect, embodiments involve obtaining a seismic volume with relatively amplitude retention acquired in the time domain for a subsurface region of interest, and transforming this seismic volume into a low-frequency monospectral amplitude volume. The method also determines a seismic attenuation volume from the seismic volume with relatively amplitude retention acquired in the time domain. The method further generates a low-frequency monospectral amplitude map of the surface of interest by averaging the low-frequency monospectral amplitude volume over a depth window around the surface of interest. The method also generates a seismic attenuation map of the surface of interest by averaging the seismic attenuation volume over a depth window around the surface of interest. The method further determines a property map based on the seismic attenuation map and the low-frequency monospectral amplitude map of the surface of interest. The method further determines the presence of gas in the subsurface region of interest based on the property map.

[0003] In general, in one aspect, embodiments relate to a system including a seismic processor comprising a computer processing unit capable of executing instructions stored in a non-transitory computer storage medium. The system obtains a seismic volume with relative amplitude preservation acquired in the time domain for a subsurface region of interest, and transforms the seismic volume into a low-frequency monospectral amplitude volume. The system also determines a seismic attenuation volume from the seismic volume and generates a low-frequency monospectral amplitude map of the surface of interest by averaging the low-frequency monospectral amplitude volume over a depth window around the surface of interest. Furthermore, the system generates a seismic attenuation map of the surface of interest by averaging the seismic attenuation volume over a depth window around the surface of interest. The system also determines a property map based at least in part on the seismic attenuation map and the low-frequency monospectral amplitude map of the surface of interest, and the system further determines the presence of gas in the subsurface region of interest based on the property map.

[0004] Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims. Attached Figure Description

[0005] Specific embodiments of the disclosed technology will now be described in detail with reference to the accompanying drawings. For consistency, the same elements are indicated by the same reference numerals in the various drawings.

[0006] Figure 1 A seismic survey according to one or more embodiments is illustrated.

[0007] Figure 2 A 3D seismic body with relative amplitude preservation according to one or more embodiments is shown.

[0008] Figure 3 The figures and diagrams are shown according to one or more embodiments.

[0009] Figure 4 A flowchart for locating a gas according to one or more embodiments is shown.

[0010] Figure 5 A property diagram according to one or more embodiments is shown.

[0011] Figure 6A and 6B A system according to one or more embodiments is shown.

[0012] Figure 7 A computer system according to one or more embodiments is shown. Detailed Implementation

[0013] In the following detailed description of embodiments of the invention, numerous specific details are set forth in order to provide a more thorough understanding of the invention. However, it will be apparent to those skilled in the art that this disclosure may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.

[0014] Throughout this application, ordinal numbers (e.g., first, second, third, etc.) may be used as adjectives for elements (i.e., any noun in this application). The use of ordinal numbers does not imply or create any particular order of elements, nor does it limit any element to a single element, unless explicitly disclosed, such as by using the terms "before," "after," "single," and other such terms. Rather, ordinal numbers are used to distinguish between elements. As an example, a first element is different from a second element, and a first element may contain more than one element and be after (or before) the second element in the order of elements.

[0015] Figure 1A seismic survey 100 is shown, which may contain a subsurface region 102 of interest, 104, of reservoir 104. The seismic survey 100 may utilize a seismic source 106 that generates radiated seismic waves 108. The radiated seismic waves 108 may return to the surface as refracted seismic waves 110, or may be reflected by a geological discontinuity 112 and returned to the surface as reflected seismic waves 114. One type of geological discontinuity may be gas deposits 120. At the surface, the refracted seismic waves 110 and the reflected seismic waves 114 can be detected by a seismic receiver 116.

[0016] In some embodiments, the refracted seismic wave 110 and reflected seismic wave 114 generated by a single activation of the seismic source 106 are recorded by the seismic receiver 116 as a time series representing the amplitude of ground motion at discrete time intervals. This time series can be represented as a seismic "trace". The seismic receiver 116 is located at multiple seismic receiver locations, which can be represented as (x r y r ), where x and y represent orthogonal axes on the Earth's surface above the subsurface region of interest 102. Therefore, the refracted seismic wave 110 and reflected seismic wave 114 generated by a single activation of the seismic source 106 can be represented as having axes (x...). r y r A three-dimensional "3D" volume of (x, t), where (x) r y r ) represents the location of the seismic receiver 116, and t defines the time sample for measuring the amplitude of ground motion.

[0017] However, seismic survey 100 can include multiple locations located by (x s y s The record of seismic waves generated by earthquake source 106 at the location of the earthquake source is represented by (x). Therefore, the seismic body of seismic survey 100 can be represented as a five-dimensional body, denoted as (x). s y s x r y r ,t).

[0018] Figure 2 A three-dimensional (3D) seismic volume is illustrated according to some embodiments. Seismic processing reduces the five-dimensional seismic volume generated by seismic survey 100 to a 3D seismic volume 200 having a depth dimension 202, a first horizontal dimension 204, and a second horizontal dimension 206, wherein the first horizontal dimension 204 is orthogonal to the second horizontal direction 206 of the 3D image representing the subsurface region of interest. This reduction from a five-dimensional seismic volume to a 3D seismic volume is performed by correcting the recording time of seismic waves for the propagation ("migration") time from the seismic source 106 to the seismic receiver 116 and summing ("superimposing") the samples in the two spatial dimensions.

[0019] According to some embodiments, migration is performed after approximating the speed of seismic wave propagation as a function of depth location rather than horizontal location. Migration using this approximation is called "time migration". According to some embodiments, migration is performed without constraining the way the seismic wave propagation speed changes. Migration using this approximation is called "depth migration".

[0020] Therefore, there are four possible combinations of overlay and migration processes. Overlaying before migration, if time migration is used, may result in "post-overlay time migration"; if depth migration is used, may result in "post-overlay depth migration". Migration before overlay, if time migration is used, may result in "pre-overlay time migration"; if depth migration is used, may result in "pre-overlay depth migration". Each combination can be a 3D seismic volume 200 with relative amplitude preservation representing a 3D image of the subsurface region of interest. According to some embodiments, the 3D seismic volume 200 with relative amplitude preservation can be in two-dimensional (2D) spatial coordinates and depth or time. Figure 2 A 2D slice is described passing through the 3D seismic body. The 3D pixels ("voxels") 208 of the 3D seismic body 200 can have estimated values ​​representing the properties of the subsurface body of interest at the location of that voxel. For example, the property can be, but is not limited to, seismic wave reflection amplitude, or monospectral amplitude, or coherence value. Figure 2 A 2D vertical slice 210 and a 2D horizontal slice 212 passing through a 3D seismic body 200 are shown.

[0021] Figure 3 Volumes and figures are shown according to one or more embodiments. The seismic volume 300 with relative amplitude preservation can be... Figure 2The 3D seismic body 200 with relative amplitude preservation is shown. The low-frequency monospectral amplitude body 302 can be determined by a transformation from the relatively amplitude-preserved seismic body 300. According to some embodiments, the low-frequency monospectral amplitude body 302 represents the amplitude of a single frequency component of a time-domain signal at each spatial location in 3D space. According to one or more embodiments, the low-frequency monospectral amplitude body 302 can represent the amplitude of a single vertical wavenumber component of a depth-domain signal at each spatial location in 3D space, provided that this amplitude is preserved when the seismic body is transformed from the time domain to the depth domain. According to some embodiments, this transformation can be performed by applying a Gabor transform along the depth axis of the relatively amplitude-preserved 3D seismic body 200. According to some embodiments, this transformation can be performed by applying a continuous wavelet transform along the depth axis of the relatively amplitude-preserved 3D seismic body 200. According to some embodiments, this transformation can be performed by applying a discrete wavelet transform along the depth axis of the relatively amplitude-preserved 3D seismic body 200. Other methods for transforming a 3D seismic body 200 with relative amplitude preservation into a low-frequency monospectral body 302 will be apparent to those skilled in the art.

[0022] The seismic attenuator 304 can be determined from the seismic body 300 with relatively preserved amplitude. Seismic attenuation can include intrinsic seismic attenuation, where seismic energy is converted into heat, and non-intrinsic seismic attenuation, where coherent seismic waves are scattered into incoherent signals. Effective seismic attenuation can include the effects of intrinsic and non-intrinsic seismic attenuation. The proposed seismic attenuation determination method is based on the attenuation-induced changes in the spectral characteristics of the seismic wavelet. The Gabor transform spectrum can be used to analyze the seismic trace to observe its time-varying frequency content. This analysis method avoids interference from other seismic waves. Other methods for estimating seismic attenuation in seismic traces include the spectral ratio method, the centroid frequency shift method, and the peak frequency shift method. The seismic attenuator can be calculated using any of the above methods, or any other method familiar to those skilled in the art. Furthermore, the seismic attenuator 304 can be an effective attenuator, an intrinsic attenuator, and an instantaneous attenuator.

[0023] According to some embodiments, multiple surfaces of interest 306 can be selectively defined on them. The location of the surface of interest 306 can vary as a function of depth. The surface of interest 306 can be the top or bottom of a hydrocarbon reservoir. The surface of interest can be a geological surface of interest to the operator of the method. According to one or more embodiments, the surface of interest 306 can be a depth of interest that does not vary with horizontal spatial location. The depth of interest can be located within the hydrocarbon reservoir.

[0024] Furthermore, according to one or more embodiments, a depth window 308 is defined around a surface 306 of interest. The depth window 308 may extend at equal depth intervals above and below the surface 306 of interest, centered on it. Alternatively, the depth window 308 may extend at equal intervals on either side of the surface 306 of interest, in a direction perpendicular to it. In other embodiments, the depth window 308 may lie entirely above or entirely below the surface 306 of interest. According to one or more embodiments, the depth window 308 has a constant thickness anywhere within the subsurface region of interest. In other embodiments, the depth window 308 varies as a function of horizontal spatial position.

[0025] By averaging the values ​​of the low-frequency monospectral amplitudes within a depth window 308 at each horizontal spatial location, a low-frequency monospectral amplitude map 310 of the surface of interest 306 is determined from the low-frequency monospectral amplitude volume 302. Averaging can be performed using one of many methods well known to those skilled in the art. For example, averaging can include, but is not limited to, forming a root mean square (RMS), mean, mode, median, harmonic mean, geometric mean, weighted mean, weighted mode, weighted median, weighted harmonic mean, weighted geometric mean, truncated mean, truncated median, truncated harmonic mean, or truncated geometric mean.

[0026] By averaging the seismic attenuation values ​​within a depth window 308 at each horizontal spatial location, a seismic attenuation map 312 for the surface of interest 306 is determined from the seismic attenuation volume 304. Averaging can be performed using one of many methods well known to those skilled in the art, such as those listed above.

[0027] According to one or more embodiments, determining the low-frequency monospectral amplitude map 310 may further include applying a filter to the low-frequency monospectral amplitude map 310. The filter may be a spatial filter, such as a spatial smoothing filter, a tilt-guided filter, a structure-oriented filter, a deterministic filter, and a statistical filter.

[0028] Similarly, according to one or more embodiments, determining the seismic attenuation map 312 may also include applying a filter to the low-frequency monospectral amplitude map 310. The filter may be a spatial filter, such as a spatial smoothing filter, a tilt-guided filter, a structure-oriented filter, a deterministic filter, and a statistical filter.

[0029] The low-frequency monospectral amplitude map 310 and the seismic attenuation map 312 are combined to determine the attribute map 314. According to one or more embodiments, the value of each pixel in the attribute map 314 is calculated as a ratio of the value of a pixel in the seismic attenuation map 312 to the value of a pixel in the low-frequency monospectral amplitude map 310. In other embodiments, this ratio may be reversed, and the value of each pixel in the attribute map 314 is calculated as a ratio of the value of a pixel in the low-frequency monospectral amplitude map 310 to the value of a pixel in the seismic attenuation map 312. In still other embodiments, the value of each pixel in the attribute map 314 is calculated from multiple pixels in the seismic attenuation map 312 and multiple pixels in the low-frequency monospectral amplitude map 310.

[0030] According to one or more embodiments, the attribute map is displayed as a plurality of pixels with varying colors, hues, and saturations, or as gray levels representing attribute values ​​within pixels, or as attribute contour lines 316 connecting pixels with equal attribute values.

[0031] Figure 4 A workflow according to one or more embodiments is shown. Figure 4 One or more boxes in the middle can be made as follows Figure 7 One or more components (e.g., computer processor 760) described herein are used to perform this action. Although presented and described sequentially... Figure 4 The various boxes in the document are as follows, but those skilled in the art will understand that some or all of these boxes may be executed in a different order, may be combined or omitted, and some or all of these boxes may be executed in parallel. Furthermore, these boxes may be executed actively or passively.

[0032] In box 402, a 3D seismic volume 200 with relative amplitude preservation is obtained by processing the seismic survey 100 of the subsurface region of interest. Processing the seismic survey 100 to obtain the 3D seismic volume 200 with relative amplitude preservation requires performing each step in the processing chain in a manner that does not distort the amplitude of the seismic signal, such as correcting inhomogeneities near the seismic source and receiver, correcting the geometric spread of the wavefield, attenuating noise, and attenuating seismic multiples. In particular, the processing algorithm must avoid generating zero values ​​in the seismic signal spectrum and angular variations in the radiometric map. The 3D seismic volume 200 with relative amplitude preservation can be a post-stack time-migration volume, a post-stack depth-migration volume, a pre-stack time-migration volume, or a pre-stack depth-migration volume.

[0033] Furthermore, in box 402, a surface of interest 306 that requires attribute map 314 is defined. The surface of interest 306 can be a depth of interest. Alternatively, the surface of interest 306 can be a geological surface, such as the top or bottom of a hydrocarbon reservoir. The surface of interest 306 is further disclosed in the preceding paragraph

[0023] .

[0034] In block 404, the relative amplitude-preserving seismic volume 300 is transformed into at least one 3D low-frequency monospectral amplitude volume. According to one or more embodiments, this transformation can be performed by applying a short-window Fourier transform along the time axis of the relative amplitude-preserving 3D seismic volume. According to other embodiments, this transformation can be performed by applying a Gabor transform or a continuous wavelet transform along the time axis of the relative amplitude-preserving 3D seismic volume. According to other embodiments, this transformation can be performed by applying a discrete wavelet transform along the time axis of the relative amplitude-preserving 3D seismic volume. Other methods for transforming a relative amplitude-preserving 3D seismic volume into multiple monospectral volumes will be apparent to those skilled in the art.

[0035] More specifically, in box 404, a filter is applied to the 3D seismic body with relative amplitude preservation. The filter can be a spatial filter, such as a spatial smoothing filter, a dip-guided filter, a structure-oriented filter, a deterministic filter, and a statistical filter. The result of applying the spatial filter can be, but is not limited to, reduction or removal of noise spikes, removal of outliers, or increase in the spatial smoothness of the 3D seismic body with relative amplitude preservation.

[0036] In block 404, according to some embodiments, a plurality of 3D low-frequency monospectral amplitude bodies 302 can be generated from the relative amplitude-preserving seismic body 300. One of these 3D low-frequency monospectral amplitude bodies 302 can be selected. The criteria used to select a 3D low-frequency monospectral amplitude body 302 can be based at least in part on the spatial variation of voxel values. For example, a 3D low-frequency monospectral amplitude body 302 that varies smoothly in space can be selected. Alternatively or additionally, other selection criteria can be used.

[0037] In box 406, the seismic attenuator 304 is determined at least in part based on the seismic volume with relatively preserved amplitude. The seismic attenuator 304 can be determined through the above... Figure 3 It can be determined using any of the various methods mentioned in the discussion.

[0038] In block 408, according to one or more embodiments, a low-frequency monospectral amplitude map 310 of the surface of interest 306 can be determined. The low-frequency monospectral amplitude map is determined by averaging the values ​​of the low-frequency monospectral amplitude volume 302 on voxels located within a depth window 308 associated with the surface of interest.

[0039] In box 410, according to one or more embodiments, a seismic attenuation map 312 for the surface of interest 306 is determined. The seismic attenuation map can be determined by averaging the values ​​of seismic attenuation volumes 304 on voxels located within a depth window 308 associated with the surface of interest.

[0040] In block 412, according to some embodiments, an attribute map 314 is generated from a low-frequency single-frequency spectral amplitude map 310 and a seismic attenuation map 312. This attribute map 314 can be generated pixel-by-pixel, such that a pixel from the low-frequency single-frequency spectral amplitude map 310 and a pixel from the seismic attenuation map 312 uniquely identify a pixel in the attribute map 314. In other embodiments, multiple pixels from the low-frequency single-frequency spectral amplitude map 310 and multiple pixels from the seismic attenuation map 312 can contribute to one or more pixels in the attribute map 314.

[0041] In other embodiments, pixel-by-pixel calculations can be supplemented by first calculating the average value of a subset of pixels in one or both of the low-frequency monospectral amplitude map 310 and the seismic attenuation map 312.

[0042] In block 414, according to some embodiments, the presence of hydrocarbons, including natural gas deposits 120, such as methane, within rock pores on property map 314 is determined. In some embodiments, the presence of gas deposits 120 may be indicated by pixels having attribute values ​​above a threshold. In some embodiments, the presence of gas deposits 120 may be indicated by pixels having attribute values ​​below a threshold. The threshold may be user-determined or may be calculated based on a range of pixel values ​​in the property map. According to other embodiments, pixel values ​​may be interpreted as the probability that gas deposits 120 may be present at the location represented by the pixel on the property map. These indications of the presence of gas deposits 120 may be automatically evaluated and stored in non-transitory computer memory. Alternatively, these indications of the presence of gas deposits 120 may be manually checked on a visual display.

[0043] In block 416, according to one or more embodiments, wells can be planned and drilled at least in part based on indications of the presence of gas deposits 120 as shown in property diagram 314. Locations indicating the presence of gas deposits 120, or locations where the probability of the presence of gas deposits 120 is high, can be targets for the well. Areas in property diagram 314 that do not indicate the presence of gas, or areas where the probability of the presence of gas deposits 120 is low, can be avoided.

[0044] Figure 5 An example of a property diagram 502 of a surface 306 of interest according to one or more embodiments is shown. Figure 5The horizontal and vertical axes are located in a horizontal plane, and the attribute values ​​in each pixel are represented by gray levels. In addition to the attribute values ​​as a function of horizontal spatial location, attribute map 502 also shows the locations of seven wells penetrating the surface of interest 306. Six of these wells, 504, primarily or exclusively produce water and correspond to the low values ​​on attribute map 502. The seventh well, 506, primarily or exclusively produces gas and corresponds to the high values ​​on attribute map 502. This strong correlation between the attribute values ​​and the fluid produced from the wells provides strong evidence that attribute map 502 is a reliable indicator of the presence of gaseous deposits 120.

[0045] Figure 6A and 6B A system according to one or more embodiments is shown. Figure 6A As shown, the drilling system 600 may include a top drive rig 610 arranged around a drill bit logging tool 620. The top drive rig 610 may include a top drive 611 suspended in a derrick 612 via a traveling block 613. At the center of the top drive 611, a drive shaft 614 may be threaded to the top tube of the drill string 615, for example. The top drive 611 allows the drive shaft 614 to rotate, causing the drill string 615 and the drill bit logging tool 620 to cut rock at the bottom of the wellbore 616. A power cable 617 supplying power to the top drive 611 may be protected within one or more maintenance circuits 618 coupled to a control system 644. Drilling mud can then be pumped into the wellbore 616 via mud lines, the drive shaft 614, and / or the drill string 615.

[0046] Furthermore, during well completion, the casing can be inserted into the wellbore 616. The sides of the wellbore 616 may require support, so the casing can be used to support the sides of the wellbore 616. In this way, the space between the casing and the untreated side of the wellbore 616 can be cemented to hold the casing in place. Cement can be forced through the lower end of the casing and into the annular space between the casing and the wall of the wellbore 616. More specifically, a cement plug can be used to push cement out of the casing. For example, the cement plug can be a rubber plug used to separate the cement slurry from other fluids, thereby reducing contamination and maintaining predictable cement slurry performance. A displacement fluid, such as water or appropriately weighted drilling mud, can be pumped into the casing above the cement plug. This displacement fluid can be a pressurized fluid used to push the cement plug downwards through the casing to expel cement from the casing outlet and return it upwards into the annular space.

[0047] like Figure 6AAs further shown, sensor 621 may be included in sensor assembly 623, which is located adjacent to drill bit 624 and coupled to drill string 615. Sensor 621 may also be coupled to processor assembly 623, which includes a processor, memory, and analog-to-digital converter 622 for processing sensor measurements. For example, sensor 621 may include acoustic sensors such as accelerometers, measuring microphones, contact microphones, and hydrophones. Similarly, sensor 621 may include other types of sensors, such as transmitters and receivers for measuring resistivity, gamma ray detectors, etc. Sensor 621 may include hardware and / or software for generating different types of logging records (such as acoustic logging records or density logging records), which can provide well data about the wellbore, including porosity of wellbore sections, gas saturation, formation boundaries in geological formations, fractures in the wellbore or completion cement, and many other information about the formation. If such well data is acquired during drilling operations (i.e., logging while drilling), this information can be used to adjust drilling operations in real time. Such adjustments can include drilling rate (ROP), drilling direction, changing mud density, and many other drilling parameters.

[0048] In some embodiments, an acoustic sensor may be installed in the drilling fluid circulation system of the drilling system 600 to record acoustic drilling signals in real time. The drilling acoustic signals can be transmitted via drilling fluid for recording by the acoustic sensor located in the drilling fluid circulation system. The recorded drilling acoustic signals can be processed and analyzed to determine well data, such as the lithological and rock physical properties of the formation. This well data can be used for various applications, such as guiding the drill bit using geological steering, casing shoe positioning, etc.

[0049] The control system 644 may be coupled to the sensor assembly 623 to execute various programmed functions for the vertical and horizontal guidance of the drill bit 624 through the wellbore 616. More specifically, the control system 644 may include hardware and / or software with the ability to geologically guide the drill bit through formations in the lateral well using sensor signals such as drilling acoustic signals or resistivity measurements. For example, the formation may be a reservoir region, such as a producing layer, bedrock, or caprock.

[0050] Geological steering can be used to position the drill bit 624 or drill string 615 relative to the boundaries between different subsurface formations (e.g., overlying, underlying, and lateral formations of the producing layer) during drilling operations. Specifically, measuring rock properties during drilling can provide the drilling system 600 with the ability to maneuver the drill bit 624 in the direction of a desired hydrocarbon concentration. Thus, the geological steering system can use various sensors located inside or adjacent to the drill string 615 to determine different rock formations within the wellbore path. In some geological steering systems, the drilling tools can use resistivity or acoustic measurements to guide the drill bit 624 during horizontal or lateral drilling.

[0051] Go to Figure 6B , Figure 6B Examples of embodiments for using a geological steering system 690 to guide a drill bit through lateral producing formations are shown. For example... Figure 6B As shown, the geological guidance system 690 may include Figure 6A The drilling system 600. Specifically, the geological guidance system 690 may include functionality for monitoring various sensor characteristics (e.g., acoustic characteristics from acoustic sensors) that change gradually or abruptly as the wellbore path traverses the caprock 630, producing layer 640, and bedrock 650. For example, due to the abrupt change in lithology between the caprock 630 and producing layer 640, the sensor characteristics of producing layer 640 may differ from those of caprock 630. When the drill bit 624 drills out of producing layer 640 and into caprock 630, the amplitude spectrum detected by a particular sensor type may change abruptly between two different sensor characteristics. Conversely, as drilling downwards from producing layer 640 into bedrock 650, the detected amplitude spectrum may change gradually.

[0052] During lateral drilling of wellbore 616, the preliminary upper and lower boundaries of the formation thickness can be derived from geophysical surveys and / or offset wells obtained prior to drilling wellbore 616. If the vertical portion 635 of the well is drilled, the actual and lower boundaries of the formation (i.e., the actual producing boundary (A, A')) and the producing thickness at the vertical portion 635 (i.e., A to A') can be determined. Based on this well data, the operator can guide drill bit 624 through the lateral section 660 of wellbore 616 in real time. Specifically, logging tools can monitor detected sensor features near drill bit 624, wherein the detected sensor features can be continuously compared with, for example, previous sensor features of caprock 630, producing layer 640, and bedrock 650, respectively. Thus, if the detected sensor features of the drilled rock are the same as or similar to the sensor features of producing layer 640, drill bit 624 may still be drilling in producing layer 640. In this scenario, drill bit 624 can be operated to continue drilling along its current path at a predetermined distance (0.5h) from the formation boundary. If the detected sensor features are the same as or similar to previous sensor features of caprock 630 or bedrock 650, control system 644 can determine that drill bit 624 has drilled out of producing formation 640 and entered its upper or lower boundary. At this point, the vertical position of drill bit 624 at this lateral position within wellbore 616 can be determined, and the upper and lower boundaries of producing formation 640 can be updated (e.g., Figure 6B (Positions B and C in the middle). In some embodiments, the vertical positions at the relative boundaries, such as positions B' and C', can be estimated based on a predetermined thickness of the layer 640.

[0053] Although Figure 6A and 6B Various configurations of the components are shown, but other configurations may be used without departing from the scope of this disclosure. For example, Figure 6A and 6B Various components can be combined to form a single component. As another example, a function performed by a single component can be performed by two or more components.

[0054] The embodiments can be implemented on a computer system. Figure 7 This is a block diagram of a computer system 702 implemented to provide computational functions associated with the algorithms, methods, functions, processes, flows, and procedures described herein. The computer 702 shown is intended to encompass any computing device, such as a server, desktop computer, laptop / notebook computer, wireless data port, smartphone, personal data assistant (PDA), tablet computing device, one or more processors within these devices, or any other suitable processing device, including physical or virtual instances (or both) of the computing device. Additionally, computer 702 may include input devices, such as a keypad, keyboard, touchscreen, or other devices capable of accepting user information, and output devices that transmit information associated with the operation of computer 702, including digital data, visual or audio information (or a combination of information), or a GUI.

[0055] Computer 702 may act as a client, network component, server, database, or other persistent device, or any other component (or combination of roles) of a computer system for performing the subject matter described in this disclosure. The illustrated computer 702 is communicatively coupled to network 730. In some embodiments, one or more components of computer 702 may be configured to operate within an environment including cloud-based, local, global, or other environments (or combinations of environments).

[0056] At a higher level, computer 702 is an electronic computing device operable to receive, transmit, process, store, or manage data and information associated with the described subject. According to some embodiments, computer 702 may also include, or be communicatively coupled to, an application server, email server, web server, cache server, streaming data server, business intelligence (BI) server, or other server (or combination of servers).

[0057] Computer 702 can receive requests from client applications (e.g., client applications running on another computer 702) via network 730 and respond to received requests by processing the requests in appropriate software applications. Furthermore, requests can also be sent to computer 702 from internal users (e.g., from a command console or via other appropriate access methods), external or third parties, other automated applications, and any other appropriate entity, individual, system, or computer.

[0058] Each component of computer 702 can communicate using system bus 703. In some implementations, any or all components of computer 702, whether hardware or software (or a combination of hardware and software), can be connected to each other or to interface 704 (or a combination of both) using system bus 703 with application programming interface (API) 712 or service layer 713 (or API 712) and service layer 713. API 712 may include specifications for routines, data structures, and object classes. API 712 may be computer language independent or computer language dependent, and refers to a complete interface, a single function, or even a set of APIs. Service layer 713 provides software services to computer 702 or other components (whether shown or not) communicatively coupled to computer 702. The functionality of computer 702 is accessible to all service consumers using the service layer. Software services, such as those provided by service layer 713, provide reusable, defined business functions through defined interfaces. For example, the interface may be software written in JAVA, C++, or other suitable languages, providing data in Extensible Markup Language (XML) format or other suitable formats. Although shown as an integrated component of computer 702, alternative implementations may show API 712 or service layer 713 as a separate component relative to or communicatively coupled to other components of computer 702 (whether shown or not). Furthermore, any or all portions of API 712 or service layer 713 may be implemented as a submodule of another software module, enterprise application, or hardware module without departing from the scope of this disclosure.

[0059] Computer 702 includes interface 704. Although in Figure 7While shown as a single interface 704, two or more interfaces 704 may be used depending on the specific needs, expectations, or implementation of computer 702. Interface 704 is used by computer 702 to communicate with other systems in a distributed environment connected to network 730. Typically, interface 704 includes logic encoded in software or hardware (or a combination of software and hardware) and operable to communicate with network 730. More specifically, interface 704 may include software supporting one or more communication protocols associated with the communication, enabling network 730 or the hardware of the interface to transmit physical signals both inside and outside the illustrated computer 702.

[0060] Computer 702 includes at least one computer processor 705. Although in Figure 7 The computer 702 is shown as a single computer processor 705, but two or more processors may be used depending on the specific needs, expectations, or particular implementation of the computer 702. Generally, the computer processor 705 executes instructions and manipulates data to perform the operations of the computer 702 and any algorithms, methods, functions, processes, flows, and procedures as described in this disclosure.

[0061] Computer 702 also includes memory 706, which stores data for computer 702 or other components (or a combination of both) that can be connected to network 730. For example, memory 706 may be a database storing data consistent with this disclosure. Although in Figure 7 The memory 706 is shown as a single memory 706, but two or more memories may be used depending on the specific needs, expectations, or specific implementation of the computer 702 and the described functions. Although the memory 706 is shown as an integrated component of the computer 702, in alternative implementations, the memory 706 may be external to the computer 702.

[0062] Application 707 is an algorithmic software engine that provides functionality according to the specific needs, expectations, or particular implementations of computer 702, particularly with respect to the functionality described in this invention. For example, application 707 can function as one or more components, modules, applications, etc. Furthermore, although shown as a single application 707, application 707 can be implemented as multiple applications 707 on computer 702. Moreover, although shown as integrated with computer 702, in alternative implementations, application 707 can be external to computer 702.

[0063] Any number of computers 702 may exist, either associated with or outside the computer system containing computer 702, wherein each computer 702 communicates via network 730. Furthermore, the terms "client," "user," and other suitable terms may be used interchangeably without departing from the scope of this disclosure. Moreover, this disclosure contemplates that a number of users may use one computer 702, or that one user may use multiple computers 702.

[0064] Although only a few exemplary embodiments have been described in detail above, those skilled in the art will readily understand that many modifications can be made to the exemplary embodiments without substantially departing from the invention. Therefore, all such modifications are intended to be included within the scope of this disclosure as defined by the appended claims. In the claims, any device-plus-function clause is intended to cover structures described herein as performing said functions and equivalents of those structures. Similarly, any functional limitation in the claims is intended to cover actions described herein as performing said functions and equivalents of those actions. The applicant expressly disclaims all claims herein from any limitation of 35 U.S.SC §112(f) unless the claims expressly use the terms “means for…” or “steps for…” and the associated functions.

Claims

1. A method for detecting gas based on seismic property maps, comprising: Seismic bodies with relative amplitude preservation for the subsurface region of interest are obtained by a computer processor in the time domain; The computer processor transforms the seismic volume, which retains the relative amplitude acquired in the time domain, into a low-frequency monospectral amplitude volume; The computer processor determines the seismic attenuator based on the seismic volume with the relative amplitude preserved in the time domain; The computer processor generates a low-frequency monospectral amplitude map of the surface of interest by averaging the low-frequency monospectral amplitude over a depth window around the surface of interest. The computer processor generates a seismic attenuation map of the surface of interest by averaging the seismic attenuation volume over a depth window around the surface of interest. The property map is determined by the computer processor based at least in part on the seismic attenuation map of the surface of interest and the low-frequency monospectral amplitude map of the surface of interest; as well as The computer processor determines the presence of gas in the subsurface region of interest based at least in part on the property map. The computed property graph also includes: Calculate the ratio of the value of at least one pixel in the seismic attenuation map of the surface of interest to the value of at least one pixel in the low-frequency monospectral amplitude map of the surface of interest; Calculate the ratio of the value of at least one pixel in the low-frequency monospectral amplitude map of the surface of interest to the value of at least one pixel in the seismic attenuation map of the surface of interest; and Calculate the difference between the value of at least one pixel in the seismic attenuation map of the surface of interest and the value of at least one pixel in the low-frequency monospectral amplitude map of the surface of interest.

2. The method according to claim 1, further comprising: The computer processor uses the property map to determine well paths through the subsurface region of interest; as well as The well path is executed using a drilling system.

3. The method according to claim 1: in, The seismic bodies with preserved relative amplitudes obtained in the time domain are selected from the group consisting of post-stack time-migration bodies, post-stack depth-migration bodies, pre-stack time-migration bodies, and pre-stack depth-migration bodies; and The seismic attenuator can be selected from the group consisting of an effective attenuator, an inherent attenuator, and an instantaneous attenuator.

4. The method according to claim 1: in, Transforming the seismic body with preserved relative amplitudes obtained in the time domain into a low-frequency monospectral amplitude body also includes: The filter is applied to the low-frequency monospectral amplitude body.

5. The method according to claim 4: in, The filter can be selected from the group consisting of spatial smoothing filters, tilt-guided filters, structure-oriented filters, deterministic filters, and statistical filters.

6. The method according to claim 1: in, The process of transforming the seismic volume with preserved relative amplitudes obtained in the time domain into a seismic attenuation volume also includes: A filter is applied to the earthquake attenuator.

7. The method according to claim 6: in, The filter can be selected from the group consisting of spatial smoothing filters, tilt-guided filters, structure-oriented filters, deterministic filters, and statistical filters.

8. A system for detecting gas based on seismic property maps, comprising: An earthquake processor includes a computer processing unit capable of executing instructions stored in a non-transitory computer storage medium, the instructions causing the earthquake processor to perform functions including: Obtain seismic bodies with relative amplitude preservation for the subsurface region of interest in the time domain; The seismic volume with the relative amplitude preserved in the time domain is transformed into a low-frequency monospectral amplitude volume; The seismic attenuation volume is determined from the seismic volume with the relative amplitude preserved in the time domain; A low-frequency monospectral amplitude map of the surface of interest is generated by averaging the low-frequency monospectral amplitude over a depth window around the surface of interest. A seismic attenuation map of the surface of interest is generated by averaging the seismic attenuation volume over a depth window around the surface of interest. The property map is determined at least in part based on the seismic attenuation map of the surface of interest and the low-frequency monospectral amplitude map of the surface of interest; as well as The presence of gas in the subsurface region of interest is determined at least in part based on the property map. The computed property graph also includes: Calculate the ratio of the value of at least one pixel in the seismic attenuation map of the surface of interest to the value of at least one pixel in the low-frequency monospectral amplitude map of the surface of interest; Calculate the ratio of the value of at least one pixel in the low-frequency monospectral amplitude map of the surface of interest to the value of at least one pixel in the seismic attenuation map of the surface of interest; and Calculate the difference between the value of at least one pixel in the seismic attenuation map of the surface of interest and the value of at least one pixel in the low-frequency monospectral amplitude map of the surface of interest.

9. The system according to claim 8: in, The seismic body with the relative amplitude preserved in the time domain is selected from the group consisting of post-stack time-migration bodies, post-stack depth-migration bodies, pre-stack time-migration bodies, and pre-stack depth-migration bodies.

10. The system according to claim 8: in, Converting the relative amplitude-preserving seismic volume obtained in the time domain into a low-frequency monospectral amplitude volume further includes: The filter is applied to the low-frequency monospectral amplitude body.

11. The system according to claim 8: in, Transforming the seismic volume with preserved relative amplitude obtained in the time domain into a seismic attenuation volume further includes: A filter is applied to the earthquake attenuator.

12. The system according to claim 8: in, The seismic attenuator can be selected from the group consisting of an effective attenuator, an inherent attenuator, and an instantaneous attenuator.

13. The system according to claim 8, further comprising: Non-transitory computer storage media used to store one or more locations indicating the presence of a gas.

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