OA17094A - Extracting SV shear data from P-wave marine data. - Google Patents

Extracting SV shear data from P-wave marine data. Download PDF

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OA17094A
OA17094A OA1201400411 OA17094A OA 17094 A OA17094 A OA 17094A OA 1201400411 OA1201400411 OA 1201400411 OA 17094 A OA17094 A OA 17094A
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data
offset
wave
seismic
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OA1201400411
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Bob A HARDAGE
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Board Of Regents Of The University Of Texas System
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Abstract

A system and method of processing seismic data obtained using a plurality of towed singlecomponent receivers in a marine environment is described, the towed single-component receivers configured to measure compressional P waves. The method comprises retrieving seismic data from a storage device, the seismic data comprising P-P data and shear mode data, wherein the P-P data and shear mode data were both received at the towed single-component receivers configured to measure compressional P waves to generate the seismic data. The method further comprises processing the seismic data to extract SV-P shear mode data and generating shear mode image data based on the extracted shear mode data.

Description

Extracting SV Shear Data from P-Wave Marine Data
CROSS REFERENCE TO RELATED APPLICATIONS
This application claims the benefit of and priority to U.S. Application No. 13/413,562, filed on March 6,2012, which claims the benefit of and priority to U.S. Application No. 13/287,746, filed November 2,2011, which claims the benefit of and priority to U.S. Application No. 13/217,064, filed August 24, 2011, which claims the benefit of and priority to U.S. Application No. 12/870,601, filed August 27, 2010, ail of which are incorporated herein by reference In their entireties.
BACKGROUND
The present application relates generally to Systems and methods for seismic exploration, including the acquisition and/or processing of seismic data to estimate properties of the Earth's subsurface.
The principal type of data used to explore for oil and gas resources Is seismic reflection data that image subsurface geology. There are three seismic wave modes that can be used for subsurface imaging - a compressional-wave (P) mode and two shear-wave modes (SV and SH). When geophysicists acquire seismic data that hâve ali three of these modes, the data are cailed full eiastic-wavefield data. Full elastic-wavefieid data are acquired by deploying three separate orthogonal seismic sources at every source station across a prospect area. One source applies a vertical force vector to the Earth, a second source applies a horizontal force vector in the inline (X) direction, and a third source applies a second horizontal force vector in the crossline (Y) direction.
The wavefieids produced by each of these three orthogonal-force sources are recorded by 3component geophones that hâve orthogonal (XYZ) sensing éléments. The resulting data are cailed 9-component data because they consist of 3-component data produced by three different sources that occupy the same source station in sequence, not simultaneously. Full descriptions and illustrations of the sources, sensors, and field procedures used to acquire full eiastic-wavefield data can be found in Chapter 2, Multicomponent Seismic Technology, Geophysical References Sériés No. 18, Society of Exploration Geophysicists, authored by B.A. Hardage, Μ. V. DeAngelo, P. E. Murray, and D. Sava (2011 ). Vertical, single-component, surface-based geophones are used for the purpose of acquiring P-wave seismic data
Marine seismic data are generated by an air gun source (e.g., an air gun array) towed a few meters (e.g., 3 to 15 m) beiow the sea surface. Data are recorded by a long cable (e.g., as long as 10 or 15 km) that has hydrophones spaced at Intervals of a few meters (e.g., 10 to 20 m). Several of these hydrophone cables can be towed by the same boat that tows the air guns, or the source and the hydrophone cables can be towed by separate boats. Sometimes there are two cable boats moving along parallel tracks, maybe 6 or 8 km apart, and each towing 10 or more cables as long as 15 km that span a latéral distance of 1 to 2 km. In these modem long-offset, multi-azïmuth marine surveys, there are 2 to 4 source boats stationed around the cable boats. The whole procedure involves a small armada moving at a slow speed with each boat performing its assignment with précisé GPS positioning and atomic-clock timing. The amount of data recorded across a large survey area can be staggering.
Water has a shear modulus of zéro, thus S waves cannot propagate in sea water. Because a marine source and receiver are In a water layer, marine seismic data are considered to be only Pwave data.
SUMMARY
A System and method of processing seismic data obtained using a towed receiver in a marine environment Is described, the towed receiver configured to measure compressional P waves. The method comprises retrieving seismic data from a storage device, the seismic data comprising P-P data and shear mode data, wherein the P-P data and shear mode data were both received at the towed receiver configured to measure compressional P waves to generate the seismic data. The method further comprises processing the seismic data to extract SV-P shear mode data and generating shear mode image data based on the extracted shear mode data..
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a diagram illustrating a fuli-eiastic, multicomponent seismic wavefield propagating in a homogeneous Earth, according to an exemplary embodiment.
FIG. 2 is a diagram showing SH and SV shear wave displacements, according to an exemplary embodiment.
FIG. 3 Is a map view of SH and SV illumination patterns for orthogonal (X and Y) horizontaldisplacement sources.
FIG. 4 is a comparison of SH, SV and P velocity behavior for elastic wave propagation in horizontally layered media.
FIG. 5 is a cross-sedional view of a theoretical calculation of P and SV radiation patterns produced when a vertical force F is applied to the surface of the Earth, shown for two different values of the Poisson's ratio of the Earth layer, according to an exemplary embodiment.
FIGs. 6Aand 6B show an S-wave radiation pattern from FIG. 5 displayed as a 3D object, according to an exemplary embodiment.
FIG. 7A îs a chart of VSP data acquired using a vertical-displacement source, according to an exemplary embodiment.
FIG. 7B is a chart of VSP data acquired using a vertical-displacement source, according to an exemplary embodiment.
FIG. 8 is a diagram showing a source-receiver geometry used to analyze P and S radiation patterns emitted by seismic sources, according to an exemplary embodiment.
FIG. 9 is a diagram illustratîng takeoff angle apertures, according to an exemplary embodiment.
FIG. 10 is a diagram illustratîng transformation of X, Y, Z receivers to P, SV, SH receivers, according to an exemplary embodiment.
io FIG. 11 is a set of charts showing example X, Y, Z data acquired with a vertical array from a vertical-lmpact source, and corresponding data rotated to P, SV and SH data space, according to an exemplary embodiment.
FIG. 12 îs a set of charts showing example X, Y, 2 data acquired with a vertical array from a shot hole explosive source, and corresponding data rotated to P, SV and SH data space, according to is an exemplary embodiment.
FIG. 13 Is a set of charts showing example X, Y, Z data acquired with a vertical array from a vertical vibrator source, and corresponding data rotated to P, SV and SH data space, according to an exemplary embodiment.
FIG. 14 is an illustration of the principle of data-pofarity reversais applied to vertical-force source data to create constant-polarity S-wave data across seismic image space, according to an exemplary embodiment.
FIG. 15 illustrâtes a first example of polarities of vertical-force seismic data and the resuit of reversing polarities ln the negative-polarity domain to convert vertical-force source data to constantpolarity dipole-source data, according to an exemplary embodiment.
FIG. 16 illustrâtes a second example of polarities of vertical-force seismic data and the resuit of reversing polarities In the negative-polarity domain to convert vertical-force source data to constantpolarity dipole-source data, according to an exemplary embodiment.
FIG. 17 Is a block diagram of a data acquisition and processing system and method for acquiring and processing full elastic waveform data from a vertical-force source using surface-based sensors, so according to an exemplary embodiment.
FIG. 18 ls a block diagram of a data acquisition and processing System and method for acquiring and processing full elastic waveform data firom a vertical-force source using sub-surface sensors, according to an exemplary embodiment.
FIG. 19 ls a block diagram of a data processing System for processing full elastic wavefield data, 5 according to an exemplary embodiment.
FIG. 20 is a flow diagram illustrating a method of processing full elastic wave data, according to an exemplary embodiment.
FIG. 21 ls a raypath diagram illustrating a comparison of P-P and SV-P Imaging of subsurface geology, according to an exemplary embodiment.
io FIG. 22 ls a raypath diagram illustrating an approach direction of upgoing P-P and SV-P raypaths at a receiver station when the top Earth layer is low-velocity unconsolidated sédiment, according to exemplary embodiment.
FIG. 23 is a raypath diagram showing principies of SV-SV and SV-P imaging, according to an exemplary embodiment.
FIG. 24 ls a raypath diagram showing approach direction of upgoing P and SV raypaths at a receiver stations when the top Earth layer is high-velodty rock, according to an exemplary embodiment.
FIG. 25 is a raypath diagram illustrating a comparison of P-SV and SV-P raypaths, according to an exemplary embodiment.
FIGs. 26A and 26B are diagrams illustrating size and position of SV-P image space for two 3D Pwave data-acquisition géométries, according to an exemplary embodiment.
FIG. 27 is a diagram of a subsurface geology illustrating positive-offset and negative-offset domains for SV-P data and Faciès A and B causing different velocitîes, according to an exemplary embodiment.
FIGs. 28A and 28B are examples of SV-P primary and multiple reflections extracted from vertical-geophone P-wave seismic data, according to an exemplary embodiment.
FIG. 29 ls a diagram illustrating SV-P and P-SV CCP imaging principies, according to an exemplary embodiment.
FIG. 30 is a diagram and table illustrating prestack migration, according to an exemplary embodiment.
FIG. 31 Is a tabulation of some similarities and différences between SV-P and P-SV data, according to an exemplary embodiment.
FIG. 32 Is a block diagram of a data processing System for processing shear wave data from a vertical sensor, according to an exemplary embodiment.
FIG. 33 Is a block diagram of a data acquisition and processing System and method for acquiring and processing shear wave data from a vertlcal-force source using surface-based sensors, according to an exemplary embodiment.
FIG. 34 is a flow diagram Illustrating a method of processing shear wave data from a vertical receiver in a situation involvlng a low-veloclty Earth surface, according to an exemplary embodiment.
FIG. 35 is a flow diagram Illustrating a method of processing shear wave data from a vertical receiver In a situation invoiving a high-velocity Earth surface, according to an exemplary embodiment.
FIG. 36 is a diagram of approach angles of P waves to a vertical geophone, according to an exemplary embodiment.
FIG. 37 is a diagram of approach angles of SV waves to a vertical geophone, according to an exemplary embodiment.
FIG. 38 is a schematic diagram of equipment used In marine seismic data acquisition and raypaths of seismic modes, according to an exemplary embodiment.
FIG. 39 Is a schematic diagram illustrating raypaths associated with a virtual seafloor source and a virtual seafloor receiver, according to an exemplary embodiment.
FIG. 40 Is a diagram of a subsurface geology Illustrating positive-offset and negative-offset domains for SV-P data and Faciès A and B causing different velodties, according to an exemplary embodiment.
FIG. 41 is a diagram illustrating (a) positive-offset marine data, (b) negative-offset marine data, and (c) a combination of positive-offset and negative-offset marine data, according to an exemplary embodiment.
FIG. 42 illustrâtes SV-P and P-SV CCP imaging prindples, according to an exemplary embodiment.
FIG. 43 illustrâtes a time-space distribution of velodties for each spedfic seismic mode, according to an exemplary embodiment.
FIG. 44 is an exemplary calculation used in prestack time migration of seismic data, according to an exemplary embodiment.
FIG. 45 Is a flow diagram iliustrating a process of prestack time migration, according to an exemplary embodiment.
FIG. 46 is a flowchart iliustrating a system and method for processing marine SV-P data, according to an exemplary embodiment.
FIG. 47 is a system diagram iliustrating a system for acquisition and processing of marine SV-P data, according to an exemplary embodiment.
DETAILED DESCRIPTION OF EXEMPLARY EMBODIMENTS io One or more embodiments described herein may provide a method by which full elasticwavefield seismic data (P, SV and SH modes) can be acquîred and processed using only one source, a vertical-force source. The embodiments may be simpler and lower-cost than using three orthogonal-force sources. The embodiments may be used in oil and gas exploration and exploitation, or any other activity where seismic reflection data are widely used. The embodiments may remove numerous technical, environmentai, and cost barrière that limit applications of full elastic-wavefield seismic data.
One or more embodiments described herein may involve departures from conventîonal seismic data processing strategy.
One or more embodiments described herein may reduce the cost of acquiring complété elastic20 wavefield seismic data. The daiiy rate for utilizlng a single vertical-force source is less than the rates of deploying both a vertical-force source and a horizontal-force source to acquire équivalent data. Further, data may be acquîred qulcker by deploying a single source at each source station to create full elastic-wavefield data rather than deploying a vertical-force source and a horizontal-force source. The longer a contracter Works to acquire data, the greater the cost of the data.
One or more embodiments described herein may provide the ability to acquire elastic-wavefield seismic data across a wider range of surface conditions, such as swamps, marshes, rugged mountain terrain, dense timber, and agricultural régions. Vertical-force sources can operate In a wide variety of surface terrains. For example, shot hole explosives can be used in swamps, marshes, heavy timber, or rugged mountains, ait of which are places horizontal sources cannot be deployed at ail, or at great cost because of site préparations. Vertical vibra tors can be deployed in high-culture and residentiai areas without causing physical damage to buildings and infra-structure.
One or more embodiments described herein may provide a wider choice of seismic sources. There is a limited choice of horizontal-force seismic sources - such as heavy, horizontal vibrators or Inclined-lmpact sources. The total number of horizontal vibrators across the worid Is small. The number of inclined-impact sources is less. More of each type of source could be manufactured if demand appears. In contrast, there are hundreds of vertical-force sources. The dominating classes of vertical-force sources are vertical vibrators (hundreds around the worid) and shot hole explosives (available anywhere). Vertical-impact sources are few, but they too can be manufactured In mass if a market Is created. For vertical seismic profile (VSP) data acquisition In remote areas (for example équatorial Jungles), an air gun fired in a mud pit would be a vertical-force source. One or more embodiments described herein may allow geoscientists to select from a large menu of vertical-force sources: vertical vibrators, shot-hoie explosives, vertical-impactors, or mud pit air guns.
Wave Components
Referring to FIG. 1, a full-elastic, multicomponent seismic wavefield propagating In a simple homogenous Earth is Illustrated. Three independent, vector-based, seismic wave modes propagate in the Earth: a compressional mode, P, and two shear modes, SV and SH (Fig. 1). Each mode travels through the Earth at a different velocity, and each mode distorts the Earth In a different direction as it propagates. Double-headed arrows 102 are particle-displacement vectors indicating the direction in which each mode dispiaces the Earth. Arrows 104 ilîustrate a direction of wave propagation. Acquisition ofthe multicomponent modes results In full elastic-wavefield data. The orientations of the P, SV, and SH displacement vectors relative to the propagation direction of each mode are illustrated in Figure 1.
The propagation velocities of the SH and SV shear modes may differ by only a few percent, but both shear velocities (Vs) are significantly less than the P-wave velocity (Vp). The velocity ratio Vp/Vs can vary by an order of magnitude in Earth media, from a value of 50 or more In deep-water, unconsolidated, near-seafloor sédiment to a value of 1.5 in a few dense, well-consolidated rocks.
Referring to FIG. 2, an exemplary distinction between SH and SV shear modes is illustrated. SH and SV shear modes may be distinguished by imagining a vertical plane passing through a source station A and a receiver station B. SV vector displacement occurs in this vertical plane, as indicated at arrow 202; SH vector displacement Is normal to the plane, as Indicated at arrow 204. This vertical plane passing through the coordinates of a source station A, a receiver station B, and a reflection point C or D produced by that source-receiver pair may be called a sagittal plane or propagation plane.
Horlzontal-Force Sources and SH/SV Illumination
Referring to FIG. 3, a map view of theoretlcal SH and SV radiation patterns produced by orthogonal horizontal-displacement sources 302, 304 will be described. Mathematical expressions that describe the geometrical shape of P, SV, and SH radiation patterns produced by seismic 5 sources In an Isotropie Earth are described by White (1983). Viewed from directly above the horizontal-displacement source, SV and SH modes propagate away from the source stations 302, 304 as expanding drcles or ellipses. To simplïfy the graphie description, the patterns will be shown as drcles. Because SV radiation from a horizontal-displacement source 302, 304 is usually more energetic than SH radiation, SV radiation drcles are drawn iarger than SH radiation drcles. These io cirdes indicate which parts of the Image space each mode affects and the magnitude of the mode illumination that reaches each Image coordinate. The relative slzes of these cirdes are qualitative and are not intended to be accurate in a quantitative sense.
A horizontal source-displacement vector 306 oriented in the Y direction (left side of figure) causes SV modes to radïate In the +Y and -Y directions and SH modes to propagate in the +X and 15 -X directions. A horizontal source-displacement vector 310 oriented In the X direction (right side of figure) causes SV modes to radiate In the +X and -X directions and SH modes to propagate in the +Y and -Y directions. If a line Is drawn from the source station 302,304 to Intersect one of these radiation drcles, the distance to the Intersection point indicates the magnitude of that particular mode displacement in the azimuth direction of that line. The orientation of the partide20 displacement vectors 308 and 312 remains constant across the Image space, but the magnitude of the SH and SV partide-dispiacement vectors vary with azimuth as shown by the SH and SV radiation drcles on FIG. 3.
Referring to FIG. 4, velodty behavior of SH and SV modes propagating through a iayered Earth hâve been described by Levin, F., 1979, Seismic velodties in transversely isotropie media I:
Geophyslcs, 44, 918-936 and Levin, F., 1980, Seismic velodties In transversely isotropie media II;
Geophysics, 45, 3-17. The Iayered Earth Is horizontally Iayered, vertical transverse isotropie (VTI) media. Note that at ail take-off angles (except angle 402) SV and SH propagate with different velodties, with SH having a significantly faster velodty at shallow take-off angles (such as angle 404) from a source station 406. This wave physics will be useful when examining seismic test data 30 described iater.
Vertlcal-Force Sources and Dlrect-S Illumination
One type of source used in onshore seismic data acquisition applies a vertical displacement force to the Earth. Among these vertical-force sources are vertical weight droppers and thumpers, explosives ln a shot hole, and vertical vibrators. Such sources are traditionally viewed as only Pwave sources, but they also produce robust S wavefields,
Referring to FIG. 5, an Illustration of a theoretical calculation, in cross-sectional views, is presented to illustrate how energy is distributed between P-wave and SV-shear mode radiation patterns when a vertical force is applied to an elastic half-space 502 from a vertical force source or vertical displacement source. See Miller, G., and H. Pursey, 1954, The field and radiation impédance of mechanical radiators on the free surface of a semi-infinite isotropie solid: Proc. Royal Soc. London, Sériés A, v. 223, p. 521-541 and White, J. E., 1983, Underground sound— applications of seismic waves: Elsevier Science Publishers. Calculations are shown for two different values of the Poisson's ratio of the Earth layer, with the first image 500 representing a Poisson's ratio of 0.44 and the second image 502 representing a Poisson's ratio of 0.33. This analysis focuses only on body waves and ignores horizontally traveling energy along the Earth-air interface. The semi-circles indicate the relative strength of the radiation. Radial lines define the take-off angle relative to vertical, ln each model, more SV energy is generated than P energy.
The calculation of FIG. 5 shows that a vertical-force source 504 produces more SV energy 506 than P energy 508, and that at take-off angles of 20-degrees and more this direct-SV mode is significantly stronger than the P mode. This particular SV radiation may not resuit in a robust illumination of geology directly below the source station; whereas, its companion P radiation does. ln order to take advantage of the direct-SV mode produced by vertical displacement onshore sources, two features can be implemented in data acquisition Systems. First, three component (3C) geophones are used rather than single-component geophones. Second, longer recording times are used to accommodate the slower propagation velocity of the downgoing and upgoing direct-SV mode. For example, P-wave recording times of four seconds to six seconds may be extended to at least eight seconds or at least 12 seconds. Recording times for large offsets between source and receiver may be at least three times or at least four times the vertical travel time to the deepest target of interest. Modem seismic data acquisition Systems can accommodate the long data-acquisition times required to image deep targets at far-offset receiver stations. A processing circuit within the data acquisition system may be configured to control the geophones or other receivers or sensors to listen or record received seismic data for at least a minimum recording time.
A definitive way to illustrate the P and direct-SV radiation produced by a vertlcal-displacement source Is to analyze its downgoing wavefield using vertical seismic profile (VSP) data. One example of VSP data acquired ln the Delaware Basin of New Mexico with a vertical vibrator used as a source is provided as FIG. 7A. The downgoing mode labeled SV is not a tube wave because it propagates with a velocity of approximately 2400 m/s (8000 ft/s), which is almost twice the velocity of a fluid-bome tube wave. The downgoing P and SV illuminating wavelets produced Immediately at the point where this vibrator applies a vertical force to the Earth surface are labeled and extended back to the surface source station 700 to illustrate that an SV mode is produced directly at the source. The absence of data coverage a cross the shallowest 3000 ft of strata leaves some doubt as to where downgoing event SV is created, so a second example of VSP data produced by a vertical vibrator In a South Texas well is illustrated on FIG. 7B. Again this verticaldisplacement source créâtes a robust direct-SV wavefield in addition to the customary P wavefield. In this example, the downgoing SV mode can be extended back to the source station at the Earth surface with confidence. In the case of FIG. 7B, the source was offset only 100 ft from the VSP well. The top diagram shows a vertical geophone response. The bottom diagram shows the response of a horizontal geophone.
The VSP data examples of FIGs. 7A and 7B show that a vertical vibrator Is an efficient producer of direct-SV radiation and créâtes an SV-SV mode that can be utilized. An explosive shot also applies a vertical-displacement force to the Earth and generates a direct-SV mode.
The SV mode exhibited by the data in FIGS. 7A and 7B Is produced at the same Earth coordinate as the P mode and is a source-generated direct-SV wave. The propagation medium at this location has unusually low VP and Vs velocities. The SV mode produces a large population of upgoing SV reflections that are observable In these raw, unprocessed data.
The term ‘SV is used above to describe the S-wave radiation. However, as will be seen below, the term “SV should be replaced with the broader term ’S, meaning the radiated S-wave energy is both SV and SH when the radiation Is considered In a 3D context rather than as a single vertical profile.
To illustrate the principle that S-wave radiation produced by a vertical-force source consiste of both SV and SH modes, the pattern displayed on the right of FIG. 5 is converted to a 3D object and displayed as FIGS. 6A and 6B. For ease of understanding, the 3D radiation pattern is simplified to contaln only the major S lobe 512, 514 shown in FIG. 5. Both the P-wave component 516 and the smaller secondary S lobe 518 seen on FIG. 5 are omitted. The solid Is fùrther altered by removing a 90-degree section 602 to allow better viewing of the 3D geometry by which S energy spreads away from the vertical-force source station VFS.
In FIG. 6A, SV and SH planes and displacement vectors are shown relative to a receiverstation Ra. In FIG. 6B, SV and SH planes and displacement vectors are drawn relative to a receiver station RB. These two arbitrary receiver stations RAand RB, separated by an azimuth of 90 degrees, are positioned on the Earth surface around a station VFS where a vertical-force source is deployed. Oblique views and map views are shown of a vertical plane passtng through the source station and each receiver station. As discussed for FIG. 2, this source-receiver plane is the SV plane for each receiver station. For each receiver, an SH plane is also shown perpendicular to each SV plane. The SH plane for receiver RA is the SV plane for receiver RB, and inversely, the SH plane for receiver RB Is the SV plane for receiver RA. Regardless of where a receiver station is positioned In azimuth space away from a vertical-force station, both SV and SH modes will propagate to that station. SH shear information is availabie as Is SV shear information when vertical-force source data are acquired.
Field Test
The Exploration Geophysics Laboratory (EGL) at the Bureau of Economie Geology Initiated a field-test program to quantify the geometrical shapes and relative strengths of compressional (P)wave and shear (S)-wave modes produced by a variety of seismic sources. The first test program was done at the Devine Test Site owned by The University of Texas at Austin and managed by EGL researchers. Sources deployed for this Initial test were: 1-kg package of explosive positioned at a depth of 20 ft, a horizontal vibrator, a vertical vibrator, and an accelerated-weight that Impacted the Earth vertically and at inclined angles.
Source-Recelver Geometry
Referring to FIG. 8, an Illustration of the source-receiver geometry is shown. The sourcereceiver geometry used to evaluate P and S source radiation patterns combined the concepts of horizontal wave testing (involving only a horizontal receiver array) and vertical wave testing (involving only a vertical receiver array) as described by Hardage, B A, 2009, Horizontal wave testing: AAPG Explorer, v. 30, no. 12, p. 26-27 and Hardage, B.A. 2010, Vertical wave testing: AAPG Explorer, v. 31, no. 1, p. 32-33. A 24-station vertical array of three-component geophones was deployed in a selected test well, with receiver stations spanning a depth interval extending from 500 to 1632 ft (Fig. 8). Three-component (3C) geophones are configured to acquire ail three dimensions of a full elastic wave. Several 25-station horizontal arrays of 3C sensors spaced 10 ft apart spanned the offset range 0 to 250 ft immediately next to the receiver well. Source stations were offset from the well at intervais of 250 ft, the iinear dimension of the horizontal surfacereceiver arrays.
Vertical Aperture
Referring to FIG. 9, an approximation of the aperture range created by the source-receiver geometry Is shown. Downgoing P and S modes were recorded over a wide aperture of vertical takeoff angles (14 degrees to 81 degrees in this example) from the surface source stations to define the geometricai shape of P and S radiation patterns In section view. The shallowest takeoff angle Involved data generated at source station 9 (offset 1920 ft) and recorded at downhole receiver station 24 (depth of 500 ft). The steepest takeoff angle involved source station 2 (offset s 250 ft) and downhole receiver station 1 (depth of 1632 ft). A first approximation of the aperture range created by the source-receiver geometry can be created by assuming straight raypaths from source to downhole receiver, which yields the resuit shown in FIG. 9. in actual wave propagation, raypaths are curved as dictated by refractions at interfaces between velodty layers. Raypaths refrad (bend) when they advance from an Earth layer having velodty V1 Into a layer having velodty 10 V2. Raypath curvature can be calculated if velodty layering is known. Straight raypath assumptions are used to explain the prindples described with référencé to FIG. 9.
Transformlng VSP Data to Wave-Mode Data
In a vertical well, azimuth orientations of X,Y horizontal geophones deployed by twisted-wire cable differ at each downhole station because of receiver-module spin. As a resuit, phase shifts 15 and amplitude variations Introduced into data by station-to-station variations in receiver orientation do not allow individual events or distinct wave modes to be recognized, particulariy S-wave events that tend to domlnate horizontal-sensor responses. In this case, receivers are mathematically oriented to spécifie azimuths and inclinations to define downgoing and upgolng P and S modes.
Referring to FIG. 10, a graphical description of the transformation of receivers from X, Y, Z data m space to P, SV, SH data space is shown. Transformations of borehole receivers from In situ X, Y,
Z orientations to a data space where receivers are oriented to emphaslze P, SV, and SH events hâve been practiced in vertical seismic profiling (VSP) technology. DiSlena, J.P., Gaiser, J.E., and Corrigan, D., 1981, Three-component vertical seismic profiles - orientation of horizontal components for shear wave analysis: Tech. Paper S5.4, p. 1990-2011, 51” Annual Meeting of
Society of Exploration Geophysicists. Hardage, B.A., 1983, Vertical seismic profiling, Part A, prindples: Geophysical Press, 450 pages (The VSP Polarization Method for Locating Reflectors, pages 307 - 315). Examples of this receiver orientation procedure applied to vertical-impact, shothole explosive, and vertical-vibrator sources at selected source stations are illustrated on FiGs. 11, 12, and 13, respectively. Data Windows spanning 100 ms immediately following the onset of interpreted P-wave direct arrivais were used to détermine azimuth and inclination angles Θ and Φ (FIG. 10) at each receiver station
Figure 10 illustrâtes a 2-step rotation of coordinate axes to détermine directional angles from a subsurface receiver to a surface-positioned seismic source. When a 3-component sensor is lowered severai hundreds of feet down a well, the azimuth orientations of horizontal sensors are not known because the receïver package rotâtes on the twisted wire cable used for deployment. As a conséquence, P, SH, and SV modes are Intermlngled on each sensor response because sensors are not oriented in the directions of P, SV, and SH particle displacements. Therefore, each subsurface receïver is mathematically oriented so that one sensor points directly along the raypath of the downward traveling P wave from a surface source. Once such rotation is done, the sensor polntlng at the source Is dominated by P data, the second sensor In the same vertical plane as the P sensor (this vertical plane passes through the source and receïver stations) Is dominated by SV, and the third sensor (perpendicuiar to this vertical plane) is dominated by SH. Two angles - a io horizontal rotation angle Θ and a vertical rotation angle Φ - hâve to be determined to achieve this sensor orientation.
To détermine horizontal azimuth angle Θ (Fig. 10), data are analyzed in a short time window spannîng only the downgoing P-wave first arrivai from the source. Only responses of the two horizontal sensors X and Y are analyzed In this first rotation step. Data acquired by sensors X and 15 Y are mathematically transformed to responses that would be observed if these two orthogonal sensors were rotated to new coordinate axes that are successlveiy incremented by one-degree of azimuth. This rotation is done 180 times to create sensor responses that allow the sensor axes to point over an azimuth range of 180 degrees from the unknown azimuth In which the sensors actually point. When sensor X is positîoned in the vertical plane passing through the receïver and 20 the source, the response of the X sensor will be a maximum, and the response of the Y sensor will be a minimum. When this maxlmum-X and minimum-Y response is found, the angle between the In situ sensor axes and the desired rotated axes that isolate P, SV, and SH wave modes is 0.
To détermine inclination angle Φ (Fig. 10), the sensor responses after transforming the data to coordinate axes oriented In azimuth Θ are then analyzed In the short data window spannîng only the 25 downgoing P-wave first arrivai, as defined In this new data-coordinate space. Data from only sensor Z (vertical) and from the new X sensor that has been rotated Into the vertical sourcereceiver plane are used in this second rotation. In this second axis rotation, these two sensor responses are mathematically transformed to responses that would be observed if these two sensors were tilted in successive inclinations of one degree of tilt over a tilt range of 90 degrees.
so When the Z receïver Is polntlng in the direction of the incoming P-wave first arrivai, its response will be a maximum, and the companion sensor In the same vertical plane (the new rotated and tiîted X sensor) response will be a minimum. When this condition Is found, angle Φ has been defined.
Data transformed to this second coordinate system defined by an azimuth rotation of Θ and an inclination angle of Φ hâve optimal séparation of P, SV, and SH modes, with P, SV, and SH being the dominant data on the rotated and tilted Z, X, and Y sensors, respectively.
Referring to FIG. 11, charts 1100,1102 and 1104 illustrate X, Y, Z data acquired atthe Devine Test Site with the vertical receiver array when a vertical-impact source was positioned at source station 9, offset 1920 fl from the receiver array. Charts 1106,1108 and 1110 illustrate the same data rotated to P, SV, SH data space. No P or SV events appear on the SH data panel. Because SH displacement is orthogonal to both P and SV displacements, the absence of P and SV events defines SH data. SV events appearing on the P data panel such as the event shown at 1112 are downgoing P-to-SV conversions. Downgoing P-to-SV conversions are caused only by non-normal incidence of a P wave on an impédance contrast interface. P and SV modes exchange energy freely when reflecting and refracting at interfaces because the displacement vectors of these two modes are in the same vertical plane. Neither P nor SV can convert energy to SH, and conversely SH can not convert into P or SV, because SH displacement is orthogonal to the vertical plane in which P and SV propagate. To confirm that a data panel is an SH mode, we search for evidence of P and SV events embedded in the data panel. If no P or SV events can be identlfied, the mode is pure SH, by définition. Note at shallow take-off angles (top 4 or 5 receiver stations), SH waves travel faster than SV waves as predicted by Levin (1979,1980), supra, and measured by Robertson, J.D. and D. Corrigan, 1983, Radiation patterns of a shear-wave vibrator in near-surface shale: Geophysics, 48,19-26.
SV waves produced directly at the source means SV waves are generated exactly at the point where a vertical force is applied to the Earth. There does not hâve to be an impedance-contrast interface close to the source to cause SV to corne into existence. SV will propagate away from a vertical-force source even in a thlck, homogeneous medium In which there are no interfaces.
In contrast, P-to-SV conversions occur only at Interfaces where there is an impédance contrast. Any time a P-wave arrives at an interface at any incident angle other than 0 degrees (normal to the interface), some of the iüuminating P energy converts into reflected and refracted P, and some converts Into reflected and refracted SV. Thus P-to-SV conversion occurs at interface coordinates remote from a source, not directly at the source point. A converted SV mode requires two conditions be présent: 1) an interface across which there is a contrast in acoustic impédance, and 2) a P-wave raypath arriving at that interface at an angle that is not normal to the interface. When the incident angle is 0 degrees (raypath perpendicular to the interface), the P-to-SV reflection coefficient is zéro. At other incident angles, the P-SV reflection coefficient is non-zero.
Referring to FIG. 12, charts 1200,1202 and 1204 lllustrate actuai X, Y, Z data acquired at the Devine Test Site with the vertical receiver array when a shot-hole explosive source was positioned at source station 5, offset 1250 ft from the array. Charts 1206,1208 and 1210 lllustrate the same data rotated to P, SV, SH data space. No P or SV events appear on the SH data panel. SV events appearing on the P data panel are weaker than Is the case fora vertical-impact source, perhaps due to more accurate receiver rotations. Note at shallow take-off angles (top 4 or 5 receiver stations), SH waves travel faster than SV waves as predicted by Levin (1979,1980), supra, and measured by Roberson and Corrigan (1983), supra.
Referring to FIG. 13, charts 1300,1302 and 1304 lllustrate actuai X, Y, Z data acquired at the Devine Test Site with the vertical receiver array when a vertical-vibrator source was positioned at source station 6, offset 1500 ft from the array. Charts 1206,1208 and 1210 lllustrate the same data rotated to P, SV, SH data space. No P or SV events appear on the SH data panel. Measurements made at shallow take-off angles hâve larger amplitudes than measurements made with vertical-impact and explosive sources (FIGs. 11 and 12).
A constant plot gain is applied to each data panel on each of FIGs. 11-13. Thus, within individual figures, P, SV, and SH amplitudes can be compared visually to judge relative energy levels of P and S modes. Such comparisons confirm SV and SH modes radiating away from a vertical-force source hâve amplitudes greater than the associated P mode. Data-display gains differ for each source, so P and S amplitudes produced by explosives should not be visually compared with P and S amplitudes produced by vertical-impact or vertical-vibrator sources.
According to theory, SH data do not convert to either P or SV modes as an elastic wavefield propagates through a layered Earth, and conversely, P and SV modes do not convert to SH modes. No SH data panel contains P or SV events, which indicate the wavefield séparations displayed on FIGs. 11 through 13 are properly done. Theory also establishes energy is freely exchanged between P and SV modes as they propagate through layered media. Ail SV data panels on Figures 11-13 show P-to-SV conversion events 1114,1214, and 1314, which agaln Indicate correct wave physlcs. Although minor amounts of SV energy remaln on the P data panels, we consider our wave-mode séparation to be suffidently accurate to establish the fondamental principle that both SH and SV shear modes are produced by a vertical-force source ln addition to the expected P-wave mode.
Another piece of evldence confirmlng the two S modes shown on FIGs. 11 to 13 are SV and SH Is the fact the wavefront labeled SH travels faster at shallow (near horizontal) takeoff angles than does the wavefront labeled SV. This distinction In SH and SV velocity behavior is emphasîzed by the theory documented by Levin (FIG. 4). The différences in SH and SV velocities is best seen by comparing the arrivai times of S wavefronts on FIGs. 11 and 12 at shallow receivers positioned over the depth interval 500 to 700 ft.
Data Processing
There is a différence between S-wave source dispiacement vectors produced by vertical-force sources and conventional horizontai-force sources. The S-wave displacement applied to the Earth by a horizontai-force source is shown on Figure 3. That displacement is oriented In a fixed azimuth direction (e.g., Indicated by arrow 306), and Earth dispiacements around the point of application ail point in the same direction (e.g., as Indicated by arrows 308) as the direction of the applied force. In contrast, the S displacement created by a vertical-force source points in every azimuth direction around Its point of application, and the corresponding Earth displacement vectors likewise point In ail azimuth directions away from the source station (see FIG. 6). The effect seen In seismic reflection data Is that S-wave data produced by a dipole source (FIG. 3) hâve the same polarity in every azimuth quadrant surrounding a source station, but S-wave data produced by a vertical-force source hâve different polarities when viewed in azimuth directions that differ by 180 degrees.
S-wave data-processlng strategies across the seismic industry are based on the assumption that data polarities are constant across the entirety of seismic image space. Thus the polarities of Swave data acquired with a vertical-force source can be adjusted to look like constant-polarity data produced by a dipole source via a data-polarity adjustment.
Referring to FIG. 14, a process of data-polarity adjustment will be described. FIG. 14 shows a map view of a vertical-force source station VFS positioned in a 3D seismic data-acquisition grid 1400. In seismic partance, the direction receiver lines are deployed is called “inline, and the direction source lines are oriented is called crossline. In most 3D seismic data-acquisition designs, inline and crossline directions are perpendicular to each other.
The azimuth direction of positive polarity in crossline and inline directions is arbitrary. However, once a data processor selects certain inline and crossline directions as being positive polarities, he/she has automatically divided inline and crossline seismic image space around a vertical-force source station into two polarity domains - a positive-polarity domain and a negative-polarity domain. FIG. 14 illustrâtes the principle of data-polarity reversais applied to vertical-force source data to croate constant-polarity S-wave data across seismic image space. An exemplary 3D seismic data-acquisition geometry called orthogonal geometry is shown in which source line and receiver lines are orthogonal to each other. VFS is a vertical-force station on one source line. A positive-polarity direction Is selected (arbitrarily) for both the crossline (source line) direction and the înline (receiver line) direction. This decision divides seismic image space into two domains - a positive-polarity domain and a negative-polarity domain.
A real-data example of this data-polarity prindple is illustrated in FIGs. 15 and 16. These 3D seismic data were acquired using a vertical vibrator. The data-acquisition grid is shown between s each pair of data panels to define the position of a flxed source station and various receiver stations where data produced by this vertical-force source were recorded. The positive Infine (IL) and crossline (XL) directions assigned to the grid are indicated at each receiver station. The wiggle trace displays on the left show the polarities of the recorded data. Wiggle trace displays on the right show the data after polarity reversais hâve been applied as described in FIG. 14. After these io polarity flips, ail data hâve consistent polarity across the entirety of seismic image space and can be processed by standard seismic software.
The data processing for SV and SH wave modes produced directly at the point of application of a vertical-force source differs from that of processing converted-SV data. With direct-source data, data polarities are reversed in the negative-offset domain, and once this data-polarity correction is 15 done, data in the two offset domains are processed as a single data set, not as two separate data sets. Direct-source S-wave data can be processed with common-midpoïnt (CMP) strategies; whereas, P-SV data are processed with common-conversion-point (CCP) strategies. Velocity analyses of data are done differently in these two data-processing domains - common midpoint versus common conversion point.
FIG. 15 illustrâtes a first example of polarities of vertical-force seismic data recorded in azimuth directions that differ by 180 degrees away from a source station (left). On the right, FIG. 15 illustrâtes the resuit of reversing polarities In the negative-polarity domain to convert vertical-force source data to constant-polarity dipole-source data.
FiG. 16 illustrâtes a second example of polarities of vertical-force seismic data recorded in 25 azimuth directions that differ by 180 degrees away from a source station (left). On the right, FIG.
illustrâtes the resuit of reversing polarities In the negative-polarity domain to convert verticalforce source data to constant-polarity dipole-source data.
Although vertical-force source data do not produce the same S-wave data polarities as conventional horizontal-force sources, data polarity reversais, corrections, inversions or adjustments in appropriate portions of seismic image space transform vertical-force polarities to horizontal-force polarities. After these polarity adjustments, vertical-force source data can be processed just as horizontal-force source data are, using known algorithms.
Flndlngs
The EGL test data show that vertical-force sources, commonly perceived as P-wave sources, generate more S energy directly at the force application point than they do P energy. ln one embodiment, the S energy Is generated directly at the force application point of the source, rather than through applications of P-to-SV mode conversions at sub-surface interfaces.
in addition, field tests show vertical-force sources produce a high-energy, high-quality SH mode directly at the source station in addition to an SV mode. This statement is confirmed by.
• The mode claimed to be SH produces an Earth displacement normal to the SV mode, and
- Has a velocity greater than the SV mode at shallow takeoff angles.
Thus, the EGL source test program évidences that full-elastic-wavefield data (P, SV, SH) can be acquired using vertical-force sources.
The existence of SV mode data directly at the source station can be contrasted with SV data which Is converted at impedance-contrast interfaces ln the Earth from P to SV mode by some layers of media below the Earth’s surface, which can be referred to as “near the source.* There are only two ways to generate an SV shear mode: 1 ) use a source that produces an SV displacement directly at the source station, or 2) use a source that generates a robust P wave and utîlize the converted SV modes that P wave produces when it illuminâtes an Interface at any incident angle other than 0 degrees.
As expiained above, SH data are observed in data produced by the three general types of vertical-force sources (vertical vibrator, vertical impact, shot hole explosive), which means an SH displacement occurs directly at the point where a vertical-force source applies Its force vector to the Earth.
Data Acquisition and Processing
Referring now to FIG. 17. a diagram of a data acquisition and processing System 1700 and method for acquiring and processing full elastic waveform data from a vertical-force source using surface-based sensors will be described. A vertical-force seismic source 1702 is disposed on, near, or within a shallow recess of the Earth’s surface 1704. Source 1702 is configured to impart a verticai-force to surface 1704 to provide seismic waves into Earth media 1706. Source 1702 may comprise a vertical vibrator, shot-hole explosive, vertical-Impactor, airgun, vertical weight-dropper or thumper, and/or other vertical-force sources. In this example, vertical-force source 1702 produces compressional P mode and both fundamental shear modes (SH and SV) in Earth 1706 directly at a point of application 1708 of the vertical-force source, ln this embodiment, at least some of the SH and SV shear waves are generated at source 1702 and not by subsurface conversion caused by portions of Earth media 1706. The frequency waves may be provided in a frequency sweep or a single broadband Impulse. A vertical-force source may be used without any horizontal-force sources.
A seismic sensor 1710 is along the Earth’s surface, which may Inciude being disposed on, near, or within a recess ofthe Earth’s surface 1704. For example, ln one embodiment, shallow holes may be drilied and sensors 1710 deployed ln the holes to avold wind noise, noise produced by rain showers, etc. Sensor 1710 is configured to detect orsense upgoing wave modes, reflected from subsurface sectors, formations, targets of interest, etc. ln this embodiment, sensor 1710 comprises w a multi-component geophone, for example a three-component geophone configured to sense compressional P mode and both fundamentai shear modes (SH and SV). As described ln FIGs. 114, various arrays and configurations of sources 1702 and sensors 1710 may be implemented in different embodiments. For example, two-dimensionai or three-dimensional acquisition templates may be deployed across Earth’s surface 1704. As another example, a plurality of sources 1702 (e.g., at least two, at least five, at least ten, etc.) may be disposed along a line and be configured to transmit seismic waves together or simultaneously. Verticai seismic profiling may be used ln one embodiment. ln an alternative embodiment, a reverse verticai seismic profiling arrangement may be used, in which one or more sources Is disposed ln a hole or well and one or more 3-component sensors or receivers are disposed along the Earth’s surface, ln another alternative embodiment, an interwell arrangement may be used, in which sources are disposed ln one well or hole and 3component receivers or sensors are disposed in another well or hole. An ln-hole source may be a wall-locked mechanical vibrator in an air-filled or fluid-filled well, or an air gun, water gun, or highenergy piezo-ceramic transducer freely suspended in a fluid coiumn, or other source.
A seismic recording System 1712 is configured to receive seismic data sensed by sensor(s) 1710 25 via a wired or wireless communication link and to store the data ln a database. System 1712 may comprise any type of computing device. System 1712 may be configured to acquire and/or process the received data. For example, processing may comprise polarity-reversal as previously described, the processing steps of FIG. 18 below, or other seismic data processing algorithme.
A digital media output device 1714 may be coupled to system 1712, or data may be transferred to device 1714 from System 1712 using any of a variety of technologies, such as a wired or wireless network, memory device, etc. Device 1714 may comprise one or more of a display device, a printer, a speaker, and/or other output devices.
According to one embodiment, system 1712 can be configured to acquîre or capture SH-SH mode data with surface-based sensors. According to another embodiment, system 1712 can be configured to acquîre both SV and SH mode data with surface-based sensors.
Referring now to FIG. 18, a diagram of a data acquisition and processing system 1800 and method for acquiring and processing full elastic waveform data from a vertical-force source using sub-surface sensors wili be described. A vertical-force seismic source 1802 is disposed on, near, or within a shallow recess ofthe Earth’s surface 1804. Source 1802 is configured to impart a vertical-force to surface 1804 to provide seismic waves into Earth media 1806. In this example, vertical-force source 1802 produces compressional P mode and both fondamental shear modes (SH and SV) in Earth 1806 directly at a point of application 1808 of the vertical-force source. In this embodiment, at least some of the SH and SV shear waves are generated at source 1802 and not by subsurface conversion caused by portions of Earth media 1806. Contamination of S data produced directly at a source station by converted-SV data produced at interfaces remote from the source station may occur. A data processing system may be configured to résolve, remove, reduce or identify this converted-SV data (and/or other noise modes, such as P events, P and S multiples, reverberating surface waves, wlnd noise, etc.) and to emphasize, amplify, or identify the target signal.
A plurality of seismic sensors 1810 are disposed at a plurality of locations within each of one or more shallow or deep holes drilled at any déviation angle. Sensors 1810 may be deployed permanently (e.g., by cementing or otherwise securing them in place) or they may be retrievable via wireiine or coil tubing. Sensors 1810 are configured to detect or sense upgolng wave modes, reflected from subsurface sectors, formations, targets of interest, etc. In this embodiment, sensors 1810 each comprise at least one muiti-component geophone, for example a three-component geophone configured to sense compressional P mode and both fondamental shear modes (SH and SV). As described In FIGs. 1-14, various arrays and configurations of sources 1802 and sensors 1812 may be implemented in different embodiments.
Sensor deployment equlpment and seismic recording system 1812 may be configured to position sensors 1810 within hole 1809, provide power to sensors 1810, and provide other fonctions needed to deploy sensors 1810. System 1812 comprises a computing system configured to receive seismic data sensed by sensors 1810 via a wired or wireless communication link 1813 and to store the data In a database. System 1812 may be configured to acquire and/or process the received data. For example, processing may comprise polarity-reversal as previously described, the processing steps of FIG. 18 below, or other seismic data processing algorithms.
A digital media 1815 may be coupled to System 1812 using any of a variety of technologies, such as a wired or wireless network, etc. Media 1815 may be configured to store and transfer the sensed and/or processed to data to other computing devlces.
Referring now to FIG. 19, a data processing System for processing fuit elastic wavefield data will be described. System 1900 comprises a digital computation System 1902, such as a Personal computer, UNIX server, single workstation, high-end cluster of workstations, or other computing System or Systems. System 1902 comprises sufficient processing power to process large quantifies of complex seismic data. A mass storage device 1904 or other memory Is coupled to digital computation System 1902, which is configured to receive data from the field recorders or sensors stored on a digital media 1906, such as a memory card, hard drive, or other memory device. Mass storage device 1904 is configured to download or receive the multi-component seismic data from digital media 1906 and to store the data In a database.
A user Interface 1908, such as a keyboard, display, touch screen display, speaker, microphone, and/or other user interface devlces may be coupled to System 1902 for two-way communication between System 1902 and a user. According to one exemplary embodiment, multiple user terminais 1910 may access data processing System 1902 through a user interface using a network of computers, terminais, or other Input/output devices (e.g., a wide-area network such as the Internet).
A software library 1912 Is coupled to data processing System 1902 and comprises one or more non-transitory computer-readable media programmed to perform one or more processing algorithms. The processing algorithms may comprise any of a number of known seismic data processing algorithms or algorithms described herein or which may be developed In the future. The algorithms can comprise algorithms in two categories: (1) algorithms required to process data acquired by surface-based 3-component sensors, and (2) algorithms required to process data acquired with 3-component sensors positioned in deep wells.
Surface-Based Sensors
For surface-based sensors, data computation System 1902 may be programmed with existing code, both proprietary code and public commercial code. System 1902 may be programmed with new code to optimize data handling and image construction. System 1902 may be programmed to extract P, SH, and SV modes from recorded data, as described herein with référencé to FIGS. 114.
Deep Well Sensors
When data are acquired with sensors In deep wells, the procedure is called vertical seismic profiling (VSP). VSP data-processing Systems are not as widely distributed as are Systems for processing surface-sensor data. VSP data may be processed using data-processing Systems made or used by VSP contractors, such as Schlumberger, Halliburton, Baker Atlas, READ, and/or other companies. The data processing Systems may be configured to extract P, SH, and SV modes from recorded data, by looking for SV and SH radiating directly from a surface source station.
System 1900 may further comprise one or more output devices 1914 coupied to digital computation System 1902. Output devices 1914 may comprise plotters, tape drives, dise drives, etc. configured to receive, store, display and/or présent processed data In a useful format.
Referring now to FIG. 20, a flow diagram illustrating a method 2000 of processing full elastic wave data wili be described. The method may be opérable on one or more processing circuits, such as digital computation System 2002. At a block 2002, a processing circuit is provided with mixed P, SH and SV modes in field-coordinate data space (Inlïne and crossline) from acquisition steps described previously. At block 2004, the processing circuit Is configured to or programmed to segregate, separate or otherwise remove P mode data by applying velocity filters to reject or filter out SH and SV modes.
A velocity filter is any numerical procedure applied to seismic data that emphaslzes events that propagate with a certain targeted velocity behavior and atténuâtes events that propagate with velocities different from this targeted velocity. There are numerous algorithme availabie to seismic data processors that perform velocity fiItering. Some of these filters operate in the frequencywavenumber (f-k) domain, some In the time-slowness (tau.p) domain, some are médian filters In the time-depth domain, etc. Velocity filters allow primary P reflections to be segregated from P multiples, and S events to be Isolated from P events.
Converted SV events hâve a faster velocity than do direct-S events because a converted SV involves a downgoing P wave; whereas, the downgoing raypath for a direct-S event Is S (much slower than P). Velocity filters can be designed that pass the slow velocities associated with an SS event (downgoing S and upgolng S) and reject the faster velocities of P-SV events (downgoing P and upgolng SV).
At a block 2006, the processing circuit is configured to reverse polarities of inline and crossline horizontal-sensor data acqulred at négative offsets, as described above with reference to FIGS. ΙΟΙ 4. At a block 2008, the processing circuit is configured to transform horizontal sensor data from inline/crossline data space to radial/transverse data space, as described above with reference to
FIGS. 10-14. As a resuit, the SH and SV modes (SH=transverse data; SV = radial data) are segregated and processed separately. The order of blocks of method 2000 may be rearranged In various embodiments; for example, the order of blocks 2006 and 2008 can be exchanged.
At a block 2010, radial sensor data are set aside as an SV data base, and transverse sensor data are set aside as an SH data base. This ségrégation of SV and SH modes allows the modes to be Individually introduced (e.g., as separate data sets) into the data-processing stream starting at block 2012.
At a block 2012, any one of numerous velocity analysis procedures availabie in the seismlc dataprocessing Industry may be appiied to each wave mode, P, SV, and SH, separately. Popular velocity-analysis options are semblance stacking, frequency-wavenumber analysis, and timeslowness analysis. This step identifies an optimal velocity function for each wave mode that will emphasize primary reflection events for that wave mode and attenuate noise, Interbed multiples, and spurious events from competing wave modes.
At a block 2014, static corrections are applied to improve reflector alignment. These corrections involve time shifts of data acquired at each source and receiver station. Because these time shifts are applied to an entire data trace, they are termed static corrections to differentiate them from dynamic time adjustments done by other processes. One static correction removes timing différences caused by variations in station élévations by adjusting time-zero on each data trace to mathematically move ail source and receiver stations to a common datum plane. A second static correction removes timing différences cause by different velocities being local to different source and recelver stations. The end resuit of these static conections Is an improvement in reflection continuity.
At a block 2016, any one of many noise rejection procedures may be applied to the data to Improve the signai-to-noise ratio. Some noise rejection options may be simple frequency filters. Others may be more sophisticated tau-p, f-k, or deconvolution procedures.
At a block 2018, the data are stacked (or summed) to create an Initial Image. Embedded In this step is a dynamic time adjustment of reflection events called a moveout correction that is applied to flatten reflection events to the same time coordinate at ail source-receiver offsets. A dataacquisltion geometry may cause many source-receiver pairs to produce reflection events at the same subsurface coordinate. In stacking, the flattened reflections from ail source-receiver pairs that image the same subsurface coordinate are summed to make a single image trace at that Image-space coordinate. When this stacking process Is extended across the entire seismic image space, a single Image trace with high signal-to-noise character Is produced at each image point in the Image space. It is at this step that a data processor gets his/her first look at the quality of the velocity analysis and static corrections that hâve been applied to the data (e.g., by displaying the data on an electronic display, printing the data using a printer, etc.).
At a block 2020, the data processor has to décidé if the image Is satîsfactory or if the data processing should be repeated to Improve the accuracy of the velocity analyses that perform the dynamic moveout corrections of reflection events and to improve the accuracies of the static corrections that time shift reflection events at each source and receiver station. If the decision is to repeat the Imaging process, the procedure retums to biock 2012 and proceeds to block 2020 again. If the Earth consists of fiat horizontal layers, these stacked data are a good image of the subsurface geology. If Earth layers are dipping or faulted, these stacked data are not a true image of the geology, but they still indicate the quality of the true image that will be created when the data are migrated (Block 2022).
At a block 2022, the data are migrated. Migration is a procedure that utilizes a seismic-derived velodty model of the Earth to move reflection events from their coordinate positions In offset-vstime image space to their correct subsurface positions in the Earth. Numerous migration algorithms are available In the seismic data-processing industry. Some algorithms are proprietary to dataprocessing companies; others are available as commerdally leased software or as shared freeware.
The position of the data migration step on Figure 20 is a post-stack migration procedure. The migration step can be moved to be positioned between blocks 2016 and 2018 to do pre-stack migration. Pre-stack migration is often more désirable than post-stack migration but is more computer intensive. Pre-stack time migration and depth migration allow the vertical coordinate axis of the image to be either depth or time, depending on the data processor preference. The possi bility of imaging using reverse time migration techniques can be utilized at this point if desired.
The teachings herein may be implemented by seismic contractors, oil and gas companies, and others. The teachings herein may be used in other industries as well, such as geothermal energy, CO2 séquestration, etc.
Extant Data
The Systems and methods described herein may be applied to processing of extant or preexisting or legacy sets of seismic data. According to one example, a memory comprises seismic data which may be raw, unprocessed or partially processed. The seismic data may hâve been generated months or years prior to the processing of the data. A processing circuit may be configured to process the seismic data to generate, provide, or achîeve full elastic waveform data.
For example, the processing circuit may be configured to reverse polarities of horizontal sensor data acquired at négative offsets as described herein to generate S mode data, such as SH mode and SV mode data, The processing circuit may further be configured to extract P, SH, and SV modes from the previously recorded data. In one embodiment, the seismic sensors will hâve been receiving data for a suffi oient period of time, such as at least ten seconds or at least twelve seconds, in order to receîve ail of the slower-moving SH and SV modes In addition to the P mode data.
According to one embodiment, sources other than explosive sources (i.e. non-explosive sources, such as vertical vibrators and vertical-impact sources) may be used to construct S-mode images, such as SV and SH images. The advantages of non-explosive sources include that they are acceptable sources in environments where explosive sources are prohibited or impractical. Exemplary advantages include:
• Explosives cannot be used in urban environments. In contrast, vibrators can operate down streets, alleys, and in close proximity to buildings.
• Explosives cannot be used along road right-of-ways. County roads and public highways are popular profile locations for vibrators.
In areas contaminated by mechanical noise (road traffic, gas-line pumping stations, oil well pump jacks, active drilling rigs, etc.), the compact impulsive wavelet (typically spanning only 100 to 200 ms) produced by an explosive shot can be overwhelmed by short noise bursts from noise sources local to one or more receiver stations. In contrast, a vibrator créâtes a wavelet by inserting a long (10 to 12 seconds) chirp into the Earth in which frequencies vary with a known time dependence. llnless mechanical noise has exactly the same frequency variation over a 10-second or 12second time duration as does a vibrator chirp signal, the cross corrélation procedure used to Identify vibroseis reflection events suppresses the noise. Explosive sources are less practical than vibrators in hlgh-noise environments.
• Vertical impact sources hâve appeal because they are lower cost than explosive sources (and usually lower cost than vibrators). Operators often choose the lowest cost source even if the source has some technical shortcomings.
While non-explosive sources are used in some embodiments described herein, explosive sources may be used in other embodiments described herein.
S data can be acquired in the widest possible range of environments when vertical-force sources are utilized. Explosive sources can be used in swamps, mountain s, etc. where non-explosive sources are not feasible or practical, and vibrators and vertical impact sources can be used In highculture areas (clties, roads, etc) where explosives are prohlbîted, and when budget constraints limit source options.
The Systems and methods described with reference to FIGs. 17-20 may Implement any of the 5 features or principles described with reference to FIGs. 1-16.
Extractlng SV Shear Data from P-Wave Seismic Data
Referring now to FIGs. 21-35, system and methods for extractlng SV shear-wave data from Pwave seismic data will be described.
Systems and methods are described for extracting SV shear-wave data from P-wave seismic to data acquired with a vertical-force source and vertical geophones. The P-wave seismic data may comprise legacy P-wave data (e.g., P-wave data acquired at some time days, months, or years, such as at least one year, In the past), P-wave data acquired In the présent day, two dimensional data, three dimensional data, single-component sensor data, and/or three-component sensor data acquired across a wide variety of Earth surface conditions.
These Systems and methods are based on the use and application of the SV-P mode produced by a vertical-force seismic source. The SV component of this seismic mode provides valuable rock and fluid Information that cannot be extracted from P-wave seismic data. The Systems and methods may produce an S-wave Image from seismic data acquired with surface-based vertical geophones.
According to some embodiments, vertical, single-component or one-component, surface-based seismic sensors are used to acquire SV shear data. In some embodiments, only a vertical, singlecomponent receiver may be présent (or hâve been présent In the case of legacy data) at each receiver station.
Systems and methods are described for extracting SV-SV data from P-wave seismic data 25 acquired with a vertical-force source and vertical geophones In situations where P-wave data are acquired across areas of exposed high-velocity rocks.
Systems and methods are described for extracting P-SV data from P-wave seismic data acquired with a vertical-force source and vertical geophones In situations where P-wave data are acquired across areas of exposed high-velocity rocks.
In some embodiments, there is no requirement of any spécifie positioning of receiver relative to source. In some embodiments, the Systems and methods described herein may apply whether source and receiver are both on the Earth surface, at the same élévation, or at distinctly different élévations.
In some embodiments, upgoing SV events are not used in imaging; instead, only the upgoing P part of SV-P data are used In Imaging.
In some embodiments, the sources may hâve known or predetermined locations relative to surface-based receivers and the direction of travel of energy that reaches the receivers at their receiver stations may be known before processing of the received data.
The principat seismic reflection data that are acquired to evaluate geoiogical conditions across onshore areas are compressional-wave (P-wave) data. From a historicai perspective, numerous io large iibraries of legacy seismic data exist, with the âges of these data extending back into the 1950's and 1960‘s. Most legacy seismic data are P-wave data.
The term land-based’ seismic data refers to any seismic data acquired in non-marine environments, which would Indude data acquired across swamps, marshes, and shallow coastal water, as well as data acquired across exposed iand surfaces. Land-based P-wave data are 15 generated using vertical-force sources. This term vertical-force source* includes any seismic source that applies a vertical force to the Earth. Induded In the broad range of vertical-force seismic sources are vertical vibrators, vertical impacts, and shot-hole explosives.
P-wave land-based seismic data are recorded using vertical geophones or other vertically oriented seismic sensors. When acquiring P-wave seismic data, the sensor deployed at each 20 receiver station can be either single-component or three-component as long as sensor eiements In each receiver package measure vertical movement of the Earth.
One or more embodiments described herein may allow SV shear-wave data to be extracted from P-wave data acquired with vertical-force sources and vertical sensors. One or more embodiments may apply whether a sensor package Is single-component or three-component. One or more 25 embodiments may apply to legacy P-wave seismic data as well as to P-wave data acquired In the présent day.
One or more embodiments described herein may allow SV shear-wave data to be extracted from either 2D or 3D P-wave data.
SV-to-P Seismic Mode
The embodiments that are configured to extract SV shear-wave data from P-wave data use the SV-to-P converted seismic mode. The notation SV-P will be used to designate this wave mode. In this notation, the first term identifies the downgoing seismic wave (SV) that Illuminâtes géologie targets, and the second term désignâtes the upgoing reflected wave (P) from those targets. To maintain consistent notation, standard P-wave data will be labeled as P-P data, meaning the downgoing illuminating wavefield is a P-wave, and the upgoing reflected wavefield is also a Pwave.
Raypath diagrams comparing SV-P imaging of subsurface geology and conventional P-P Imaging are illustrated on Figure 21. The bold arrows 2100, 2102 drawn at the source station 2104 and receiver station 2106 are vertical to illustrate: (1) the seismic source applies a vertical force vector to the Earth, and (2) each senslng geophone Is oriented vertically or otherwise configured to sense or measure vertical movement of the Earth. Receiver 2102 may be a vertical geophone, a io vertical component of a multl-component geophone, or another single- or multi-component geophone configured to sense, measure or detect vertical movement of the Earth (e.g., a 54 degree geometry geophone or Gal'perin geophone). As described hereinabove, a vertical-force seismic source produces not only P waves but also SV and SH shear waves. Consequently, both downgoing P and downgoing SV raypaths are shown propagating away from the vertical-force source station 2104 on Figure 21. Segments of downgoing and upgoing raypaths are labeled either P or SV to indicate the spécifie wave mode that travels along each segment of each raypath. Circled arrows on each raypath segment identify the direction in which the wave mode acting on that raypath segment displaces the Earth. The data polarities Indicated by these particle displacement vectors agréé with the polarity conventions defined by Aki and Richards (1980).
Common-midpoint imaging may be used to produce P-P stacked Images of the Earth's subsurface. In a flat-layered Earth, when the velocity of the downgoing wavefield that illuminâtes a géologie target is the same as the velocity of the upgoing reflected wavefield from that target, as it is for P-P data, the reflection point (Image point) is half way between the source and the receiver. Therefore, the terms “common midpoint or “CMP are used to describe this Imaging concept.
When seismic images are made using a downgoing illuminating wavefield that has a velocity that diffère from the velocity ofthe upgoing reflected wavefield, a different concept called commonconvereion-point’ imaging Is used to construct stacked Images of géologie targets. The abbrevlation “CCP Is used to indicate this seismic imaging strategy. CCP imaging techniques are used to construct stacked images from SV-P data because the downgoing SV mode has a velocity that diffère from the velocity of the upgoing P mode (Fig. 21 ).
As shown on Figure 21, the upgoing events that arrive at a receiver station are P-wave events for both P-P and SV-P modes. A concept not illustrated in this simplified, stralght-raypath model is that a P raypath curves to become almost true-vertical when It entere an unconsolîdated, low velocity layer 2100 that covers most of the Earth's surface. This principle Is lllustrated on Figure 22. When upgoing P raypaths 2200,2202 bend to almost true-vertical as they approach a receiver station 2106, their particle displacement vectors 2204,2206 align with vertically orientée! geophones at receiver station 2106 and induce a strong response in a vertical geophone. Because both legacy P-wave seismic data and present-day P-wave data are recorded with vertical geophones, these P-wave data contain not only P-P modes, but also SV-P modes, such as raypath 2200 lllustrated in Figure 22.
As lllustrated in Figure 36, If a P-wave is traveling in a true horizontal direction when It arrives at a vertical geophone, the P-wave will not generate any response In the geophone. If a P-wave Is traveling ln a true vertical direction when it arrives at a vertical geophone, the P-wave will Induœ a maximum geophone response (A). At any Intermediate angle of approach, the geophone response produced by an arriving P-wave will be A cos(4>), where Φ is the approach angle measured relative to true vertical, and A Is the maximum response the P-wave produces when it travels In a true vertical direction. At some non-vertical approach angle Φχ, a P-wave will still hâve a small vertical component that will produce a small response in a vertical geophone, but not a “usable signal. The exact value of cutoff angle Φχ varies from location to location, and varies day to day at any given location, depending on the level of background noise that is présent. Background noise includes wind-generated shaking of local végétation, mechanical vibrations from nearby machinery or vehieufar traffic, water drops fallîng from the sky or dripping from close-by trees and bushes, and other factors that induce disturbances close to a geophone station.
An additional Imaging option Is lllustrated on Figure 23. In this scénario, the raypath labeling acknowledges a vertical-force source 2104 causes an SV-SV mode 2300 which arrives at a receiver station 2106 just as does a P-P mode 2108 (Figure 21). However, when the principle is applied that, in most Earth surface conditions, raypaths approach a surface receiver in an almost or substantially vertical direction, the orientation of the particle displacement vector 2302 associated with an upgoing SV raypath 2301 does not activate a vertical geophone (as the upgoing P waves do In Figure 22). Thus for some P-wave data acquired with vertical geophones, it may not be possible to extract SV-SV reflection events (or P-SV reflection events) from the response of vertical-geophone data.
An exception to the principle described on Figure 23 occurs when vertical geophones are deployed across an Earth surface where the top Earth layer is a hard, high-velodty material, as in layer 2400 ln Figure 24. ln this type of surface condition, an SV raypath 2400 will arrive at a receiver station 2106 along a substantially nonvertical trajectory, and the vertical component of an SV particle displacement vector 2402 will activate a vertical geophone 2106 (Figure 24). Thus, when P-wave data are acquired across high-velocity surfaces with vertical geophones, data having an upgoing SV mode are recorded by vertical geophones in addition to SV-P data. As a resuit, both P-SV and SV-SV data, which both hâve upgoing SV modes, are recorded by vertical geophones in situations where geophones are deployed across a high-velocity surface layer. Both upgoing P and SV raypaths in Figures 24 approach receiver station 2106 from a direction that differs significantly from near-verticai.
As illustrated ln Figure 37, where the upgoing mode is SV, the response that an SV arrivai Induces in a vertical geophone is Asin(O), rather than Acos(<t>) as it is for an upgoing P mode. The larger Φ is, the stronger the SV response is. As S velocity Increases in the top-most Earth layer, Φ increases. How big Φ should be, and how large S velocity should be to ensure there is an appréciable value of Φ, dépend again on the magnitude of the background noise at the receiver station.
One or more embodiments described herein may acquire P-SV data without the use of threecomponent geophones and without extracting the upgoing SV mode from horizontal-geophone responses. One or more embodiments described herein allows P-SV data to be acquired with slngle-component vertical geophones, for example ln situations where the top Earth layer Is highvelocity rock. One or more embodiments described herein may acquire P-SV data without the use of a receiver configured to sense, detect or measure horizontal movement of the Earth.
P-SV and SV-P raypaths are compared on Figure 25. Because upgoing raypaths become nearverticai ln a low-velocity surface layer (Fig. 22), the orientation of partide displacement associated with the upgoing SV segment 2500 of a P-SV mode 2502 fails to activate a vertical geophone in many Earth surface environments. Thus, in some vertical-geophone P-wave data, there will be no usable P-SV data. However, P-SV data will be recorded by a vertical geophone ln cases where the top Earth layer has high velocity (Figure 24).
SV-P Image Space
The imaging principles of P-SV and SV-P modes 2502, 2504 illustrated on Figure 25 emphaslze an SV-P mode images geology 2506 doser to a source station 2508 than to a receiver station 2510. When P-wave data are acquired with a source-receiver geometry in which receivers occupy an area that differs significantly from the area occupied by sources, it is useful to understand how the image space spanned by SV-P data differs from the image space spanned by the P-SV mode.
Figures 26A and 26B show two options in which P-wave data are acquired across the same image space using vertical-force sources and vertical geophones. The figures illustrate sourcereceiver geometries from an aerial view looking downward, showing the size and position of SV-P
Image space (11,12,13,14) for two three-dîmensional P-wave data-acquisition geometries. With the source-recel ver geometry shown on Figure 26A, the area spanned by source stations 2600 Is larger than the area spanned by receïver stations 2602. In the option shown as Figure 26B, the reverse Is true, and receivers span an area 2604 larger than the area spanned by sources 2610. The CMP P-wave Image space will be the same for both geometries because the same number of source-receiver pairs Is Involved, and these station pairs occupy the same Earth coordinates In both geometries. To avoid graphie clutter, the boundaries of P-P image space are not shown on the drawings, but if drawn, the boundaries of P-P Image space would be half-way between the boundaries of receïver area R1-to-R4 and the boundaries of source area S1-to-S4 in both Figures 26A and 26B, reflecting the midpoint aspect of the CMP method.
The size and position of SV-P image space resulting from these two distinct data-acquisition geometries of Figures 26A and 26B differ. SV-P image space covers a large area 2606 when the geometry option of Figure 26A is used and a retatively smaller area 2606 when the geometry option of Figure 26B is used. For both geometries, SV-P image points are positîoned doser to source stations than to receïver stations. Because of the redprocal relationships between the image coordinates of SV-P and P-SV modes (Figure 25), the image space spanned by P-SV data when the geometry of Figure 26A is used would be the Image space spanned by SV-P data in Figure 26B. if the geometry of Figure 26B Is used, then P-SV data would span the SV-P image space drawn on Figure 26A. Because the same number of source-receiver pairs Is involved in each dataacquisition geometry in this exemplary embodiment, SV-P stacking fold across the larger area (Fig. 26A) will be lower than SV-P stacking fold across the smaller area (Fig. 26B). Each geometry offers advantages for the SV-P mode, depending on the signal-to-noise ratio of SV-P data. If the SV-P signal-to-noise ratio is rather high, then the option of Figure 26A extends good-quality SV information over a larger area than what Is imaged by P-SV data. If the SV-P signal-to-noise ratio is low, then Increaslng SV-P fold over a smalier area as In Figure 26B should create better quality SV information than what is provided by P-SV data that extend over a iarger area with reduced fotd.
SV-P Data Processing - Data Polarity
As explaïned with reference to the embodiments of Figures 1-20, to extract SV-SV and SH-SH modes from data generated by a vertical-force source, the processing reverses the polarity of data acquired by horizontal geophones stationed In the negative-offset direction relative to the polarity of data acquired by horizontal geophones deployed in the positive-offset direction. That data polarity adjustment does not apply to SV-P data In this embodiment because the SV-P wave mode Is recorded by vertical geophones, not by horizontal geophones.
Raypaths Involved In positive-offset and negative-offset SV-P imaging are illustrated on Figure 27. In this diagram, SV-P data generated at vertical source A and recorded at vertical receiver A are labeled SVA for the downgoing SV mode and PA for the upgoing P mode. The offset direction from vertical source A to vertical receiver A is arbi trarily défi ne d as positive offset. When the positions of source and receiver are exchanged, creating vertical source B and vertical receiver B, the offset direction reverses and is deflned as négative offset. The raypath for negative-offset SV-P data is labeled SVB for the downgoing SV mode and P8 for the upgoing P mode. The polarities shown for the downgoing SV particle-displacement vector conform to the polarity convention established by Aki and Richards (1980) and documented by Hardage et al. (2011 ). Note that for io both positive-offset data and negative-offset data, the vertical component of the particledisplacement vectors for the upgoing P modes are in the same direction (pointing up), hence there ls no change in SV-P data polarity between positive-offset data and negative-offset data.
If the SV-SV mode is extracted from P-wave data in situations where a high-velocity Earth surface ailows the upward traveling SV mode to energize a vertical geophone (Fig. 24), it Iikewise 15 ls not necessary to adjust the polarity of the vertical-geophone data In either offset-direction domain. Adjusting the polarity of upward traveling SV modes in the negative-offset domain to agréé with the polarity in the positive-offset domain is used when the SV mode is recorded by horizontal geophones, not when they are acquired by vertical geophones.
SV-P Data Processing - Velocity Analysis
The embodiments described herein may be configured to perform a velocity analysis as a dataprocesslng step when constructing seismic Images. When CMP data are processed, it is not necessary to be concemed about which offset domain (positive or négative) data résidé in when performing velocity analyses. If the velocities of downgoing and upgoing wave modes are the same (CMP data processing), the same velocity behavior occurs in both offset directions. However, when converted modes are involved, the method may comprise two velodty analyses—one analysis for positive-offset data and a second analysis for negative-offset data.
The reason for this dual-domain velodty analysis ls illustrated on Figure 27, which shows two distinct rock fades between two surface-based source and receiver stations. Laterally varying rock conditions such as shown on this diagram can be found in many areas. For purposes of illustration, 30 assume the P and S velocities in Fades A are significantly different from the P and S velodties in Fades B. The travel time required for a positive-offset SV-P event to travel raypath SVA-PA is not the same as the travel time for a negative-offset SV-P event to travel raypath SVb-Pb· This différence In travel time occurs because the SVA mode is totally in Fades A, but the SVB mode is almost entirely In Faciès B. Likewise, ail of mode PB is in Faciès A, but mode PA has significant travel paths Inside Faciès A and Faciès B. Because travel times differ in positive-offset and negative-offset directions, one velocity analysis is done on positive-offset data, and a separate velocity analysis ls done for negative-offset data.
Examples of SV-P reflection events extracted from P-wave data by velocity analysis are displayed as Figures 28A and 28B. Figures 28A and 28B illustrate SV-P reflections extracted from vertical-geophone P-wave seismic data. The seismic source was a shot-hole explosive (a verticalforce source). Two shot signal gathers or acquisitions generated at source stations 1007 and 1107 are displayed after velocity fiitering. For each shot gather, velocity analyses were done separately 10 for positive-offset data and negative-offset data. In these examples, there is not a large différence between positive-offset and negative-offset velocities. As a resuit, the curvatures of negative-offset SV-P reflections are approximately the same as the curvatures of positive-offset SV-P reflections.
Only reflection events having curvatures coindding with downgoing Vs velocities and upgoing Vp velocities appropriate for the rock sequence where these data were acquired are accepted. Other 15 velocities are rejected. These examples corne from a seismic survey for which the energy sources were vertical-force sources, and the analyzed data were recorded by vertical geophones. Analyses for two common-shot trace gathers are shown. For each shot gather, positive-offset data were subjected to velocity analysis separately from negative-offset data. Each velocity analysis rejected reflection events having velocities that differed by more than 20-percent from the velocities used to 20 create high-quality P-SV Images across the same image space. The resuit is that high-quality SVP reflections are extracted from vertical geophone data for both positive-offset P-wave data and negative-offset P-wave data. The principal différence in P-SV and SV-P velocity analyses in this exemplary embodiment ls that P-SV velocity analyses are done on data recorded by horizontal geophones; whereas, SV-P velocity analyses are done on data recorded by vertical geophones.
To make seismic images from the reflection events shown in FIGs. 28A and 28B, reflection events for a number of source stations in the survey (e.g., at least 10, at least 100, at least 1000, etc.) wouid be generated. The reflection event data then wouid be binned, stacked and migrated. For example, the reflection event data may be binned using CCP or ACP binning strategies to define those coordinates. The reflection event data may then be stacked and then migrated after 30 stack to generate an image. Migration physically moves reflections from where they are in reflection time to where they should be in image time.
The reflection events shown in FIGs. 28A and 28B comprise primary reflection events and multiple reflection events. Multiple reflection events resuit from multiple reflections of seismic waves caused by réverbérations between interfaces of layers of the Earth. Multiple reflection events can cause an Image to not be positioned correctly in travel time space. Multiple reflections may be filtered out of the reflection events In subséquent processing.
The reflection events shown In FIGs. 28A and 28B comprise an Interpreted primary reflection at a point where reflection events in négative offset and positive offset domains meet, such as point 2800. The reflection events comprise an interpreted multiple reflection at a point where reflection events in négative offset and positive offset domains do not meet, such as point 2802.
SV-P Data Processing: Constructlng SV-P Images
The processing of SV-P data for generating Images can be done in a number ofways, such as: (1) by CCP binning and stacking of SV-P reflections, followed by post-stack migration of the stacked data, or (2) by implementing prestack time migration, depth migration or reverse-time migration of SV-P reflections. Each method has its own benefits. For example, method 2 (prestack migration) Is a more rigorous approach; method 1 (CCP blnning/stacking and post-stack migration) is lower cost. To perform CCP binning and migration of SV-P data, CCP coordinates of SV-P Image points are mlrror Images of CCP image points associated with P-SV data, as Iîîustrated on Figure 29. The SV-P data-processing strategy may be based on this mirror-image symmetry of CCP image-point profiles for P-SV and SV-P modes.
Because positive-offset and negative-offset SV-P data hâve different velocity behavlors, two separate CCP blnning/stacking steps are done to create an SV-P stacked image. In a first step, positive-offset data are binned and stacked Into an Image using velocities determined from positiveoffset data, and In a second step, negative-offset data are binned and stacked into a second Image using velocities determined from negative-offset data. The final SV-P image is the sum of these two images. This same dual-lmage strategy may be implemented when binning and stacking P-SV data. The three stacked Images (negative-offset Image, positive-offset Image, and summed Image) can be migrated and used in geological applications. As documented by Hardage et al. (2011) relative to P-SV imaging, some géologie features are sometimes better seen in one of these three Images than In Its two companion Images. Thus ail three stacked and migrated images may be used In geological Interprétations.
SV-P Data Processing: Method 1—CCP Binning, Stacking, and Post-Stack Migration
Some commercial seismic data-processing software that can be purchased or leased by the geophysicai community can caicuiate converted-mode image coordinates called asymptotic conversion points, which are abbreviated as ACP. Two examples are Vista seismic data processing software, sold by Geophysicai Exploration & Development Corporation, Alberta,
Canada and ProMAX seismic data processing software, sold by Halliburton Company, Houston, Texas. An ACP is an image coordinate where the trend of correct CCP image points for a spécifie source-receiver pair becomes quasi-vertical (Figure 29). Deep geology is correctly imaged using P-SV data binned using ACP coordinates, and would also be correctly imaged by SV-P data binned 5 using ACP concepts that are adjusted for SV-P data. However, shallow geology is not correctly imaged for either P-SV data or SV-P data when ACP binning methods are used. True CCP binning can produce correct stacked images of both shallow and deep geology for converted modes appropriate for post-stack migration. On Figure 29, the asymptotic conversion point for the P-SV mode is labeled ACP1, and the asymptotic conversion point for the SV-P mode is labeled ACP2.
Neither image point is conect except where their associated CCP binning profile Is quasi-vertical (i.e., for deep targets). As emphasized above, these two image points are mirror images of each other relative to the common midpoint (point CMP on Figure 29) for any source-receiver pair involved in a seismic survey.
One exemplary method of produdng SV-P CCP/ACP binning comprises adjusting software that 15 performs CCP binning for P-SV data so that the coordinates of sources and receivers are exchanged when determining image-point coordinates. Referring to the source-receiver pair drawn on Figure 29, an exchange of station coordinates has the effect of moving the receiver station to the source station and the source station to the receiver station. Software used to process P-SV data will then calculate the image point trend labeled CCP2 rather than the trend labeled CCP1.
m Using coordinates specified by profile CCP2 to bin SV-P reflectïons extracted from verticalgeophone data can produce SV-P images. The SV-P images should be equal In quality to what Is now achieved with P-SV data.
Curve CCP1 shows the trend of common-conversion points for P-SV data. Curve CCP2 shows the trend of common-conversion points for SV-P data. ACP1 and ACP2 are asymptotic conversion 25 points for trends CCP1 and CCP2, respectively. CCP1 and CCP2 are mirror images of each other relative to the common midpoint CMP for this source-receiver pair.
SV-P Data Processing: Method 2—Prestack Migration
According to an alternative embodiment, prestack migration can be done so as to create a timebased seismic image or a depth-based seismic image. Referring to Figure 30, prestack migration 30 may be done by numerically propagating a spécifie seismic wavefield downward from each source station to illuminate géologie targets, and then numerically propagating a spécifie seismic wavefield upward from reflecting interfaces to each receiver station.
The spécifie wavefields used ln prestack time migration, depth migration, or reverse-time migration may be created by applying velocity filtere to data recorded by vertical geophones so that reflection events having only a predetermined velocity behavior remain after velocity filtering. The predetermined velocity behaviors of interest are those associated with the foliowing seismic modes: P-P, P-SV, SV-SV, and SV-P. If 3C geophones are used in combination with a vertical-force source, a fifth velocity filtering option is to extract SH-SH reflection events. However, for this latter option, the filtering action is applied to data recorded by transverse horizontal geophones. The resuit is an image of géologie interfaces seen by each spécifie seismic mode. For simplicity, only one source station and only one receiver station are shown on Figure 30.
The table on Figure 30 considère only wave modes produced by a vertical-force source as described hereinabove with reference to Figures 1-20 (P, SV, SH) and the responses of only vertical geophones. For an Earth with isotropie velocity layere, there are fîve possible combinations of downgoing (D) and upgoing (U) modes. These possibilities are labeled Option 1 through Option 5 in the figure table.
As Indicated by the table on Figure 30, prestack migration software can croate an SV-P image if the velocity of the downgoing wavefield is that for a propagating SV wavefield and the velocity of the upgoing wavefield is that for a P wavefieid. Examples of SV-P data that would be used for prestack migration Option 3 listed on Figure 30 (SV-P imaging) are exhibited on Figure 28. For a 3D Pwave seismic survey, velocity filtering similar to that done to produce these two example shotgathere would be done for ali shot gathers across a survey area. If a survey involves 1000 source stations, then 1000 velocity-filtered shot-gathere similar to those on Figure 28 would be created. Ail 1000 sets of SV-P reflections would be pre-stack migrated downward through an Earth model having layere of SV velocities and then migrated upward through an Earth model having layere of P-wave velocities, ln Figure 30, a time-space distribution of velocities for a spécifie seismic mode is defined so that a spécifie downgoing wavefield (D) can be propagated through this Earth velocity model from every source station to illuminate targets. A second time-space distribution of velocities fora second spécifie seismic mode is then imposed to propagate that spécifie reflected upgoing wavefield (U) to every receiver station. The combinations of downgoing and upgoing velodties that can be implemented for a vertical-force source and vertical geophones are listed in the table of Figure 30.
SV-P Data Processing · Determining S-Wave Velocity
To calculate either of the CCP binning profiles shown on Figure 29, the processing System Is configured to détermine the S-wave velocity within the geology that is being imaged. If the alternat® option of creating converted-mode Images with prestack migration techniques Is used (Fig. 30), the processing System is configured to generate reliable estimâtes of S-wave velocities within the rocks that are illuminated by the seismic data. Determining the S-wave velocity for calculating SV-P image points can be done in the same way that S-wave imaging velodties are determined for P-SV data. Methods for determining S-wave velodty for calculating convertedmode image points comprise:
1. Use 3-component vertical seismic profile (VSP) data acquired local to the seismic Image area to calculate Interval values of Vp and Vs velodties.
2. Use dipole sonie log data acquîred local to the seismic image space to détermine VP to and Vs velodties.
3. Combine iaboratory measurements of Vp/Vs veiodty ratios for rock types like those being Imaged with seismic-based estimâtes of P-wave velocities to calculate S-wave velodties.
4. Calculate CCP binning profiles for a variety of Vp/Vs velodty ratios, make separate stacks of converted-mode data for each CCP trend, and examine the sériés of stacked data to détermine which CCP profile produces the best quality Image.
Any of these methods will provide reliable S-wave velocities to use for binning SV-P data. Altemate methods may be used.
Comparison of SV-P data to P-SV data
This application shows there are severai similarities between SV-P data and P-SV data, according to some exemplary embodiments. There are also différences between the two wave modes, according to some exemplary embodiments. Some of these similarities and différences are listed in the table shown as Figure 31. Similarities between SV-P and P-SV data include items 1, 5, and 6 (same energy source, same velocity analysis strategy, and same normal moveout (NMO) velocity behavior). Différences include items 2, 3,4, and 7 (different receivers, different image coordinates, different CCP profiles, and different polarity behavior).
SV-P Data Processing Apparatus
Refening now to FIG. 32, a data processing System for processing SV-P data will be described.
System 3200 is configured to extract SV shear data from vertical-sensor responses. System 3200 30 comprises a digital computation System 3202, such as a personal computer, UNIX server, single workstation, high-end cluster of workstations, or other computing System or Systems. System 3202 comprises sufficient processing power to process large quantities of complex seismlc data. A mass storage device 3204 or other memory is coupied to digital computation System 3202, which Is configured to receive data from the field recorders orsensors stored on a digital media 3202, such as a memory card, hard drive, or other memory device. Mass storage device 3204 Is configured to download or receive the muitl-component seismic data from digital media 3206 and to store the 5 data In a database.
In this embodiment, digital media 3206 comprises data received from a vertical sensor using a field recorder or receiver. The data on digital media 3206 may hâve been acqulred recently or days, months, or years in the past. The data may hâve been recorded using a vertical force sensor having a suffident listening time, for example of at least 5 seconds, at least 8 seconds, at least 10 10 seconds, or other période of time. The data may hâve been acquired without the expectation of recovering SV-P data by the entity handling the acquisition of data and without knowledge of the presence of SV-P data In the data acquired from seismic reflections.
The remaining éléments In FIG. 32 may comprise any of the embodiments described herelnabove with reference to FIG. 19, or other components. Software library 3212 may comprise 15 processing algorithme configured to process the data according to any of the principles described hereinabove, for example with reference to FIGs. 21-31, and FIGs. 34 and 35 below.
SV-P Data Acquisition
Referring now to Figure 33, a diagram of a data acquisition System 3300 and method for acquiring SV-P data from a vertical-force source using surface-based sensors wili be described. A 20 vertical-force seismic source 3302 is disposed on, near, or within a shallow recess of the Earth's surface 3304, which may comprise relatively high-velocity layers or portions or reiativeiy lowvelocity layers or portions. Source 3302 Is configured to impart a vertical-force to surface 3304 to provide seismic waves Into Earth media 3306. Source 3302 may comprise a vertical vibrator, shothole explosive, vertical-impactor, air gun, vertical welght-dropper or thumper, and/or other vertical25 force sources. In this example, vertical-force source 3302 produces compressional P mode and both fondamental shear modes (SH and SV) in Earth 3306 directly at a point of application 3308 of the vertical-force source. In this embodiment, at least some of the SH and SV shear waves are generated at source 3302 and not by subsurface conversion caused by portions of Earth media 3306. The frequency waves may be provided In a frequency sweep or a single broadband impulse. 30 A vertical-force source may be used without any horizontal-force sources.
A seismic sensor 3310 is along the Earth’s surface, which may inciude being disposed on, near, or within a recess of the Earth’s surface 3304. For example, In one embodiment, shallow holes may be dritled and sensors 3310 deployed in the holes to avold wind noise, noise produced by rain showers, etc. Sensor 3310 Is confîgured to detect or sense upgoing wave modes, reflected from subsurface sectors, formations, targets of interest, etc. In this embodiment, sensor 3310 may comprise a vertical-response sensor (either single-component or 3-component package) confîgured to sense compressional P modes and, as described herein, other modes such as SV-P (e.g., direct SV-P). In one embodiment, sensor 3310 may comprise a vertical-response sensor without horizontal-response sensors, for example only a single, vertical-response sensor. Various arrays and configurations of sources 3302 and sensors 3310 may be Implemented in different embodiments.
The remaining éléments In FIG. 32 may comprise any of the embodiments described hereinabove with reference to FIG. 17, or other components.
Data Processing in Low-Veloclty Earth Surface
Referring now to FiG. 34, a flow diagram iliustrating a method 3400 of processing vertical sensor data for low-velocity Earth surface will be described. The method may be opérable on one or more processing circuits, such as digital computation system 3202. The method 3400 may use similar techniques to those described above with reference to FIG. 20, which contains further explanation of some of the processing procedures described in FIG. 34. At a block 3402, a processing circuit is provided with mixed P-P and SV-P modes in vertical-sensor data from acquisition steps described previously. At block 3404, the processing circuit Is confîgured to or programmed to segregate, separate or otherwise remove P-P and SV-P mode data by applying velocity filters to reject or filter out improper wave-mode propagation velocities.
At a block 3406, the processing circuit is confîgured to détermine NMO, stacking and/or migration velocities for P-P and SV-P modes. Separate velocity analyses should be done for positive-offset SV-P data and for négative offset SV-P data. The processing circuit perforais separately velodty analyses for positive-offset data and negative-offset data to détermine how the magnitudes of interval velocities differ in these two offset domains. If there is no latéral variation in P and SV velodties around a source station, there is no need to do two separate SV-P velodty analyses - one velocity analysis for positive-offset data, and a second velocity for negative-offset data. In such a simple, uniform-veiodty Earth, positive-offset SV-P reflections and negative-offset SV-P reflections hâve the same velodty curvatures, and a velodty analysis done In one offset domain can be used for the opposite-azîmuth offset domain. However, it Is rare for there to not be latéral variations in P and SV velodties around a source station as illustrated on Figure 27. When layer velocities vary latérally for any reason, positive-offset and negative-offset SV-P data should undergo separate velodty analyses as previously discussed using Figure 27. To ensure latéral velocity variations are accounted for, converted-mode data are processed as two separate data sets. One data set Involves only positive-offset data, and the second data set involves only negative-offset data. Velocity fiitering may be done separately for positive-offset data and negativeoffset data to détermine offset dépendent Interval velocities that can be used to image SV-P data. Velocity fiitering may be done separately for positive-offset data and negative-offset data to output SV-P reflection data corresponding to the calculated SV-P veiodties. The veiodties used in some embodiments are the magnitudes of interval veiodties and average veiodties needed to stack and/or migrate SV-P data. These velocities may hâve no algebraic sign.
At a block 3408, static corrections are applied to improve reflector alignment. These corrections involve time shifts of data acquired at each source and receiver station. Because these time shifts are applied to an entîre data trace, they are termed static corrections to differentiate them from dynamic time adjustments done by other processes. One static correction removes timing différences caused by variations in station élévations by adjusting time-zero on each data trace to mathematically move ail source and receiver stations to a common datum plane. A second static correction removes timing différences cause by different veiodties being local to different source and receiver stations. The end resuit of these static corrections is an improvement in reflection continuity.
At a block 3410, any one of many noise rejection procedures may be applied to the data to improve the signal-to-noise ratio. Some noise rejection options may be simple frequency filters. Others may be more sophisticated tau-p, f-k, or deconvoiution procedures. At block 3410, multiple atténuation may be applied to attenuate noise attributable to multiples.
As described, multiple methods are available for processing the data to identify SV-P mode data and use it for generating an image, such as Method 1 and Method 2 described above. If Method 1 Is used, at a block 3412, the processing circuit is configured to stack (or sum) P-P, SV-P positiveoffset and SV-P negative-offset data separately using either CCP coordinates or ACP coordinates. At a block 3414, the processing circuit is configured to sum SV-P positive-offset and SV-P négative offset stacks. Block 3414 may use a CCP binning process. At a block 3416, the processing circuit is configured to migrate post-stack data to make four images: a P-P Image, an SV-P positive offset Image, an SV-P negative-offset Image and an SV-P summed image.
If Method 2 is used, at a block 3420, the processing circuit Is configured to do separate pre-stack time migrations, depth migrations, or reverse-time migrations of P-P, SV-P positive offset data and SV-P negative-offset data and, at a block 3422, sum SV-P positive-offset and SV-P negative-offset images.
At block 3418, an operator views the images created by either or both of Method 1 and Method 2 and makes a détermination as to whether the image quality is acceptable. If not, the process retums, for example to block 3406 for further processing. An operator may adjust static corrections, recalculate velocities, etc. Altematively, block 3418 may be automated to not require a person to make the détermination, but rather to hâve the processing circuit make the détermination based on certain image goals.
Data Processing In Hlgh-Velocity Earth Surface
Referring now to FIG. 35, a flow diagram illustrating a method 3500 of processing vertical sensor data for high-velocity Earth surface will be described. The method 3500 may use similar techniques to those described above with reference to FIGs. 20 and 34, which contains further expianation of some ofthe processing procedures described in FIG. 35. As explained previously, In high-velocity Earth surface situations, upgoing SV data can be detected by a vertical-force source, meaning that the data that can be processed into images now Indudes the SV-SV mode and the P-SV mode.
At a block 3502, a processing circuit is provided with mixed P-P, SV-SV, P-SV and SV-P modes in vertical-sensor data from acquisition steps described previously. At block 3504, the processing circuit is configured to or programmed to segregate, separate or otherwise remove P-P, SV-SV, PSV and SV-P mode data by applying velodty fiiters to reject or filter out improper wave-mode propagation velocities.
At a block 3506, the processing circuit is configured to détermine NMO, stacking and/or migration velodties for P-P, SV-SV, P-SV and SV-P modes. Separate velocity analyses are required for positive-offset P-SV and SV-P data and for négative offset P-SV and SV-P data.
At a block 3508, static corrections are applied to improve reflector alignment, as described with reference to block 3408. At a block 3510, any one of many noise rejection procedures may be applied to the data to improve the signal-to-noise ratio. Some noise rejection options may be simple frequency fiiters. Others may be more sophisticated tau-p, f-k, or deconvolution procedures. At block 3510, multiple atténuation may be applied to reduce noise attributable to multiples.
As described, multiple methods are available for processing the data to identify SV-P mode data and use it for generating an image, such as Method 1 and Method 2 described above. If Method 1 is used, at a block 3512, the processing circuit Is configured to stack (or sum) P-P, SV-P positiveoffset and SV-P negative-offset data and P-SV positive-offset data and P-SV negative-offset data, each to be stacked separately. At a block 3514, the processing circuit is configured to sum SV-P positive-offset and SV-P négative offset stacks and separately sum P-SV positive-offset and P-SV negative-offset stacks. At a block 3516, the processing circuit Is configured to migrate post-stack data to make eight images: a P-P image, an SV-P positive offset image, an SV-P negative-offset image, an SV-SV Image, a P-SV positive offset image, a P-SV négative offset image, P-SV summed image and an SV-P summed image.
If Method 2 Is used, at a block 3520, the processing circuit Is configured to do separate pre-stack time migrations, depth migrations, or reverse-time migrations of P-P, SV-SV, SV-P and P-SV positive offset data and SV-P and P-SV negative-offset data and, at a block 3522, sum SV-P positive-offcet and SV-P negative-offset Images.
At block 3518, an operator views the images created by either or both of Method 1 and Method 2 and makes a détermination as to whether the image quatity Is acceptable. If not, the process retums, for example to btock 3506 for further processing. An operator may adjust static corrections, recalculate velocitles, etc. Altematively, block 3518 may be automated to not require a person to make the détermination, but rather to hâve the processing circuit make the détermination based on certain image goals.
As illustrated in a comparison of Figures 20, 34 and 35, it is not necessary ln the methods of Figures 34 and 35 to change the polarity of negative-azimuth SV-P data to agréé with the polarity of positive-azimuth SV-P data when dealing with vertical-sensor data. Also, two separate velocity analyses are performed when processing SV-P data as ln the methods of Figures 34 and 35 because that imagïng is based on common-conversion point concepts, not on common-midpoint concepts as used in the methods of Figure 20. ln the methods of Figures 34 and 35, one velocity analysis Is done for positive-azimuth data and a second analysis Is done for negative-azimuth data (as explained with reference to Figure 27).
Extracting Shear Wave Information from Towed Cable Marine Seismic Data
According to one or more embodiments, S-wave information can be extracted from towed-cable marine data when certain data-processing steps are Implemented by a data processor.
ln some embodiments, a single-component compressional P wave sensor Is used as a receiver to receive both P-P and SV-P modes.
ln some embodiments, multi-component sensors are not needed.
in some embodiments, the single-component compressional P wave sensor Is disposed ln the water well above the sea floor, within the water column, for example being towed behind a boat. The single-component compressional P wave sensor may be similarfy disposed. ln some embodiments, neither the P wave source nor P wave receiver are disposed on, In contact with, or within the seafloor.
In some embodiments, an SV-P mode is sensed in a marine environment and processed to generate a Visual image of one or more formations beneath the sea floor.
In some embodiments, a virtuai source and/or virtuai receiver are used in the acquisition of the seismic data, wherein the virtuai source or receiver Is computationally derived from data from an actual source or receiver, respectively.
In some embodiments, a single-component or one-component P wave source towed by a boat generates a downgoing P wave which upon contact with the seafloor generates a downgolng SV shear wave mode directly at the point of contact of the P wave with the seafloor, at the seafloor surface. In some embodiments, this downgolng SV mode is not a converted shear mode created by reflectlons of a downgoing P mode off formations below the sea floor, but Is Instead an SV mode generated directly at the point of contact of the P wave with the seafloor.
In some embodiments, Image processing is based on towed-cable marine data In which there are no receivers other than those In the towed cable.
Marine Seismic Sources
Marine seismic data are generated by towing a seismic source below the sea surface. Although some seismic sources, primarily shear-wave generators, hâve been devised that function on the seafloor, seafloor-positioned sources are generally not used to generate seismic reflection data because of deployment challenges and environmental régulations that protect seafloor biota. Thus, marine seismic data acquisition typically involves sources that can be towed at a desired depth below the sea surface (e.g., 3 to 15 meters or other depths).
One energy source that may be used in marine environments is a towed air gun. Air gun sources can be a single air gun, an array of air guns, or several arrays of air guns with each array containing numerous air guns. Sources other than air guns can be encountered when legacy marine data are considered. Among source types that may be used to acquire marine seismic data are vibrators, explosives, sparkers, and various mechanisms that produce impulsive wavelets in the water column. The embodiments described herein may use any types of source, such as towed sources, used to generate marine seismic reflection data.
Marine Seismic Sensors
Marine seismic data may be recorded by towing an array of hydrophones below the sea surface. These hydrophones are embedded In one or more long cables that trail behind a seismic recording boat. Geophones and/or accelerometers are used in some towed-cable Systems. Marine seismic data can also be acquired with stationary sensors placed on the seafloor. Stationary seafloor sensors typically involve combinations of hydrophones and geophones or combinations of hydrophones and accelerometers. The embodiments described herein may use any type of sensor, 5 such as towed-cable sensors, whether the sensors comprise hydrophones, geophones, accelerometers, etc.
Virtual Sources and Receivers
Referring now to FIG. 38, a diagram illustrâtes exemplary components of a marine seismic dataacquisition System and raypaths of compressional (P) and vertical shear (SV) seismic modes to generated during seismic Illumination of sub-seafloor geology. P-wave raypaths are shown as solid lines. S-wave raypaths are shown as dashed lines. A source 3800 is towed by a boat 3802. Only P waves propagate in the water iayer because water has a shear modulus of zéro and cannot support shear-mode propagation. When the downgoing P mode 3800 produced by a marine energy source impinges on the seafloor 3804 at any Incident angle other than true vertical, two downgoing 15 modes—a P mode 3806 and an SV mode 3808—are created at the seafloor interface 3804 and continue to propagate downward and illuminate sub-seafloor targets, such as target 3812. The downgoing P raypath 3800 In the water layer 3812 originales at a real seismic source 3800. The origin point 3810 of the downgoing SV raypath at the seafloor is a virtual seismic source. The acquisition and processing described herein exploits the downgoing SV mode 3808 produced at m virtual-source coordinates along seafloor 3804.
The embodiment of Figure 38 may use any type of towed marine energy sources, any type of seismic sensors, and may use sensor stations that are towed in the water layer and/or stationary sensors on the seafloor.
Referring now to Figure 39, a simplified version of the diagram of Figure 38 illustrâtes the wave 25 physics of exemplary embodiments.
- A is the real seismic source where a downgoing P wave Is generated.
• B is the position of the virtual source on the seafloor where, by downward wavefield extrapolation, the downgoing P wave from source A segregates into downgoing P and SV transmitted wave modes and an upgoing P reflected mode. The upgoing P so reflection from seafloor coordinate 3810 Is not shown.
- C is a reflection point from a sub-seafloor target where the downgoing SV from virtual source B créâtes an upgoing P reflection event, as described herein with référencé to, for example, Figures 21 through 25,27, etc.
• D is the position of a virtuai receiver created when the upgoing P reflection recorded by towed-sensor E is projected downward to the seafloor by wavefield extrapolation, as will be described below.
E Is a real, towed receiver that records the upgoing P reflection from target point C.
Downward Wavefield Extrapolation
As illustrated in Figure 39, real source A generates a downgoing P wave that reaches the seafloor and créâtes a virtuai source. Any coordinate along a raypath associated with a propagating seismic wave mode can be defined as the position of a virtuai source or a virtuai receiver for that wave mode. For this reason, the position of a virtuai source In this application may io be defined by downward extrapolation of a seismic wavefield from the position of an actual towed marine seismic source to a desired source-origin point on or near the seafloor, and the position of a virtuai sensor may be defined by extrapolating a seismic wavefield downward from a real towed seismic receiver to a preferred location for that receiver on or near the seafloor. For an explanation of recent virtuai source/receiver principles, see, for example, U.S. Patent No. 7,706,211 to Bakulin 15 et al. titled Method of Determining a Seismic Velocity Profile and U.S. Patent Application
Publication No. 2010/0139927 published June 10, 2010 to Bakulin et al. titled Method of Imaging a Seismic Source Involving a Virtuai Source, Methods of Produdng a Hydrocarbon Fluid, and a Computer Readable Medium. Similarly, the SV-P wave from virtuai source B is received at point D, which may be a virtuai receiver. Point D becomes a virtuai receiver by way of wavefield extrapolation processing. Downward wavefield extrapolation may be used to transform data generated by a real source and recorded by a real receiver to data équivalent to that generated by a deeper source and recorded by a deeper receiver. In this manner, virtuai sources and virtuai receivers may be computationally, numerically, or mathematically created, though In alternative embodiments other techniques may be used.
Downward wavefield extrapolation Is used for wave-equation migration of seismic data, whether migration is done in the depth domain or in the Image-time domain. In one embodiment, wavefield extrapolation may be Implemented as described In Wapenaar, C.PA, and A. J. Berkhout, 1989, Elastic wavefield extrapolation—redatuming of single- and muiti-component seismic data: Elsevier Science, 468 pages. The principles of wavefield extrapolation and computational procedures used to perform the data transformations described in Wapenaar may be used in an exemplary embodiment. The processing of waveforms may comprise redatuming sources and receivers, and redatuming that applies to S wavefields as well as P wavefields. In another embodiment, the wavefield extrapolation process of U.S. Patent No. 7,035,737 to Ren, J., 2006, Method for seismic wavefield extrapolation, may be used. The portions of this patent describing how to do wavefield extrapolation using a variable extrapolation step size followed by phase-shifted linear interpolation of the extrapolated wavefield are expressly incorporated herein by reference. Alternative methods and procedures of wavefield extrapolation may be used in one or more of the embodiments described herein, and reference to wavefield extrapolation herein Is not to be construed as limiting to any particular method or algorithm.
According to some embodiments, wavefield extrapolation may refer to any process by which the downgoing, P-only, wavefield produced by a towed marine seismic source Is computationally or numericaliy replaced by downgoing P and SV wavefieids produced by a virtual source at an io interface iiluminated by the downgoing, real-source, P-wavefield. Wavefield extrapolation may also refer to any process by which the upgoing, P-only wavefield received at towed receiver E is computationally replaced by virtual receiver D on the seafloor. ln one embodiment, the interface where a virtual source should be computationally positioned is the seafloor. However, according to an exemplary embodiment, a virtual source could be computationally positioned below the seafloor 15 or even above the seafloor as long as the medium below the source station physically has, or is numericaliy assigned, a non-zero shear modulus that will allow a downgoing SV mode to propagate.
Referring to Figure 39, downward wavefield extrapolation is used in this embodiment to migrate data generated by real towed-source A and recorded by real towed-receiver E downward so that 20 the data are transformed to data that would hâve been generated by virtual-source B on the seafloor and recorded by virtual-receiver D also on the seafloor.
Marine Shear Waves
An example of a P-SV refiection is shown on Figure 38 by the downgoing P raypath 3806 from the towed source that converts to an upgoing SV raypath 3816 at refiection point RP2. Because S25 waves cannot propagate in water, this upgoing SV mode must be recorded by a multicomponent sensor, preferably a 4-component (4C) sensor package that has horizontal geophones or accelerometers and is deployed on the seafloor at position 4C3.
According to one embodiment, a System and method involves acquiring and processing an SV-P mode in a marine seismic application, which is an event comprising a downgoing SV raypath 30 produced at the virtual seafloor source position 3810 that converts to an upgoing P raypath at refiection point RP1. ln Figure 38, the SV-P mode is illustrated for example by SV raypath 3808 and P raypath 3814. An SV-P mode is the inverse of the P-SV mode utilized by marine geophysicists. Because this upgoing P raypath extends upward to towed sensor H1, SV-P data are embedded In conventional towed-cable marine data (e.g., legacy data). No seafloor sensor Is required to capture SV-P data, although the technology applies if seafloor sensors are used rather than towed-cable sensors.
PosItlve-Offset and Negatlve-Offset Data
Raypaths involved in positive-offset and negative-offset marine SV-P imaging are illustrated on Figure 40. VP and Vs velocities in Fades A are different than they are in Fades B. Straight raypaths are drawn for simplidty.
In this diagram, SV-P data generated at virtuai source A and recorded at virtual receiver A are labeied SVA for the downgoing SV mode and PA for the upgoing P mode. The offset diredion from virtual source A to virtuai receiver A is arbitrarily defined as positive offset. When the positions of source and receiver are exchanged, creating virtual source B and virtual receiver B, the source-torecelver offset diredion reverses and Is defined as négative offset. The raypath for negative-offset SV-P data is labeied SVB for the downgoing SV mode and PB for the upgoing P mode. The polarities shown for the downgoing SV partide-displacement vedor conform to the polarity convention established by Aki and Richards (1980) and documented by Hardage et al. (2011). Note that for both positive-offset data and negative-offset data, the vertical component of the partidedisplacement vedors for the upgoing P modes are In the same diredion (pointing up), hence there is no change in SV-P data polarity between positive-offset data and negative-offset data.
The considération of positive-offset and negative-offset data is used in land-based seismic data acquisition where receivers extend in all azimuths away from a source point. The possibiiity of positive-offset and negative-offset data is also considered for marine seismic data. Most towedcable marine seismic data involve only positive-offset data because the source Is usuaily positioned in front ofthe receiver cable (Fig. 41 at (a)). However, a source couid be attached to a separate boat trailing at the rear of a towed receiver cable (Fig. 41 at (b)). In such a case, the data would be negative-offset data. In modem marine surveys, source boats often précédé and trait towed cables as shown on Figure 41 at (c), and the recorded data then Involve both positive-offset and negativeoffset data.
SV-P Velocity Analysis
One or more embodiments described herein may comprise performing a velocity analysis as a data-processing step when constructing seismic images. When converted modes are involved, two velocity analyses can be done—one analysis for positive-offset data and a second analysis for negative-offset data. The reason for this dual-offset-domain velodty analysis is illustrated on Figure 40 which shows two distinct rock fades A and B between two source and receiver stations.
Laterally varying rock conditions such as shown on this diagram are found in many marine basins. For purposes of illustration, assume the P and S velodties in Faciès A are significantly different from the P and S velodties in Fades B. The travel time required for a positive-offset SV-P event to travel raypath SVa-Pa is not the same as the travel time for a negative-offset SV-P event to travel raypath SVb-Pb· This différence in travel time occurs because the SV* mode is totaliy In Fades A, but the SVB mode is almost entirely in Fades B, Likewise, ail of mode PB Is in Fades A, but mode PA has significant travel paths Inside both Faciès A and Fades B. Because travel times differ In positive-offset and negative-offset directions, seismic intervai velodties determined from positiveoffset data differ from interval velodties determined from negative-offset data. Thus, in some embodiments, one velodty analysis is done on positive-offset data, and a separate velodty analysis is done for negative-offset data.
Figure 42 illustrâtes SV-P and P-SV CCP imaging prindples. Curve CCP1 shows the trend of common-conversion points for P-SV data. Curve CCP2 shows the trend of common-conversion points for SV-P data. ACP1 and ACP2 are asymptotic conversion points for trends CCP1 and CCP2, respectively. CCP1 and CCP2 are mirror images of each other relative to the common midpoint CMP for this source-receiver pair.
Constructlng SV-P Images
The processing of SV-P data for generating SV-P images can be done in a number of ways, such as: (1) by common-conversion-point (CCP) binning and stacking of SV-P reflections, followed by post-stack migration of the stacked data, or (2) by implementing prestack migration of SV-P reflections. Method 2 (prestack migration) is a more rigorous approach; method 1 (CCP binning/stacking and post-stack migration) is lower cost. To perform CCP binning and migration of SV-P data, CCP coordinates of SV-P image points relative to this common-midpoint between a source and a receïver are mirror images of CCP Image points assodated with P-SV data, as illustrated on Figure 42. The SV-P data-processing strategy may be based on this mlrror-image symmetry of CCP Image-point profiles for P-SV and SV-P modes.
Because positive-offset and negative-offset SV-P data hâve different velodty behaviors, two separate CCP binning/stacking steps are done to croate an SV-P stacked image. In Step 1, positive-offset data are binned and stacked Into an image using velodties determined from positiveoffset data, and In Step 2, negative-offset data are binned and stacked into a second image using velodties determined from negative-offset data. The final SV-P image is the sum of these two images. This same dual-lmage strategy may impiemented when binning and stacking P-SV marine data. The three stacked images (positive-offset, negative-offset, and summed offsets) can be mlgrated and used in geologicai applications. As documented by Hardage et al. (2011) relative to P-SV imaging, some géologie features are sometimes better seen in one of these three images than in Its two companion images. Thus ail three stacked and migrated SV-P images may be used In geologicai interprétations.
Marine SV-P Data Processing: Imaging Method 1—CCP Binnlng, Stacking, and Post-Stack Migration
Some commercial seismic data-processing software that can be purchased or leased by the geophysical community can calculate converted-mode Image coordinates called asymptotic conversion points, which are abbreviated as ACP. Two examples are Vista seismic data processing software, sold by Geophysical Exploration & Development Corporation, Alberta, Canada and ProMAX seismic data processing software, sold by Halliburton Company, Houston, Texas. Such software calculâtes converted-mode image coordinates called asymptotic conversion points, which are abbreviated as ACP. An ACP is an image coordinate where the trend of correct CCP image points for a spécifie source-receiver pair becomes quasl-verticai (Fig. 42). Deep geology Is correctly Imaged using P-SV data binned by ACP prindples, and would also be correctly imaged by SV-P data binned using ACP concepts that are adjusted for SV-P data. However, shallow geology is not correctly imaged for either P-SV data or SV-P data when ACP binnlng methods are used. True CCP binning can produces correct stacked images of both shallow and deep geology for converted modes appropriate for post-stack migration. On Figure 42, the asymptotic conversion point for the P-SV mode is labeled ACP1, and the asymptotic conversion point for the SV-P mode is labeled ACP2. Neither image point is correct except where their associated CCP binning profile is quasi-vertical (i.e., for deep targets). As has been emphasized, these two image points are mirror images of each other relative to the common midpoint (point CMP on Figure 42) for any source-receiver pair involved in a seismic survey.
One exemplary method of producting CCP or ACP binning for marine SV-P data comprises adjusting software that performs CCP binning for marine P-SV data so that the coordinates of sources and receivers are exchanged when determining image-point coordinates. Referring to the source-receiver pair drawn on Figure 42, an exchange of station coordinates has the effect of moving the receiver station to the source station and the source station to the receiver station. Software used to process P-SV data will then calculate the image point trend labeled CCP2 rather than the trend labeled CCP1. Using coordinates specified by profile CCP2 to bin marine SV-P reflections extracted from marine towed-sensor data will produce SV-P images, which should be equal in quality to what is now achieved with marine P-SV data.
Marine SV-P Data Processing: Imaging Method 2—Prestack Migration
According to an alternative embodiment, prestack migration can be done to create a tlme-based seismic image or a depth-based seismic image. Referring to Figure 43, prestack migration can be done by numericaliy propagating a spécifie seismic wavefield downward from each source station to illuminate géologie targets, and then numericaliy propagating a spécifie seismic wavefield upward from reflecting interfaces to each receiver station.
The spécifie wavefields used in prestack migration may be created by applying velocity filters to seismic data so that reflection events having only a predetermlned velocity behavior remain after velocity fiitering. Velocity wavefields are listed in the table of Figure 43. The spécifie velocity behavïors of interest In this exemplary embodiment are those downgoing and upgoing velocities associated with P-P and SV-P seismic modes. These modes are listed as option 1 and option 3 on Figure 43. The resuit of prestack migration is an image of géologie Interfaces seen by each spécifie seismic mode (P-P and SV-P). For slmplidty, only one source station and only one receiver station are shown on Figure 43.
As indicated by the table on Figure 43, prestack time migration, depth migration, or reverse-time migration processing can create a SV-P Image If the velocity of the downgoing wavefield ls that for a propagating SV wavefield and the velocity of the upgoing wavefield ls that for a P wavefield.
in Figure 43, a time-space distribution of velocities for a spécifie seismic mode is defined so that a spécifie downgoing wavefield (D) can be propagated through this Earth velocity model from every source station to Illuminate targets. A second time-space distribution of velocities for a second spécifie seismic mode is then Imposed to propagate that spécifie upgoing wavefield (U) to every receiver station. The combinations of downgoing and upgoing velocities that can be implemented for towed-cable marine seismic In this exemplary embodiment involve options 1 and 3 listed in the table.
Prestack Time Migration
Prestack time migration of seismic data may be done by constructing common-source trace gathers and calculating where individual data points In each trace of each shot gather need to be positioned in seismic image space. An exemplary calculation is illustrated in Figure 44. In this diagram, S is the position of a source station in migrated Image space, R is the position of a spécifie receiver station in migrated image space, and A ls the position of an Image point that is being constructed.
The position of Image point A is defined as space-time coordinates (X*,t). To perform prestack time migration, coordinate XA is defined by a data processor, and time coordinate t then ls incremented from 0 to îmax. where îmax is the length of the migrated data trace. The diagram shows the migration of only one data point from only one trace of only one shot gather. The objective is to calculate the time coordinate T of the data sample from the S-to-R data trace that needs to be placed at image-space coordinates (Xa, t).
The calculation is done by the two square-root équations shown on Figure 44 and shown below:
ln which:
A=lmage point t=image-trace time coordinate
XA=lmage-trace coordinate
DsA=Horizontal distance from S to A
Dar= Horizontal distance from A to R
TsA-One-way time from S to A
TAR=One-way time from A to R
Vsa-RMS velocity for downgoing mode at (Xa, t)
Var=RMS velocity for upgoing mode at (X*, t)
T=TsA+TAR=Time coordinate of data sample placed at Image coordinates (X*, t)
Figure 44 illustrâtes the double square root calculation used in prestack time migration of seismic data. Image coordinate Xa Is defined by the data processor. Image time t varies from zéro to the maximum time coordinate of the migrated data. Velocities Vsa and Var are rms velocities determined by a separate velocity analysis and preserved ln a file that can be accessed to calculate time coordinate T of the data sample that needs to be moved to Image coordinate at (XA, t).
One square-root équation calculâtes one-way time Tsa for the downgoing raypath from S to A. The second square-root équation calculâtes the one-way time Tar for the upgoing raypath from A to R. The time coordinate T of the data sample from shot-gather trace S-to-R which needs to be placed at migration coordinates (Xa, t) is the sum of Tsaand Tar. This prestack time-migration procedure ls called the double square-root calculation. An assumption built into the calculation is that down and up one-way travel times can be represented as travel times along straight, not curved, raypaths.
Another view of prestack time migration is shown as Figure 45. This diagram illustrâtes a process of prestack time migration, according to an exemplary embodiment. In step 1, a data processor or processing circuit is configured to select from a memory a particular data trace recorded by receiver R of a particular Shot Record for performing prestack time migration. Image coordinate XA defined by the data processor may or may not coindde with the position of a receiver station. In this example, Χλ is not coïncident with a receiver station. In step 2, the data processor is configured to build one migrated image trace at image-space coordinate XA. Image-time coordinate t ls a time coordinate of this migrated data trace. Raypaths SA and AR shown relative to step 2 are the raypaths from Figure 44.
In step 3, the data processor ls configured to access from memory a velodty file that defines rms velodties at every coordinate in the migrated Image space. In step 4, one-way travel times Tsa and Tar defined by the square-root équations on Figure 44 are calculated to define the time coordinate T of the Input data trace that needs to be moved to image coordinates (Xa, t). In step 5, the data processor is configured to move the data sample from shot-gather data space to migrated image space.
Referring nowto FIG. 46, a System and method for processing marine SV-P data is shown, according to an exemplary embodiment. This System is configured to produce (1) trace gathers, and (2) Images of sub-seafloor geology that describe S-wave propagation through Imaged strata. At block 1, towed-cable seismic data are retrieved from a storage device or memory. The seismic data may hâve been acquired using any of the processes described herein, such as those described with reference to FIGs. 38,39 and/or 41. As stored in the storage device, the seismic data may comprise P-P data as well as shear mode data, such as SV-P data, said P-P and SV-P data having been received through a towed receiver or other sensor configured to measure compresslonal P waves to generate the seismic data.
At block 2, the data processor is configured to extrapolate the P wavefields of the seismic data downward to create virtual sources and virtual receivers on the seafloor, for example as described above with reference to Figure 39. At block 3, the data processor is configured to perform data conditioning steps, such as frequency filtering, deconvolution, de-multiple, spectral whîtening and/or otherdata conditioning processesthat adjust the appearance ofseismic data. Deconvolution may refer to a numerical process that restores the shape of a seismic wavelet to the shape it had before it was distorted by interfering wavelets or by any phase and amplitude changes caused by sensor responses, equipment filtering, background noise, etc. De-multiple may refer to a numerical process that removes interbed multiple reflections from seismic data. De-multiple is one type of deconvolution, i.e., the removal of Interfering wavelets. Spectral whitening may refer to a process 5 of adjusting the frequency spectrum of a seismic wavelet so that the spectrum is as fiat as possible over the widest possible frequency range. Wide, fiat spectra resuit in compact time wavelets that hâve optimal resolution. At block 4, the data processor is configured to détermine SV-P velodties separateiy for positive-offset data and negative-offset data if the sources were positioned in front of and behlnd towed recelvers during the acquisition of the data being processed, as described for io example with référencé to Figures 40 and 41 herein.
As described above, two illustrative image processing methods are described herein, though others may be used. In a first imaging option, at block 5, the data processor Is configured to create separate CCP stacks for positive-offset and negative-offset SV-P data. At block 6, the data processor may be configured to sum the positive-offset and negative-offset SV-P stacks. At block 15 7, the data processor may be configured to appiy any desired data conditioning steps, such as those described above with référencé to block 3. At block 8, the data processor Is configured to migrate post-stack data to make SV-P and P-P Images.
If the second imagïng option Is used, at block 9 the data processor is configured to perform separate prestack migrations for positive-offset SV-P data and negative-offset SV-P data if sources 20 are In front of and behlnd towed receivers (either time domain or depth domain). At block 10, the data processor is configured to sum positive-offset and negative-offset SV-P images. At block 11, the data processor Is configured to appiy any desired data-conditioning steps.
Once an image is made by either image processing option 1 or image processing option 2, that image is difficult to compare against normal towed-cable image because the image uses the 25 seafloor (or near seafloor) as a datum (datum - depth where seismic image time is defined to be zéro), in contrast, towed-cable images use sea level as a datum. The images look significantiy different when the seafloor has considérable slope or topographie relief. Thus the seafloor datum Image can be re-datumed to sea level so image comparisons are easter to do, as shown at block 12. This re-datuming may comprise a time shift of each trace that accounts for the two-way P-wave 30 travel time through the water layer to the seafloor coordinate where each trace is positioned In SVP image space. The SV-P image was created by stripping off the water layer. After SV-P imaging is compieted, the processing can then add the water layer back into the picture.
SV-P Data Acquisition
Refenring now to Figure 47, a diagram of a data acquisition system 4700 and method for acqulring SV-P data In a marine environment wili be described. A marine towed source 4702 is disposed under, near, or about a surface of a marine environment, near sea level 4704. Source 4702 Is towed by a boat while In operation, while transmitting compressional P waves into the water column 4706. Source 4702 Is configured to Impart an Impulsive force to water column 4706 to provide seismic waves to point A on a seafloor 4708. Source 4702 may comprise an air gun or other Impulsive or swept-frequency force sources. In this example, source 4702 produces compressional P mode, but not shear modes (SH and SV) because the shear modulus of water is zéro. However, upon contact, encounter, or impingement of the P mode wavefield with seafloor 4708 at point A, a downgoing P and a downgolng shear wave mode (SV) is produced. In this embodiment, at least some of the SV shear waves are generated at point A and not by sub-seafloor mode conversion at sub-seafloor interfaces within Earth media 4710.
A seismic sensor 4712, in this case a marine towed sensor, is towed by a boat attached to the sensor by a cable, which also may be disposed under, near, or about a surface of the marine environment at sea level 4704. Sensor 4712 Is configured to detect or sense upgoing wavefields, reflected from subsurface sectors, formations, targets of interest, etc. within Earth media 4710 to point B. Upgoing waves within Earth media 4710 comprise P-P waves (P waves downgoing from point A and upgoing to point B) and upgoing SV waves (both SV-SV waves and P-SV waves). The upgoing SV waves cannot propagate through water column 4706 to marine towed sensor 4712 and, therefore, only the upgoing P waves reach marine towed sensor 4712. In this embodiment, sensor 4712 comprises a sensor configured to sense compressional P modes and, as described herein, other modes such as SV-P (e.g., direct SV-P). In one embodiment, sensor 4712 Is a hydrophone, which may be configured to provide an output which has no directional information about the waves being sensed. Various arrays and configurations of sources 4702 and sensors 4712 may be implemented In different embodiments. Towed sources and receivers may be In constant motion throughout the acquisition of seismic data.
In alternative embodiments, marine towed source 4702 and/or marine towed sensor 4712 may Instead by disposed on, at, embedded within or in contact with seafloor 4708. In this case, the sensor may be a vertical-force sensor configured to record a vertical response.
Data sensed by marine towed sensor 4712 are configured to be stored by a suitable processing circuit in a digital media or data storage device 4714, which may be any type of memory or other data storage device described herein. Block 4716 illustrâtes a data processor configured to perforai wavefield extrapolation to create virtual SV source A and virtual P sensor B on seafloor
4708, and/or other processing steps described herein. One or more of the aspects described with reference to FIG. 17 and FIG. 33 may be used with aspects of FIG. 47 In aîtemative embodiments.
Determining S-Wave Velocity
To calculate either of the CCP blnning profiles shown on Figure 42, a data processor may be confîgured to détermine S-wave velocities within the geological layering that is being imaged. If the second option of creating converted-mode images with prestack migration techniques Is used, the data processor uses estimâtes of S-wave velocities within the rocks that are illuminated by the seismic data. Determining the S-wave velocities needed for calculating SV-P image points can be done using techniques for determining S-wave Imaging velocities when processing P-SV data.
Exemplary methods for determining S-wave velocity needed for calculating converted-mode image points Include: 1) using vertical seismic profile data acquired local to the seismic image area to calculate interval values of VP and Vs velocities, 2) using dipole sonie log data acquired local to the seismic image space to détermine VP and Vs velocities, 3) combining laboratory measurements of VP/VS velocity ratios for rock types like those being imaged with seismic-based estimâtes of P15 wave velocities to back-calculate S-wave velocities, 4) calculating CCP blnning profiles for a variety of VP/VS velocity ratios, making separate stacks of converted-mode data for each CCP trend, and examining the sériés of stacked data to détermine which CCP profile produces the best quality image, or other methods. These methods can be used to provide reliable S-wave velocities to use for velocity filtering to define S-wave modes, stacking, and migrating SV-P data.
it is understood that principles, steps, components, or teachings from any of the embodiments described herein may be combined with other embodiments described herein to provide yet further embodiments.
In an alternative embodiment, as taught herein, a downgoing P wave that impinges on point A on the seafloor generates both an SV shear wave mode and an SH shear wave mode. This is because the vertical component of the downgoing P wave can be viewed as a low-energy vertical force source at point A that produces the radiation patterns shown as Figure 6. In this alternative embodiment, seafloor-based sensors, such as 4 component (4C) sensors may be used to receive a variety of upgoing wavemodes and store them in a memory for further processing.
Various embodiments disclosed herein may include or be implemented in connection with so computer-readable media confîgured to store machlne-executable instructions therein, and/or one or more modules, circuits, units, or other éléments that may comprise analog and/or digital circuit components (e.g. a processor or other processing circuit) confîgured, arranged or programmed to perform one or more of the steps recited herein. By way of example, computer-readable media may Include non-transitory media such as RAM, ROM, CD-ROM or other optical disk storage, magnetic disk storage, flash memory, or any other non-transitory medium capable of storing and providing access to desired machine-executable instructions. The use of circuit or module herein Is meant to broadly encompass any one or more of discrets circuit components, analog and/or digital 5 circuit components, integrated circuits, soiid state devices and/or programmed portions of any of the foregoing, including microprocessors, microcontrollers, ASiCs, programmable logic, or other electronic devices. ln various embodiments, any number of sources and receivers may be used, from one to hundreds, thousands, or more.
While the detailed drawings, spécifie examples and particular formulations given describe io exemplary embodiments, they serve the purpose of illustration only. The hardware and software configurations shown and described may differ depending on the chosen performance characteristics and physical characteristics of the computing devices. The Systems shown and described are not limited to the précisé details and conditions disclosed. Furthermore, other substitutions, modifications, changes, and omissions may be made ln the design, operating conditions, and arrangement of the exemplary embodiments without departing from the scope of the présent disclosure as expressed in the appended claims.

Claims (19)

  1. WHAT IS CLAIMED IS:
    1. A method of processing seismic data, the seismic data obtained using a plurality of towed receïvers In a marine environment, the towed receivers configured to measure compressional P waves, comprising:
    δ retrieving seismic data from a storage device using a processing circuit, the seismic data comprising P-P data and shear mode data, wherein the P-P data and shear mode data were both received at the towed receivers without the presence of co-located horizontal singlecorn ponent receivers;
    processing the seismic data to extract SV-P shear mode data using the processing io circuit, wherein the processing comprises extrapolating wavefields represented by the seismic data downward to computationally create virtual sources and virtual receivers on a seafloor in the vicinity of an area Imaged by the seismic data; and generating shear mode image data based on the extracted shear mode data using the processing circuit.
    15
  2. 2. The method of Claim 1, wherein the processing comprises determining velocities that separately correct the normal moveouts of positive-offset SV-P reflections and the normal moveouts of negative-offset SV-P reflections.
  3. 3. The method of Claim 2, wherein the processing comprises creating separate common conversion point stacks for the positive-offset SV-P data and the negative-offset SV-P
    20 data.
  4. 4. The method of Claim 3, wherein the processing comprises summing the common conversion point stacks for the positive-offset SV-P data and the negative-offset SV-P data.
  5. 5. The method of Claim 4, wherein the processing comprises post-stack mlgrating the stacked SV-P data.
    25
  6. 6. The method of Claim 2, wherein the processing comprises separately pre-stack migrating the SV-P data for positive-offset SV-P data and negative-offset SV-P data.
  7. 7. The method of Claim 1, wherein the P-P data and shear mode data were both received at the towed receivers disposed well above the seafloor within the water column without the use of horizontal geophones, the towed receivers configured to receive compressional P waves 30 and not shear waves.
  8. 8. The method of Claim 1, wherein the SV-P data is a resuit of downgoing P waves from towed P wave sources which upon contact with the seafloor generate downgoing SV shear waves directly at the point of contact of the P waves with the seafloor at the seafloor surface.
  9. 9. The method of Claim 1, further comprising:
    transmitting P waves from P wave sources, wherein the P waves upon contact with the seafloor generate downgoing SV shear waves directly at the point of contact of the P waves with the seafloor at the seafloor surface, the downgoing SV shear waves reflecting off sub-seafloor interfaces as SV-P wave modes;
    receiving the SV-P wave modes using the towed receîvers; and storing the SV-P wave modes in the data storage device to achieve the seismic data comprising P-P data and shear mode data.
  10. 10. A system for processing seismic data obtained using a towed receiver, comprising:
    a data storage device to store seismic data comprising P-P data and shear mode data, wherein the P-P data and shear mode data were both received at a towed receiver without the presence of co-located horizontal singie-component receîvers to generate the seismic data; and a processing circuit configured to process the seismic data to extract SV-P mode data and to generate a shear mode image based on the extracted SV-P mode data, wherein the processing circuit is configured to extrapolate wavefields represented by the seismic data downward to computationally create a virtual source and a virtual receiver on a seafloor in the vidnity of an area imaged by the seismic data, wherein the processing circuit is configured to détermine velocities that separately correct the normal moveouts of positive-offset SV-P reflections and the normal moveouts of negative-offset SV-P reflections.
  11. 11. The system of Claim 10, wherein the processing circuit is configured to détermine velocities that separately correct the normal moveouts of positive-offset SV-P reflections and the normal moveouts of negative-offset SV-P reflections.
  12. 12. The system of Claim 11, wherein the processing circuit is configured to calculate separate common conversion point stacks for the positive-offset SV-P data and the negative-offset SV-P data.
  13. 13. The system of Claim 12, wherein the processing circuit is configured to sum the common conversion point stacks for the positive-offset SV-P data and the negative-offset SV-P data.
  14. 14. The system of Claim 13, wherein the processing circuit Is configured to post-stack migrate the SV-P data.
  15. 15. The system of Claim 11, wherein the processing circuit Is configured to separately pre-stack migrate the SV-P data for positive-offset SV-P data and negative-offset SV-P data.
    5
  16. 16. The system of Claim 10, wherein the seismic data were received at the towed receiver disposed well above the seafloor within the water column without the use of multicomponent geophones.
  17. 17. The system of Claim 10, wherein the SV-P mode data Is a resuit of a downgoing P wave from a towed P wave source which upon contact with the seafloor generates a downgoing SV w shear wave mode directly at the point of contact of the P wave with the seafloor at the seafloor surface.
  18. 18. The system of Claim 10, further comprising:
    a P wave source configured to transmit P waves, wherein the P waves upon contact with the seafloor generate a downgoing SV shear wave mode directly at the point of contact of the 15 P wave with the seafloor at the seafloor surface which continues downward to reflect back toward the seafloor surface from a sub-seafloor Interface as an SV-P wave mode;
    a towed receiver configured to receive the SV-P wave mode; and a processing circuit configured to store the SV-P wave mode ln the data storage device to achieve the seismic data.
  19. 20 19. The method of Claim 1, wherein the towed receivers comprise hydrophones.
OA1201400411 2012-03-06 2013-03-04 Extracting SV shear data from P-wave marine data. OA17094A (en)

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