Generalized linear inversion of reflection seismic data

Geophysics ◽  
1983 ◽  
Vol 48 (6) ◽  
pp. 665-676 ◽  
Author(s):  
Dennis A. Cooke ◽  
William A. Schneider
Keyword(s):  
Seismic Data ◽  
Powder River Basin ◽  
Data Sets ◽  
Linear Inversion ◽  
Seismic Line ◽  
Data Set ◽  
Reflection Seismic ◽  
Generalized Linear Inversion ◽  
Impedance Profile ◽  
Inversion Techniques

Generalized linear inversion, sometimes known as model perturbation, nonlinear regression, or inverse modeling, is applied to synthetic and real seismic data sets with the objective of obtaining an impedance profile as a function of time. The impedances solved for are parameterized in a manner that describes the unknown earth using fewer variables than previous seismic generalized linear inversion techniques. In this application only single traces of common‐midpoint (CMP) processed data will be inverted. The method of generalized linear inversion (GLI) presented here is designed to improve on the shortcomings of recursive inversion with respect to relative and absolute scale of the impedance results, resolution of impedance boundaries, and distortion from residual wavelet effects. In obtaining these goals other advantageous aspects of GLI were discovered. For example, it is insensitive to noise in many cases, and it will allow an interpreter to fix the impedance of any number of known lithologies in an interval being inverted. This last property is extremely useful when evaluating a prospect on an otherwise well‐understood seismic line. The GLI method is illustrated on a number of synthetic examples and one field data set from the Powder River basin of Wyoming.

Sparse reflectivity inversion for nonstationary seismic data with surface-related multiples: Numerical and field-data experiments

Geophysics ◽  
2017 ◽  
Vol 82 (3) ◽  
pp. R199-R217 ◽  
Author(s):  
Xintao Chai ◽  
Shangxu Wang ◽  
Genyang Tang
Keyword(s):  
Seismic Data ◽  
Resolution Enhancement ◽  
Synthetic Data ◽  
Data Sets ◽  
Data Set ◽  
Anelastic Attenuation ◽  
Seismic Resolution ◽  
Text Filtering ◽  
The Stability ◽  
Reflectivity Inversion

Seismic data are nonstationary due to subsurface anelastic attenuation and dispersion effects. These effects, also referred to as the earth’s [Formula: see text]-filtering effects, can diminish seismic resolution. We previously developed a method of nonstationary sparse reflectivity inversion (NSRI) for resolution enhancement, which avoids the intrinsic instability associated with inverse [Formula: see text] filtering and generates superior [Formula: see text] compensation results. Applying NSRI to data sets that contain multiples (addressing surface-related multiples only) requires a demultiple preprocessing step because NSRI cannot distinguish primaries from multiples and will treat them as interference convolved with incorrect [Formula: see text] values. However, multiples contain information about subsurface properties. To use information carried by multiples, with the feedback model and NSRI theory, we adapt NSRI to the context of nonstationary seismic data with surface-related multiples. Consequently, not only are the benefits of NSRI (e.g., circumventing the intrinsic instability associated with inverse [Formula: see text] filtering) extended, but also multiples are considered. Our method is limited to be a 1D implementation. Theoretical and numerical analyses verify that given a wavelet, the input [Formula: see text] values primarily affect the inverted reflectivities and exert little effect on the estimated multiples; i.e., multiple estimation need not consider [Formula: see text] filtering effects explicitly. However, there are benefits for NSRI considering multiples. The periodicity and amplitude of the multiples imply the position of the reflectivities and amplitude of the wavelet. Multiples assist in overcoming scaling and shifting ambiguities of conventional problems in which multiples are not considered. Experiments using a 1D algorithm on a synthetic data set, the publicly available Pluto 1.5 data set, and a marine data set support the aforementioned findings and reveal the stability, capabilities, and limitations of the proposed method.

Common-focus point-based target-oriented imaging approach for continuous seismic reservoir monitoring

Geophysics ◽  
2018 ◽  
Vol 83 (4) ◽  
pp. M41-M48 ◽  
Author(s):  
Hongwei Liu ◽  
Mustafa Naser Al-Ali
Keyword(s):  
Seismic Data ◽  
Rock Physics ◽  
Time Lapse ◽  
Velocity Estimation ◽  
Estimation Methods ◽  
Data Sets ◽  
Data Set ◽  
Velocity Models ◽  
Reservoir Monitoring ◽  
Focus Point

The ideal approach for continuous reservoir monitoring allows generation of fast and accurate images to cope with the massive data sets acquired for such a task. Conventionally, rigorous depth-oriented velocity-estimation methods are performed to produce sufficiently accurate velocity models. Unlike the traditional way, the target-oriented imaging technology based on the common-focus point (CFP) theory can be an alternative for continuous reservoir monitoring. The solution is based on a robust data-driven iterative operator updating strategy without deriving a detailed velocity model. The same focusing operator is applied on successive 3D seismic data sets for the first time to generate efficient and accurate 4D target-oriented seismic stacked images from time-lapse field seismic data sets acquired in a [Formula: see text] injection project in Saudi Arabia. Using the focusing operator, target-oriented prestack angle domain common-image gathers (ADCIGs) could be derived to perform amplitude-versus-angle analysis. To preserve the amplitude information in the ADCIGs, an amplitude-balancing factor is applied by embedding a synthetic data set using the real acquisition geometry to remove the geometry imprint artifact. Applying the CFP-based target-oriented imaging to time-lapse data sets revealed changes at the reservoir level in the poststack and prestack time-lapse signals, which is consistent with the [Formula: see text] injection history and rock physics.

Denoising seismic data using the nonlocal means algorithm

Geophysics ◽  
2012 ◽  
Vol 77 (1) ◽  
pp. A5-A8 ◽  
Author(s):  
David Bonar ◽  
Mauricio Sacchi
Keyword(s):  
Seismic Data ◽  
Random Noise ◽  
Seismic Energy ◽  
Real Data ◽  
Spatial Proximity ◽  
Data Sets ◽  
Noise Attenuation ◽  
Nonlocal Means ◽  
Reflection Seismic ◽  
Generally True

The nonlocal means algorithm is a noise attenuation filter that was originally developed for the purposes of image denoising. This algorithm denoises each sample or pixel within an image by utilizing other similar samples or pixels regardless of their spatial proximity, making the process nonlocal. Such a technique places no assumptions on the data except that structures within the data contain a degree of redundancy. Because this is generally true for reflection seismic data, we propose to adopt the nonlocal means algorithm to attenuate random noise in seismic data. Tests with synthetic and real data sets demonstrate that the nonlocal means algorithm does not smear seismic energy across sharp discontinuities or curved events when compared to seismic denoising methods such as f-x deconvolution.

Use of seismic stratigraphy for Minnelusa exploration, northeastern Wyoming

Geophysics ◽  
1984 ◽  
Vol 49 (6) ◽  
pp. 715-721 ◽  
Author(s):  
Reverend Francis D. Raffalovich ◽  
Terrell B. Daw
Keyword(s):  
Seismic Data ◽  
Seismic Stratigraphy ◽  
Synthetic Seismograms ◽  
Powder River Basin ◽  
Paper Briefly ◽  
Seismic Attribute ◽  
Seismic Line ◽  
Processing Techniques ◽  
Sonic Logs ◽  
Section Form

While Minnelusa sands have yielded significant reserves in Wyoming’s Powder River Basin, geologic complexities have made these sands an elusive target. This paper briefly describes the development of a technique which was used successfully in the exploration of Minnelusa sands. This tehnique can be applied to many stratigraphic exploration programs. Sonic logs, which are key logs in defining Minnelusa sands, in the C-H field were used to construct synthetic seismograms. These synthetics were then organized in cross‐section form to define whether a change in Minnelusa sands would yield an identifiable change on the synthetics. The “idealized” seismic response did show an obvious lateral change from upper sand to no upper sand conditions, and a pilot seismic line was shot using a Vibroseis® source. This line, which was shot through the C-H field, successfully showed the updip limits of the upper Minnelusa sands. A subsequent seismic program was acquired and other leads and prospects were identified, including prospects that were drilled and successfully completed in the Rozet area. However, a number of other wells conformed to Murphy’s law. In addition to standard processing techniques, high‐resolution processing and seismic attribute processing was done on some of the seismic data, yielding differing degrees of success. By closely coordinating geologic and geophysical principles, a useful stratigraphic‐seismic methodology was developed which has application to a wide variety of exploration problems. ™Trade and service mark of Conoco Inc.

A robust workflow for performing joint impedance inversion and its applications

2020 ◽  
Vol 8 (1) ◽  
pp. T141-T149
Author(s):  
Ritesh Kumar Sharma ◽  
Satinder Chopra ◽  
Larry R. Lines
Keyword(s):  
Time Domain ◽  
Seismic Data ◽  
Sedimentary Basin ◽  
Vertical Component ◽  
Data Sets ◽  
Data Set ◽  
Matching Process ◽  
Multicomponent Seismic ◽  
Impedance Inversion ◽  
Straightforward Approach

Multicomponent seismic data offer several advantages for characterizing reservoirs with the use of the vertical component (PP) and mode-converted (PS) data. Joint impedance inversion inverts both of these data sets simultaneously; hence, it is considered superior to simultaneous impedance inversion. However, the success of joint impedance inversion depends on how accurately the PS data are mapped on the PP time domain. Normally, this is attempted by performing well-to-seismic ties for PP and PS data sets and matching different horizons picked on PP and PS data. Although it seems to be a straightforward approach, there are a few issues associated with it. One of them is the lower resolution of the PS data compared with the PP data that presents difficulties in the correlation of the equivalent reflection events on both the data sets. Even after a few consistent horizons get tracked, the horizon matching process introduces some artifacts on the PS data when mapped into PP time. We have evaluated such challenges using a data set from the Western Canadian Sedimentary Basin and then develop a novel workflow for addressing them. The importance of our workflow was determined by comparing data examples generated with and without its adoption.

Interpretation of vintage 2D seismic reflection data along the Austrian-Hungarian border: Subsurface expression of the Rechnitz metamorphic core complex

2020 ◽  
Vol 8 (4) ◽  
pp. SQ73-SQ91 ◽  
Author(s):  
Gabor C. Tari ◽  
Ingrid Gjerazi ◽  
Bernhard Grasemann
Keyword(s):  
Seismic Data ◽  
Pannonian Basin ◽  
Metamorphic Core Complex ◽  
Border Zone ◽  
Data Sets ◽  
Core Complex ◽  
Seismic Reflection Data ◽  
Reflection Seismic ◽  
Detachment Faults ◽  
Metamorphic Core

In the border zone between Austria and Hungary, the Miocene extension of the Pannonian Basin was characterized by extreme, large-magnitude upper crustal extension accommodated along low-angle detachment faults. Although some of these prominent normal faults have already been described using 2D seismic data sets and well data on the Hungarian side, we offer the first systematic interpretation using the Austrian and Hungarian vintage seismic data sets acquired in the 1970s and 1980s. The refinement of the previously proposed metamorphic core complex (MCC) style, east-northeast–west-southwest-trending very high-strain extension provides a modern understanding of back-arc extension in this part of the Pannonian Basin system as the result of the collapse of the Alpine orogen. Although previous interpretations could not achieve the subsurface correlation of major structural elements across the border, we did systematically map these for the first time. Numerous exploration wells, drilled on both sides of the border, were integrated with reflection seismic data to differentiate between the lower versus upper plates of the major low-angle detachment faults, including the largest one responsible for the formation of the Rechnitz MCC. Based on our new interpretation, the regionally mapped Rechnitz detachment fault has an unexpectedly large subsurface extent, on the order of 1000 km2. Moreover, the unusually large number of industry 2D seismic profiles (approximately 50) used to map this and other prominent faults, in the Austrian and Hungarian sides, makes the Rechnitz MCC possibly the best constrained one in the world in terms of subsurface definition by reflection seismic data.

3D ray+Born migration/inversion—Part 2: Application to the SEG/EAGE overthrust experiment

Geophysics ◽  
2003 ◽  
Vol 68 (4) ◽  
pp. 1357-1370 ◽  
Author(s):  
Stéphane Operto ◽  
Gilles Lambaré ◽  
Pascal Podvin ◽  
Philippe Thierry
Keyword(s):  
Spatial Resolution ◽  
Seismic Data ◽  
Velocity Model ◽  
Nonuniform Distribution ◽  
Data Sets ◽  
Data Set ◽  
Quantitative Estimates ◽  
3D Processing ◽  
Type Data ◽  
New Formula

The SEG/EAGE overthrust model is a synthetic onshore velocity model that was used to generate several large synthetic seismic data sets using acoustic finite‐difference modeling. From this database, several realistic subdata sets were extracted and made available for testing 3D processing methods. For example, classic onshore‐type data‐acquisition geometries are available such as a swath acquisition, which is characterized by a nonuniform distribution of long offsets with azimuth and midpoints. In this paper, we present an application of 2.5D and 3D ray‐Born migration/inversion to several classical data sets from the SEG/EAGE overthrust experiment. The method is formulated as a linearized inversion of the scattered wavefield. The method allows quantitative estimates of short wavelength components of the velocity model. First, we apply a 3D migration/inversion formula formerly developed for marine acquisitions to the swath data set. The migrated sections exhibit significant amplitude artifacts and acquisition footprints, also revealed by the shape of the local spatial resolution filters. From the analysis of these spatial resolution filters, we propose a new formula significantly improving the migrated dip section. We also present 3D migrated results for the strike section and a small 3D target containing a channel. Finally, the applications demonstrate, that the ray+Born migration formula must be adapted to the acquisition geometry to obtain reliable estimates of the true amplitude of the model perturbations. This adaptation is relatively straightforward in the frame of the ray+Born formalism and can be guided by the analysis of the resolution operator.

scholarly journals Auroral spectral estimation with wide-band color mosaic CCDs

2013 ◽  
Vol 3 (2) ◽  
pp. 753-823
Author(s):  
B. J. Jackel ◽  
C. Unick ◽  
M. T. Syrjäsuo ◽  
N. Partamies ◽  
J. A. Wild ◽  
...  
Keyword(s):  
Low Cost ◽  
Spectral Estimation ◽  
Wide Band ◽  
Data Sets ◽  
Color Information ◽  
Linear Inversion ◽  
Wavelength Resolution ◽  
Inversion Techniques ◽  
Auroral Imaging ◽  
Multiple Detectors

Abstract. Color mosaic CCDs use a matrix of different wide-band micro-filters in order to produce images with several (often three) color channels. These devices are increasingly employed in auroral studies to provide time sequences of two dimensional luminosity maps, but the color information is typically only used for qualitative analysis. In this study we use Backus–Gilbert linear inversion techniques to obtain quantitative measures of effective spectral resolution for multi-channel color mosaic CCDs. These techniques also allow us to explore the possibility of further improvements by modifying or combining multiple detectors. We consider two spectrally calibrated commercial color CCDs (Sony ICX285AQ and ICX429AKL) in order to determine effective wavelength resolution of each device individually, together, and with additional filters. From these results we develop methods to enhance the utility of existing data sets, and propose ways to improve the next generation of low-cost color auroral imaging systems.

Land FWI in the Delaware Basin, west Texas: A case study

2020 ◽  
Vol 39 (5) ◽  
pp. 324-331
Author(s):  
Gary Murphy ◽  
Vanessa Brown ◽  
Denes Vigh
Keyword(s):  
Seismic Data ◽  
Waveform Inversion ◽  
Surface Velocity ◽  
High Signal ◽  
Data Sets ◽  
Data Set ◽  
Low Frequencies ◽  
Near Surface ◽  
Delaware Basin ◽  
West Texas

As part of a wide-reaching full-waveform inversion (FWI) research program, FWI is applied to an onshore seismic data set collected in the Delaware Basin, west Texas. FWI is routinely applied on typical marine data sets with high signal-to-noise ratio (S/N), relatively good low-frequency content, and reasonably long offsets. Land seismic data sets, in comparison, present significant challenges for FWI due to low S/N, a dearth of low frequencies, and limited offsets. Recent advancements in FWI overcome limitations due to poor S/N and low frequencies making land FWI feasible to use to update the shallow velocities. The chosen area has contrasting and variable near-surface conditions providing an excellent test data set on which to demonstrate the workflow and its challenges. An acoustic FWI workflow is used to update the near-surface velocity model in order to improve the deeper image and simultaneously help highlight potential shallow drilling hazards.

Time-lapse acoustic impedance variations during CO2 injection in Weyburn oilfield, Canada

Geophysics ◽  
2019 ◽  
Vol 85 (1) ◽  
pp. M1-M13 ◽  
Author(s):  
Yichuan Wang ◽  
Igor B. Morozov
Keyword(s):  
Oil Recovery ◽  
Seismic Data ◽  
Acoustic Impedance ◽  
Time Lapse ◽  
Time Shift ◽  
Co2 Injection ◽  
Inversion Method ◽  
Data Sets ◽  
Storage Site ◽  
Data Set

For seismic monitoring injected fluids during enhanced oil recovery or geologic [Formula: see text] sequestration, it is useful to measure time-lapse (TL) variations of acoustic impedance (AI). AI gives direct connections to the mechanical and fluid-related properties of the reservoir or [Formula: see text] storage site; however, evaluation of its subtle TL variations is complicated by the low-frequency and scaling uncertainties of this attribute. We have developed three enhancements of TL AI analysis to resolve these issues. First, following waveform calibration (cross-equalization) of the monitor seismic data sets to the baseline one, the reflectivity difference was evaluated from the attributes measured during the calibration. Second, a robust approach to AI inversion was applied to the baseline data set, based on calibration of the records by using the well-log data and spatially variant stacking and interval velocities derived during seismic data processing. This inversion method is straightforward and does not require subjective selections of parameterization and regularization schemes. Unlike joint or statistical inverse approaches, this method does not require prior models and produces accurate fitting of the observed reflectivity. Third, the TL AI difference is obtained directly from the baseline AI and reflectivity difference but without the uncertainty-prone subtraction of AI volumes from different seismic vintages. The above approaches are applied to TL data sets from the Weyburn [Formula: see text] sequestration project in southern Saskatchewan, Canada. High-quality baseline and TL AI-difference volumes are obtained. TL variations within the reservoir zone are observed in the calibration time-shift, reflectivity-difference, and AI-difference images, which are interpreted as being related to the [Formula: see text] injection.

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