Improving Q estimates from seismic reflection data using well‐log‐based localized spectral correction

Geophysics ◽  
2004 ◽  
Vol 69 (6) ◽  
pp. 1521-1529 ◽  
Author(s):  
Chris L. Hackert ◽  
Jorge O. Parra
Keyword(s):  
Seismic Reflection ◽  
Synthetic Data ◽  
Correction Method ◽  
South Florida ◽  
Test Case ◽  
Well Log ◽  
Seismic Line ◽  
Seismic Reflection Data ◽  
Reflection Data ◽  
Q Values

Most methods for deriving Q from surface‐seismic data depend on the spectral content of the reflection. The spectrum of the reflected wave may be affected by the presence of thin beds in the formation, which makes Q estimates less reliable. We incorporate a method for correcting the reflected spectrum to remove local thin‐bed effects into the Q‐versus‐offset (QVO) method for determining attenuation from seismic‐reflection data. By dividing the observed spectrum by the local spectrum of the known reflectivity sequence from a nearby well log, we obtain a spectrum more closely resembling that which would be produced by a single primary reflector. This operation, equivalent to deconvolution in the time domain, is demonstrated to be successful using synthetic data. As a test case, we also apply the correction method to QVO with a real seismic line over a south Florida site containing many thin sandstone and carbonate beds. When corrected spectra are used, there is significantly less variance in the estimated Q values, and fewer unphysical negative Q values are obtained. Based on this method, it appears that sediments at the Florida site have a Q near 33 that is roughly constant from 170‐ to 600‐m depth over the length of the line.

Automated stacking of seismic reflection data based on nonrigid image matching

Geophysics ◽  
2018 ◽  
Vol 83 (3) ◽  
pp. V171-V183 ◽  
Author(s):  
Sönke Reiche ◽  
Benjamin Berkels
Keyword(s):  
Image Matching ◽  
Seismic Reflection ◽  
Synthetic Data ◽  
Real Data ◽  
Seismic Line ◽  
Seismic Reflection Data ◽  
Velocity Models ◽  
Reflection Data ◽  
Seismic Image ◽  
Matching Techniques

Stacking of multichannel seismic reflection data is a crucial step in seismic data processing, usually leading to the first interpretable seismic image. Stacking is preceded by traveltime correction, in which all events contained in a common-midpoint (CMP) gather are corrected for their offset-dependent traveltime increase. Such corrections are often based on the assumption of hyperbolic traveltime curves, and a best fit hyperbola is usually sought for each reflection by careful determination of stacking velocities. However, assuming hyperbolic traveltime curves is not accurate in many situations, e.g., in the case of strongly curved reflectors, large offset-to-target-ratios, or strong anisotropy. Here, we found that an underlying model parameterizing the shape of the traveltime curve is not a strict necessity for producing high-quality stacks. Based on nonrigid image-matching techniques, we developed an alternative way of stacking, both independent of a reference velocity model and any prior assumptions regarding the shape of the traveltime curve. Mathematically, our stacking operator is based on a variational approach that transforms a series of seismic traces contained within a CMP gather into a common reference frame. Based on the normalized crosscorrelation and regularized by penalizing irregular displacements, time shifts are sought for each sample to minimize the discrepancy between a zero-offset trace and traces with larger offsets. Time shifts are subsequently exported as a data attribute and can easily be converted to stacking velocities. To demonstrate the feasibility of this approach, we apply it to simple and complex synthetic data and finally to a real seismic line. We find that our new method produces stacks of equal quality and velocity models of slightly better quality compared with an automated, hyperbolic traveltime correction and stacking approach for complex synthetic and real data cases.

scholarly journals Hydraulic fracturing in thick shale basins: problems in identifying faults in the Bowland and Weald Basins, UK

2016 ◽  
Author(s):  
David K. Smythe
Keyword(s):  
Hydraulic Fracturing ◽  
Seismic Reflection ◽  
Upper Jurassic ◽  
Normal Faults ◽  
Regulatory Regime ◽  
Seismic Line ◽  
Seismic Reflection Data ◽  
Reflection Data ◽  
Unconventional Resource ◽  
The Uk

Abstract. North American shale basins differ from their European counterparts in that the latter are one to two orders of magnitude smaller in area, but correspondingly thicker, and are cut or bounded by normal faults penetrating from the shale to the surface. There is thus an inherent risk of groundwater resource contamination via these faults during or after unconventional resource appraisal and development. US shale exploration experience cannot simply be transferred to the UK. The Bowland Basin, with 1900 m of Lower Carboniferous shale, is in the vanguard of UK shale gas development. A vertical appraisal well to test the shale by hydraulic fracturing (fracking), the first such in the UK, triggered earthquakes. Re-interpretation of the 3D seismic reflection data, and independently the well casing deformation data, both show that the well was drilled through the earthquake fault, and did not avoid it, as concluded by the exploration operator. Faulting in this thick shale is evidently difficult to recognise. The Weald Basin is a shallower Upper Jurassic unconventional oil play with stratigraphic similarities to the Bakken play of the Williston Basin, USA. Two Weald licensees have drilled, or have applied to drill, horizontal appraisal wells based on inadequate 2D seismic reflection data coverage. I show, using the data from the one horizontal well drilled to date, that one operator failed identify two small but significant through-going normal faults. The other operator portrayed a seismic line as an example of fault-free structure, but faulting had been smeared out by reprocessing. The case histories presented show that: (1) UK shale exploration to date is characterised by a low degree of technical competence, and (2) regulation, which is divided between four separate authorities, is not up to the task. If UK shale is to be exploited safely: (1) more sophisticated seismic imaging methods need to be developed and applied to both basins, to identify faults in shale with throws as small as 4–5 m, and (2) the current lax and inadequate regulatory regime must be overhauled, unified, and tightened up.

scholarly journals Structural Interpretation of Yamama and Naokelekan Formations in Tuba Oil Field Using 2D Seismic Data

2021 ◽  
Vol 54 (2B) ◽  
pp. 55-64
Author(s):  
Belal M. Odeh
Keyword(s):  
Seismic Data ◽  
Seismic Reflection ◽  
Synthetic Seismogram ◽  
Oil Field ◽  
Well Log ◽  
Seismic Reflection Data ◽  
Depth Maps ◽  
Reflection Data ◽  
Interpretation Process ◽  
Southern Iraq

This research includes structure interpretation of the Yamama Formation (Lower Cretaceous) and the Naokelekan Formation (Jurassic) using 2D seismic reflection data of the Tuba oil field region, Basrah, southern Iraq. The two reflectors (Yamama and Naokelekan) were defined and picked as peak and tough depending on the 2D seismic reflection interpretation process, based on the synthetic seismogram and well log data. In order to obtain structural settings, these horizons were followed over all the regions. Two-way travel-time maps, depth maps, and velocity maps have been produced for top Yamama and top Naokelekan formations. The study concluded that certain longitudinal enclosures reflect anticlines in the east and west of the study area representing Zubair and Rumaila fold confined between them a fold consist of two domes represents Tuba fold with the same trending of Zubair and Rumaila structures. The study confirmed the importance of this field as a reservoir of the accumulation of hydrocarbons.

EXPLORATION HORIZONS FROM NEW SEISMIC CONCEPTS OF CDP AND DIGITAL PROCESSING

Geophysics ◽  
1967 ◽  
Vol 32 (2) ◽  
pp. 207-224 ◽  
Author(s):  
John D. Marr ◽  
Edward F. Zagst
Keyword(s):  
Data Processing ◽  
Seismic Data ◽  
Seismic Reflection ◽  
Synthetic Data ◽  
Digital Processing ◽  
Seismic Data Processing ◽  
Multiple Reflections ◽  
Seismic Reflection Data ◽  
Reflection Data ◽  
Recent Developments

The more recent developments in common‐depth‐point techniques to attenuate multiple reflections have resulted in an exploration capability comparable to the development of the seismic reflection method. The combination of new concepts in digital seismic data processing with CDP techniques is creating unforeseen exploration horizons with vastly improved seismic data. Major improvements in multiple reflection and reverberation attenuation are now attainable with appropriate CDP geometry and special CDP stacking procedures. Further major improvements are clearly evident in the very near future with the use of multichannel digital filtering‐stacking techniques and the application of deconvolution as the first step in seismic data processing. CDP techniques are briefly reviewed and evaluated with real and experimental data. Synthetic data are used to illustrate that all seismic reflection data should be deconvolved as the first processing step.

Application of waveform tomography to marine seismic reflection data from the Queen Charlotte Basin of western Canada

Geophysics ◽  
2011 ◽  
Vol 76 (2) ◽  
pp. B55-B70 ◽  
Author(s):  
E. M. Takam Takougang ◽  
A. J. Calvert
Keyword(s):  
Seismic Reflection ◽  
Field Data ◽  
Velocity Model ◽  
P Wave ◽  
Low Velocity ◽  
Seismic Line ◽  
Seismic Reflection Data ◽  
Reflection Data ◽  
Sonic Log ◽  
Waveform Tomography

To obtain a higher resolution quantitative P-wave velocity model, 2D waveform tomography was applied to seismic reflection data from the Queen Charlotte sedimentary basin off the west coast of Canada. The forward modeling and inversion were implemented in the frequency domain using the visco-acoustic wave equation. Field data preconditioning consisted of f-k filtering, 2D amplitude scaling, shot-to-shot amplitude balancing, and time windowing. The field data were inverted between 7 and 13.66 Hz, with attenuation introduced for frequencies ≥ 10.5 Hz to improve the final velocity model; two different approaches to sampling the frequencies were evaluated. The limited maximum offset of the marine data (3770 m) and the relatively high starting frequency (7 Hz) were the main challenges encountered during the inversion. An inversion strategy that successively recovered shallow-to-deep structures was designed to mitigate these issues. The inclusion of later arrivals in the waveform tomography resulted in a velocity model that extends to a depth of approximately 1200 m, twice the maximum depth of ray coverage in the ray-based tomography. Overall, there is a good agreement between the velocity model and a sonic log from a well on the seismic line, as well as between modeled shot gathers and field data. Anomalous zones of low velocity in the model correspond to previously identified faults or their upward continuation into the shallow Pliocene section where they are not readily identifiable in the conventional migration.

The role of deep seismic reflection data in understanding the architecture and petroleum potential of Australia's onshore sedimentary basins

2010 ◽  
Vol 50 (2) ◽  
pp. 726 ◽  
Author(s):  
Lidena Carr ◽  
Russell Korsch ◽  
Leonie Jones ◽  
Josef Holzschuh
Keyword(s):  
Seismic Reflection ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Seismic Line ◽  
Seismic Reflection Data ◽  
Petroleum Potential ◽  
Deep Seismic Reflection ◽  
Reflection Data ◽  
Stratigraphic Sequences

The onshore energy security program, funded by the Australian Government and conducted by Geoscience Australia, has acquired deep seismic reflection data across several frontier sedimentary basins to stimulate petroleum exploration in onshore Australia. Detailed interpretation of deep seismic reflection profiles from four onshore basins, focussing on overall basin geometry and internal sequence stratigraphy, will be presented here, with the aim of assessing the petroleum potential of the basins. At the southern end of the exposed part of the Mt Isa Province, northwest Queensland, a deep seismic line (06GA–M6) crosses the Burke River structural zone of the Georgina Basin. The basin here is >50 km wide, with a half graben geometry, and bounded in the west by a rift border fault. Given the overall architecture, this basin will be of interest for petroleum exploration. The Millungera Basin in northwest Queensland is completely covered by the thin Eromanga Basin and was unknown prior to being detected on two seismic lines (06GA–M4 and 06GA–M5) acquired in 2006. Following this, seismic line 07GA–IG1 imaged a 65 km wide section of the basin. The geometry of internal stratigraphic sequences and a post-depositional thrust margin indicate that the original succession was much thicker than preserved today and may have potential for a petroleum system. The Yathong Trough, in the southeast part of the Darling Basin in NSW, has been imaged in seismic line 08GA–RS2 and interpreted in detail using sequence stratigraphic principles, with several sequences being mapped. Previous studies indicate that the upper part of this basin consists of Devonian sedimentary rocks, with potential source rocks at depth. In eastern South Australia, seismic line 08GA–A1 crossed the Cambrian Arrowie Basin, which is underlain by a Neoproterozoic succession of the Adelaide Rift System. Stratigraphic sequences have been mapped and can be tied to recent drilling for mineral and geothermal exploration. Shallow drill holes from past petroleum exploration have aided the assessment of the petroleum potential of the Cambrian Hawker Group, which contains bitumen in the core, indicating the presence of source rocks in the basin system.

Imaging Folegandros Basin by Using Seismic Reflection Data from a Part of Seismic Line AEG-1

2015 ◽  
Author(s):  
N. Andronikidis ◽  
M. Gialitaki ◽  
A. Mouchou ◽  
G. Kritikakis ◽  
E. Manoutsoglou ◽  
...  
Keyword(s):  
Seismic Reflection ◽  
Seismic Line ◽  
Seismic Reflection Data ◽  
Reflection Data

Geostatistical seismic inversion for frontier exploration

2017 ◽  
Vol 5 (4) ◽  
pp. T477-T485 ◽  
Author(s):  
Ângela Pereira ◽  
Rúben Nunes ◽  
Leonardo Azevedo ◽  
Luís Guerreiro ◽  
Amílcar Soares
Keyword(s):  
Acoustic Impedance ◽  
Seismic Reflection ◽  
Seismic Inversion ◽  
Well Log ◽  
Data Set ◽  
Seismic Reflection Data ◽  
Log Data ◽  
The Real ◽  
Reflection Data ◽  
Impedance Models

Numerical 3D high-resolution models of subsurface petroelastic properties are key tools for exploration and production stages. Stochastic seismic inversion techniques are often used to infer the spatial distribution of the properties of interest by integrating simultaneously seismic reflection and well-log data also allowing accessing the spatial uncertainty of the retrieved models. In frontier exploration areas, the available data set is often composed exclusively of seismic reflection data due to the lack of drilled wells and are therefore of high uncertainty. In these cases, subsurface models are usually retrieved by deterministic seismic inversion methodologies based exclusively on the existing seismic reflection data and an a priori elastic model. The resulting models are smooth representations of the real complex geology and do not allow assessing the uncertainty. To overcome these limitations, we have developed a geostatistical framework that allows inverting seismic reflection data without the need of experimental data (i.e., well-log data) within the inversion area. This iterative geostatistical seismic inversion methodology simultaneously integrates the available seismic reflection data and information from geologic analogs (nearby wells and/or analog fields) allowing retrieving acoustic impedance models. The model parameter space is perturbed by a stochastic sequential simulation methodology that handles the nonstationary probability distribution function. Convergence from iteration to iteration is ensured by a genetic algorithm driven by the trace-by-trace mismatch between real and synthetic seismic reflection data. The method was successfully applied to a frontier basin offshore southwest Europe, where no well has been drilled yet. Geologic information about the expected impedance distribution was retrieved from nearby wells and integrated within the inversion procedure. The resulting acoustic impedance models are geologically consistent with the available information and data, and the match between the inverted and the real seismic data ranges from 85% to 90% in some regions.

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