scholarly journals Synthetic seismograms through synthetic Franciscan: Insights into factors affecting large-aperture seismic data

1997 ◽  
Vol 24 (24) ◽  
pp. 3317-3320 ◽  
Author(s):  
Christof Lendl ◽  
Anne M. Tréhu ◽  
John A. Goff ◽  
Alan R. Levander ◽  
Bruce C. Beaudoin
Keyword(s):  
Seismic Data ◽  
Synthetic Seismograms ◽  
Factors Affecting ◽  
Large Aperture

scholarly journals High-resolution coherency functionals for velocity analysis: An application for subbasalt seismic exploration

Geophysics ◽  
2013 ◽  
Vol 78 (5) ◽  
pp. U53-U63 ◽  
Author(s):  
Andrea Tognarelli ◽  
Eusebio Stucchi ◽  
Alessia Ravasio ◽  
Alfredo Mazzotti
Keyword(s):  
High Resolution ◽  
Seismic Data ◽  
Field Data ◽  
Signal To Noise Ratio ◽  
Synthetic Seismograms ◽  
Seismic Exploration ◽  
Velocity Analysis ◽  
Signal To Noise ◽  
Geologic Setting ◽  
Analytic Signals

We tested the properties of three different coherency functionals for the velocity analysis of seismic data relative to subbasalt exploration. We evaluated the performance of the standard semblance algorithm and two high-resolution coherency functionals based on the use of analytic signals and of the covariance estimation along hyperbolic traveltime trajectories. Approximate knowledge of the wavelet was exploited to design appropriate filters that matched the primary reflections, thereby further improving the ability of the functionals to highlight the events of interest. The tests were carried out on two synthetic seismograms computed on models reproducing the geologic setting of basaltic intrusions and on common midpoint gathers from a 3D survey. Synthetic and field data had a very low signal-to-noise ratio, strong multiple contamination, and weak primary subbasalt signals. The results revealed that high-resolution coherency functionals were more suitable than semblance algorithms to detect primary signals and to distinguish them from multiples and other interfering events. This early discrimination between primaries and multiples could help to target specific signal enhancement and demultiple operations.

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.

Full‐waveform processing and interpretation of kilohertz cross‐well seismic data

Geophysics ◽  
1993 ◽  
Vol 58 (9) ◽  
pp. 1248-1256 ◽  
Author(s):  
Ashraf A. Khalil ◽  
Robert R. Stewart ◽  
David C. Henley
Keyword(s):  
Oil Recovery ◽  
Seismic Data ◽  
Shear Waves ◽  
Synthetic Seismograms ◽  
Oil Field ◽  
S Wave ◽  
Sonic Log ◽  
The Cross ◽  
Interval Velocities ◽  
The Individual

High‐frequency, cross‐well seismic data, from the Midale oil field of southeastern Saskatchewan, are analyzed for direct and reflected energy. The goal of the analysis is to produce interpretable sections to assist in enhanced oil recovery activities ([Formula: see text] injection) in this field. Direct arrivals are used for velocity information while reflected arrivals are processed into a reflection image. Raw field data show a complex assortment of wave types that includes direct compressional and shear waves and reflected shear waves. A traveltime inversion technique (layer stripping via ray tracing) is used to obtain P‐ and S‐wave interval velocities from the respective direct arrivals. The velocities from the cross‐well inversion and the sonic log are in reasonable agreement. The subsurface coverage of the cross‐well geometry is investigated; it covers zones extending from the source well to the receiver well and includes regions above and below the source/receiver depths. Upgoing and downgoing primary reflections are processed, in a manner similar to the vertical seismic profiling/common‐depth‐point (VSP/CDP) map, to construct the cross‐well images. A final section is produced by summing the individual reflection images from each receiver‐gather map. This section provides an image with evidence of strata thicknesses down to about 1 m. Synthetic seismograms are used to interpret the final sections. Correlations can be drawn between some of the events on the synthetic seismograms and the cross‐well image.

Reflectivity randomness revisited

Geophysics ◽  
1999 ◽  
Vol 64 (5) ◽  
pp. 1630-1636 ◽  
Author(s):  
Ayon K. Dey ◽  
Larry R. Lines
Keyword(s):  
Seismic Data ◽  
Real Data ◽  
Seismic Profile ◽  
Synthetic Seismograms ◽  
Seismic Exploration ◽  
Well Log ◽  
Simple Test ◽  
Vertical Seismic Profile ◽  
Seismic Reflectivity

In seismic exploration, statistical wavelet estimation and deconvolution are standard tools. Both of these processes assume randomness in the seismic reflectivity sequence. The validity of this assumption is examined by using well‐log synthetic seismograms and by using a procedure for evaluating the resulting deconvolutions. With real data, we compare our wavelet estimations with the in‐situ recording of the wavelet from a vertical seismic profile (VSP). As a result of our examination of the randomness assumption, we present a fairly simple test that can be used to evaluate the validity of a randomness assumption. From our test of seismic data in Alberta, we conclude that the assumption of reflectivity randomness is less of a problem in deconvolution than other assumptions such as phase and stationarity.

APPARENT ATTENUATION DUE TO INTRABED MULTIPLES, II

Geophysics ◽  
1978 ◽  
Vol 43 (4) ◽  
pp. 730-737 ◽  
Author(s):  
M. Schoenberger ◽  
F. K. Levin
Keyword(s):  
Seismic Data ◽  
Field Data ◽  
Seismic Waves ◽  
Synthetic Seismograms ◽  
Frequency Dependent ◽  
Total Attenuation ◽  
The World ◽  
Apparent Attenuation

In a paper with the same title published in Geophysics (June 1974), we showed that synthetic seismograms from two wells gave a frequency‐dependent attenuation due to intrabed multiples of about 0.06 dB/wavelength. This loss was 1/3 to 1/2 of the total attenuation found for field data on lines near the wells. Our data sufficed to confirm the conclusion of O’Doherty and Anstey that attenuation caused by intrabed multiples may be appreciable, but the number of wells was insufficient to establish the magnitude of that attenuation in general. To get a better feel for intrabed multiple‐generated attenuation, we have computed losses for 31 additional wells from basins all over the world. Sonic and, where available, density logs were digitized every foot and converted into synthetic seismograms with 50 orders of intrabed multiples. Using the technique of the 1974 paper of extending the logs and placing an isolated reflector 2000 ft below the bottom of the wells, we computed attenuation constants for plane seismic waves that had traveled down and back through the subsurfaces defined by the logs. Computed constants varied from 0.01 dB/wavelength to 0.22 dB/wavelength. Total traveltimes ranged from 0.7 to 2.7 sec; the average was 1.9 sec. Attenuation constants computed from surface seismic data near four of the 31 wells gave values 1.3 to 7 times the corresponding intrabed constants. Thus, attenuation due to intrabed multiples accounts for an appreciable fraction of the observed attenuation but by no means all of it.

scholarly journals Seismically detected porous Zechstein carbonates in Southern Jutland, Denmark

1995 ◽  
Vol 42 ◽  
pp. 34-46
Author(s):  
Kim Gunn Maver
Keyword(s):  
Seismic Data ◽  
Acoustic Impedance ◽  
Seismic Reflection ◽  
Synthetic Seismograms ◽  
Lateral Distribution ◽  
Seismic Modelling ◽  
Seismic Sections ◽  
Well Data ◽  
Impedance Models

Zechstein carbonates in Southern Jutland, Denmark, have been explored by 10 wells since 1952, and a total of more than 2000 km of 2D seismic data has been acquired by various contractors. Seismic modelling, based on all the well data, is used as an aid to predict the lateral distribution of porous Zechstein carbonate intervals from the seismic data. ID seismic modelling is used to define the maximum number of intervals detected by the seismic sections at well locations. The ID seismic modelling results are also used to derive 2D acoustic impedance models and corresponding synthetic seismograms. The seismic modelling results illustrate a number of diagnostic reflection patterns associated with the porous carbonate intervals. The predicted distribution of porous carbonate intervals is, however, found to be uncertain, as thickness and porosity variations of each interval cannot be distinguished. Furthermore, thin porous carbonate intervals are not detected by the seismic sections, and the seismic reflection patterns indicating the presence of porous carbonate intervals can be associated with other lithologies. Porous Ca-la, Ca-lb, Ca-2 and Ca-3 carbonate intervals are found to be detected by the seismic sections only in the Zechstein platform area, and only the porous Ca-2 carbonate interval can be mapped

Geophysical tutorial: Well-tie calculus

2014 ◽  
Vol 33 (6) ◽  
pp. 674-677 ◽  
Author(s):  
Evan Bianco
Keyword(s):  
Seismic Data ◽  
Synthetic Seismograms ◽  
Proprietary Software ◽  
The Third ◽  
Geologic Interpretation ◽  
Well Data

Welcome to the third tutorial in this series. Evan Bianco has put together a terrific look at 1D synthetic seismograms — the critical connections between well data and seismic data that make geologic interpretation possible. Most of us use proprietary software for this part of the workflow, but do you really know what's going on in there? My challenge is: Take a couple of hours, install IPython from ipython.org , and see if you can work your way through Bianco's Notebook at github.com/seg/tutorials — I guarantee you will learn something. If you get stuck, please reach out to him.

scholarly journals 2D Seismic Structural and Stratigraphic Study of Kirkuk Group Formation in Amara Oil Field- Southeastern Iraq

2021 ◽  
pp. 3942-3951
Author(s):  
Ali K. Jaheed ◽  
Hussein H. Karim
Keyword(s):  
Seismic Data ◽  
Seismic Reflection ◽  
Sedimentary Basin ◽  
Group Formation ◽  
Structural Features ◽  
Field Structure ◽  
Synthetic Seismograms ◽  
Oil Field ◽  
Well Logs ◽  
Depth Maps

The Amarah Oil field structure was studied and interpreted by using 2-D seismic data obtained from the Oil  Exploration company. The study is concerned with Maysan Group Formation (Kirkuk Group) which is located in southeastern Iraq and belongs to the Tertiary Age. Two reflectors were detected based on synthetic seismograms and well logs (top and bottom Missan Group). Structural maps were derived from seismic reflection interpretations to obtain the location and direction of the sedimentary basin. Two-way time and depth maps were conducted depending on the structural interpretation of the picked reflectors to show several structural features. These included three types of closures, namely two anticlines extended in the directions of S-SW and NE, one nose structure (anticline) in the middle of the study area,  and structural faults in the northeastern part of the area, which is consistent with the general fault pattern. The seismic interpretation showed the presence of some stratigraphic features. Stratigraphic trap at the eastern part of the field, along with other phenomena, such as flatspot (mound), lenses, onlap, and toplap, were detected as indications of potential hydrocarbon accumulation in the region.

Computation of synthetic seismograms for a thin layered periodic structure

1982 ◽  
Vol 19 (7) ◽  
pp. 1449-1453
Author(s):  
P. F. Daley ◽  
F. Hron
Keyword(s):  
Seismic Data ◽  
Integration Method ◽  
Transversely Isotropic ◽  
Synthetic Seismograms ◽  
Transversely Isotropic Medium ◽  
Long Wavelength ◽  
Long Wavelength Approximation ◽  
Reflectivity Method ◽  
Wavelength Approximation ◽  
Time Required

In the long-wavelength approximation it has been shown in several papers within the last 20 years that an elastic medium composed of alternating homogeneous isotropic layers of two different constituents is equivalent both kinematically and dynamically to a homogeneous transversely isotropic medium. Such a fact excludes uniqueness in inverting seismic data for these particular cases. A comparison of the seismic responses of the equivalent media is made by constructing synthetic seismograms using the reflectivity (numerical integration) method and the asymptotic ray approach. For the sake of simplicity the SH case only is considered. The preferable approach when considering media of this type is found to be the asymptotic ray approximation as the CPU time required is a fraction of that used in the reflectivity method for comparable results.

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