A SIMPLE UPGRADE FOR SOME BRIGHT SPOTS

Geophysics ◽  
1977 ◽  
Vol 42 (4) ◽  
pp. 868-871 ◽  
Author(s):  
Jerry A. Ware
Keyword(s):  
Constant Velocity ◽  
Bright Spot ◽  
Ray Theory ◽  
Multiple Reflections ◽  
Low Velocity ◽  
Reasonable Estimate ◽  
Raw Data ◽  
Common Depth Point ◽  
Bright Spots ◽  
The Common

Confirmation that a bright spot zone in question is low velocity can sometimes be made by looking at constant velocity stacks or the common‐depth‐point gathers. When this confirmation does exist, then it is usually possible to do simple ray theory to get a reasonable estimate of the pay thickness, especially if the water‐sand velocity and the gas‐sand velocity are either known or can be predicted for the area. The confirmation referred to can take the form of under‐removal of the primary events or be exhibited by multiple reflections from the bright spot zone. Such under‐removals or multiple reflections will not be seen on the stacked sections but are sometimes obvious on the raw data, such as the common‐depth‐point gathers, or can be implied by looking at constant velocity stacks of the zone in question at different stacking velocities.

IMPROVED MULTIPLE ATTENUATION IN COMMON DEPTH POINT STACKING

1974 ◽  
Vol 14 (1) ◽  
pp. 107
Author(s):  
John Wardell
Keyword(s):  
Random Noise ◽  
Low Frequency ◽  
Detailed Knowledge ◽  
Multiple Reflections ◽  
Response Curves ◽  
Seismic Section ◽  
Multiple Attenuation ◽  
Common Depth Point ◽  
Wide Range ◽  
The Common

Since the introduction of the common depth point method of seismic reflection shooting, we have seen a continued increase in the multiplicity of subsurface coverage, to the point where nowadays a large proportion of offshore shooting uses a 48 fold 48 trace configuration. Of the many benefits obtained from this multiplicity of coverage, the attenuation of multiple reflections during the common depth point stacking process is one of the most important.Examinations of theoretical response curves for multiple attenuation in common depth point stacking shows that although increased multiplicity does give improved multiple attenuation, this improvement occurs at higher and higher frequencies and residual moveouts (of the multiples) as the multiplicity continues to increase. For multiplicities greater than 12, the improvement is at relatively high frequencies and residual moveouts, while there is no significant improvement for the lower frequencies of multiples with smaller residual moveouts, which unfortunately are those most likely to remain visible after the stacking process.The simple process of zeroing, or muting, certain selected traces (mostly the shorter offset traces) before stacking can give an average 6 to 9 decibels improvement over a wide range of the low frequency and residual moveout part of the stack response, with 9-15 decibels improvement over parts of this range. The cost of this improvement is an increase in random noise level of 1-2 decibels. With digital processing methods, it is easy to zero the necessary traces over selected portions of the seismic section if so desired.The process does not require a detailed knowledge of the multiple residual moveouts, but can be used on a routine basis in areas where strong multiples are a problem, and a high stacking multiplicity is being used.

Geophysical case history of the Two Hills Colony gas field of Alberta

Geophysics ◽  
1985 ◽  
Vol 50 (7) ◽  
pp. 1061-1076 ◽  
Author(s):  
G. W. Focht ◽  
F. E. Baker
Keyword(s):  
Colony Formation ◽  
Oil And Gas ◽  
Direct Detection ◽  
Waveform Analysis ◽  
Bright Spot ◽  
Low Velocity ◽  
Gas Field ◽  
Seismic Line ◽  
Seismic Waveform ◽  
Bright Spots

Seismic waveform changes, which in their most obvious form are known as “bright spots,” have been known for some years to give direct indications of hydrocarbons. An example of successful application of waveform analysis and direct detection of gas in a shallow Lower Cretaceous formation of east‐central Alberta, Canada, is detailed. At a depth of approximately 1 800 ft, the Colony formation typically consists of only thin (10 ft) blanket sands interbedded with shale. However, in 1976, Hudson’s Bay Oil and Gas Company Ltd., encountered a 100 ft thick occurrence of channel sand (with substantial gas pay) in this formation. After some hit and miss attempts at extending the channel trend through geologic interpretation, seismic methods were applied. A seismic line over the channel well revealed a classic bright spot. Several other lines also showed bright spots in the Colony zone. The conclusions from seismic modeling are as follows. Gas within the Colony sand is seismically detectable. The relatively low velocity of the gas sand, combined with the lateral consistency of the sediments above the Colony formation, permits detection. However, the inconsistency and complexity of sediments underlying the Colony resulted in interference patterns that prevented exact quantitative analysis of gas pays. Furthermore, other geologic phenomena provided waveform changes similar to that of gas sand. Through detailed examination of the geology and evaluation of the alternative explanations of the waveform changes, successful interpretation was accomplished. Estimations of net gas pay were generally accurate within 20 percent. In some areas, very subtle anomalies in wave character representing gas pays as thin as 5 ft can now be interpreted with confidence. Several examples are given of successful detection and prediction of gas. To date (October, 1979) seismic waveform analysis has led to the drilling of 86 wells; 67 of these are commercial gas wells in the Colony formation, representing a success ratio of 78 percent. Total reserves discovered geophysically (by Hudson’s Bay Oil and Gas Co. Ltd.) to date in the Colony formation are estimated at 110 Bcf.

Modeling of zero-offset reflection profiles with asymptotic ray theory

1981 ◽  
Vol 18 (3) ◽  
pp. 551-560
Author(s):  
George A. McMechan
Keyword(s):  
Seismic Reflection ◽  
Constant Velocity ◽  
Seismic Refraction ◽  
Drill Core ◽  
Ray Theory ◽  
Low Velocity ◽  
Tectonic Structures ◽  
Seismic Reflection Data ◽  
Reflection Data ◽  
Zero Offset

Synthetic reflection profiles computed by asymptotic ray theory can be used in the interpretation of laterally varying tectonic structures. The algorithm is implemented for normally incident (zero-offset) rays in two-dimensional models that are specified in terms of constant velocity layers separated by piecewise cubic boundaries. Applications include modeling of profiles containing lenses, interbedded high- and low-velocity layers, and oceanic ridges. The method is practical and flexible in the sense that structural, lithologic, drill core, and seismic refraction constraints can be directly combined with the seismic reflection data.

Marchenko multiple elimination and full wavefield migration in a resonant pinch-out model

Geophysics ◽  
2021 ◽  
pp. 1-59
Author(s):  
Evert Slob ◽  
Lele Zhang ◽  
Eric Verschuur
Keyword(s):  
Constant Velocity ◽  
Local Minimum ◽  
Velocity Model ◽  
Dominant Frequency ◽  
Data Sampling ◽  
Multiple Reflections ◽  
Linear Inversion ◽  
Acoustic Reflection ◽  
Reflection Data ◽  
Multiple Elimination

Marchenko multiple elimination schemes are able to attenuate all internal multiple reflections in acoustic reflection data. These can be implemented with and without compensation for two-way transmission effects in the resulting primary reflection dataset. The methods are fully automated and run without human intervention, but require the data to be properly sampled and pre-processed. Even when several primary reflections are invisible in the data because they are masked by overlapping primaries, such as in the resonant wedge model, all missing primary reflections are restored and recovered with the proper amplitudes. Investigating the amplitudes in the primary reflections after multiple elimination with and without compensation for transmission effects shows that transmission effects are properly accounted for in a constant velocity model. When the layer thickness is one quarter of the wavelength at the dominant frequency of the source wavelet, the methods cease to work properly. Full wavefield migration relies on a velocity model and runs a non-linear inversion to obtain a reflectivity model which results in the migration image. The primary reflections that are masked by interference with multiples in the resonant wedge model, are not recovered. In this case, minimizing the data misfit function leads to the incorrect reflector model even though the data fit is optimal. This method has much lower demands on data sampling than the multiple elimination schemes, but is prone to get stuck in a local minimum even when the correct velocity model is available. A hybrid method that exploits the strengths of each of these methods could be worth investigating.

Inversion of normal incidence seismograms

Geophysics ◽  
1982 ◽  
Vol 47 (5) ◽  
pp. 757-770 ◽  
Author(s):  
A. Bamberger ◽  
G. Chavent ◽  
Ch. Hemon ◽  
P. Lailly
Keyword(s):  
Simulated Data ◽  
Normal Incidence ◽  
State Equation ◽  
Inversion Algorithm ◽  
Multiple Reflections ◽  
Common Depth Point ◽  
Adjoint State ◽  
Nmo Correction ◽  
The One ◽  
Practical Feasibility

The well‐known instability of Kunetz’s (1963) inversion algorithm can be explained by the progressive manner in which the calculations are done (descending from the surface) and by the fact that completely different impedances can yield indistinguishable synthetic seismograms. Those difficulties can be overcome by using an iterative algorithm for the inversion of the one‐dimensional (1-D) wave equation, together with a stabilizing constraint on the sums of the jumps of the desired impedance. For computational efficiency, the synthetic seismogram is computed by the method of characteristics, and the gradient of the error criterion is computed by optimal control techniques (adjoint state equation). The numerical results on simulated data confirm the expected stability of the algorithm in the presence of measurement noise (tests include noise levels of 50 percent). The inversion of two field sections demonstrates the practical feasibility of the method and the importance of taking into account all internal as well as external multiple reflections. Reflection coefficients obtained by this method show an excellent agreement with well‐log data in a case where standard estimation techniques [deconvolution of common‐depth‐point (CDP) stacked and normal‐moveout (NMO) correction section] failed.

GOLDEN BEACH: A BRIGHT SPOT

1978 ◽  
Vol 18 (1) ◽  
pp. 109
Author(s):  
R. B. Mariow
Keyword(s):  
Seismic Data ◽  
High Amplitude ◽  
Late Eocene ◽  
Polarity Reversal ◽  
Bright Spot ◽  
Areal Extent ◽  
Water Contact ◽  
Bright Spots ◽  
Gippsland Basin ◽  
Seismic Reflector

The Golden Beach closed anticlinal structure lies five kilometres offshore in the Gippsland Basin. Golden Beach 1A was drilled in 1967 near the crest of the structure and intersected a gas column of 19 m (63 feet) at the top of the Latrobe Group (Late Eocene) where most of the hydrocarbon accumulations in the Gippsland Basin have been found. The gas-water contact lies at a depth of 652 m (2139 feet) below sea level.On seismic data recorded over the structure, a high amplitude flat-lying event was interpreted as a bright 'flat spot' at the gas-water contact. Reprocessing of the seismic data enhanced the bright spot effect and enabled the areal extent of the gas zone to be mapped. The presence of the gas also leads to a polarity reversal of the top of the Latrobe Group seismic reflector over the gas accumulation.Seismic data from other structures containing hydrocarbons in the Gippsland Basin support the concept that bright spots and flat spots are more likely to be associated with gas than with oil accumulations, and that the observed bright spot effect decreases with increasing depth.

Evaluation of direct hydrocarbon indicators through comparison of compressional‐ and shear‐wave seismic data: a case study of the Myrnam gas field, Alberta

Geophysics ◽  
1985 ◽  
Vol 50 (1) ◽  
pp. 37-48 ◽  
Author(s):  
Ross Alan Ensley
Keyword(s):  
Shear Wave ◽  
Seismic Data ◽  
Compressional Wave ◽  
Bright Spot ◽  
Low Velocity ◽  
Gas Reservoir ◽  
Gas Field ◽  
Compressional Waves ◽  
The Relationship

Shear waves differ from compressional waves in that their velocity is not significantly affected by changes in the fluid content of a rock. Because of this relationship, a gas‐related compressional‐wave “bright spot” or direct hydrocarbon indicator will have no comparable shear‐wave anomaly. In contrast, a lithology‐related compressional‐wave anomaly will have a corresponding shear‐wave anomaly. Thus, it is possible to use shear‐wave seismic data to evaluate compressional‐wave direct hydrocarbon indicators. This case study presents data from Myrnam, Alberta which exhibit the relationship between compressional‐ and shear‐wave seismic data over a gas reservoir and a low‐velocity coal.

Computation of residual statics using projectors

Geophysics ◽  
1985 ◽  
Vol 50 (9) ◽  
pp. 1502-1504 ◽  
Author(s):  
Koraljka Čaklović ◽  
Lavoslav Čaklović
Keyword(s):  
System Of Equations ◽  
Unknown Parameters ◽  
Linear System Of Equations ◽  
Common Depth Point ◽  
Reference Trace ◽  
Position Index ◽  
Static Corrections ◽  
The Common ◽  
System 1 ◽  
Text Correction

The residual statics problem, as we know, is treated as the solution of one linear system of equations. If we assume that the static corrections are “surface consistent,” then we know that time shifts of each trace can be written as the sum of three terms [Formula: see text] where i = 1, …, [Formula: see text] is the shot position index with [Formula: see text] the number of shot positions, j = 1, …, [Formula: see text] is the receiver position index with [Formula: see text] the number of receiver positions, k = 1, …, [Formula: see text] is the common‐depth‐point (CDP) position index with [Formula: see text] the number of common depth points, [Formula: see text] = correction for ith shot position, [Formula: see text] = correction for jth receiver position, and [Formula: see text] = correction for each trace in the kth CDP gather. For every pair (i, j) we have one equation. We write system (1) in matrix form as [Formula: see text] where [Formula: see text] is the vector of unknown parameters; and [Formula: see text] is the vector which consists of the time shifts obtained by crosscorrelation of each trace in CDP gather with the corresponding reference trace.

A simultaneous inversion of seismic traveltimes and amplitudes for velocity and attenuation

Geophysics ◽  
1996 ◽  
Vol 61 (6) ◽  
pp. 1738-1757 ◽  
Author(s):  
Don W. Vasco ◽  
John E. Peterson ◽  
Ernest L. Majer
Keyword(s):  
Perturbation Approach ◽  
Well Log ◽  
Ray Theory ◽  
Fracture Zones ◽  
Low Velocity ◽  
Simultaneous Inversion ◽  
Attenuation Structure ◽  
Paraxial Ray ◽  
The Relationship ◽  
Velocity Region

It is possible to efficiently use traveltime and amplitude information to infer variations in velocity and Q. With little additional computation, terms accounting for source radiation pattern and receiver coupling may be included in the inversion. The methodology is based upon a perturbation approach to paraxial ray theory. The perturbation approach linearizes the relationship between velocity deviations and traveltime and amplitude anomalies. Using the technique, we infer the velocity and attenuation structure at a fractured granitic site near Raymond, California. A set of four well pairs are examined and each is found to contain two zones of strong attenuation. The velocity variations contain an upper low velocity region corresponding to the uppermost attenuating zone. The location of these zones agrees with independent well‐log and geophysical data. The velocity and attenuation anomalies appear to coincide with extensively fractured sections of the borehole and may indicate fracture zones rather than individual fractures.

ELASTIC‐WAVE VELOCITY MEASUREMENTS IN ROCKS AND OTHER MATERIALS BY PHASE‐DELAY METHODS

Geophysics ◽  
1975 ◽  
Vol 40 (6) ◽  
pp. 955-960 ◽  
Author(s):  
E. A. Kaarsberg
Keyword(s):  
Elastic Wave ◽  
Wave Velocity ◽  
Path Length ◽  
Shear Velocity ◽  
Elastic Wave Velocity ◽  
Phase Delay ◽  
Velocity Measurements ◽  
Multiple Reflections ◽  
Low Velocity ◽  
High Attenuation

The phase delay of a continuous sinusoidal elastic wave after transmission through a medium may be used to determine the velocity of propagation of the wave in the medium. The change in path length for a given frequency, or the change in frequency for a given path length, required to change the phase delay by integral multiples of 360 degrees is measured in the laboratory by the use of source and receiver piezoelectric transducers whose signals are applied to the horizontal and vertical deflection circuits of an oscilloscope. The accuracy of the method depends upon the accuracy with which the frequency of the transmitted wave and its path length through the medium (or change in path length) can be determined, provided the effect of extraneous signals (e.g., boundary reflections, multiple reflections, alternate modes of propagation, etc.) is negligible. The phase‐delay methods are illustrated and compared with conventional pulse methods by using both to make compressional‐velocity measurements in water and compressional‐ and shear‐velocity measurements in a high velocity basalt and in a low velocity dried mud sample. The results of the two methods agree to within a few percent. It is suggested that these phase‐delay methods may be especially well‐suited for making elastic‐wave velocity measurements in media with high attenuation of the waves propagated in them.

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