Inferring the statistical distribution of velocity heterogeneities by statistical traveltime tomography

Geophysics ◽  
2003 ◽  
Vol 68 (5) ◽  
pp. 1714-1730 ◽  
Author(s):  
Bertrand Iooss ◽  
David Geraets ◽  
Tapan Mukerji ◽  
Yann Samuelides ◽  
Mustafa Touati ◽  
...  
Keyword(s):  
Spatial Statistics ◽  
Seismic Data ◽  
Heterogeneous Media ◽  
Real Data ◽  
Spatial Covariance ◽  
Reservoir Properties ◽  
Seismic Reflection Data ◽  
Rock Density ◽  
Reflection Data ◽  
Tomography Method

Understanding the internal heterogeneities of reservoirs is one of the key issues in better recovery and efficient reservoir management. Seismic data are widely used to map subsurface heterogeneities. These heterogeneities can include variations in wave velocity and rock density, which can be used to interpret variations in reservoir properties such as porosity, lithofacies, and fluids. This paper describes a statistical tomography method to infer the spatial statistics of subsurface velocity heterogeneities from seismic data. We consider an acoustic wave propagating in a medium represented as a single macromodel superimposed on statistically stationary random velocity perturbations. While the macromodel is retrieved by classical seismic methods, the picked traveltimes and their fluctuations are used to estimate the covariance function of the spatially varying velocity perturbations. We present a formulation based on ray‐theoretical results and describe two algorithms: one using the prestack traveltimes and the other using the stacking velocities. The methods are tested with synthetic seismic reflection data in an idealized medium (with a Gaussian spatial covariance) and with synthetic transmission data in a more geologically realistic medium. Then, the two algorithms are applied on real data. The estimates of the spatial statistics obtained from inverting the traveltime statistics match reasonably well with the true parameters of the heterogeneous media.

scholarly journals Monte Carlo reservoir analysis combining seismic reflection data and informed priors

Geophysics ◽  
2015 ◽  
Vol 80 (1) ◽  
pp. R31-R41 ◽  
Author(s):  
Andrea Zunino ◽  
Klaus Mosegaard ◽  
Katrine Lange ◽  
Yulia Melnikova ◽  
Thomas Mejer Hansen
Keyword(s):  
Monte Carlo ◽  
Seismic Data ◽  
Seismic Reflection ◽  
Probabilistic Approach ◽  
Multiple Point ◽  
Petroleum Reservoir ◽  
Inversion Algorithm ◽  
Reservoir Properties ◽  
Seismic Reflection Data ◽  
Reflection Data

Determination of a petroleum reservoir structure and rock bulk properties relies extensively on inference from reflection seismology. However, classic deterministic methods to invert seismic data for reservoir properties suffer from some limitations, among which are the difficulty of handling complex, possibly nonlinear forward models, and the lack of robust uncertainty estimations. To overcome these limitations, we studied a methodology to invert seismic reflection data in the framework of the probabilistic approach to inverse problems, using a Markov chain Monte Carlo (McMC) algorithm with the goal to directly infer the rock facies and porosity of a target reservoir zone. We thus combined a rock-physics model with seismic data in a single inversion algorithm. For large data sets, the McMC method may become computationally impractical, so we relied on multiple-point-based a priori information to quantify geologically plausible models. We tested this methodology on a synthetic reservoir model. The solution of the inverse problem was then represented by a collection of facies and porosity reservoir models, which were samples of the posterior distribution. The final product included probability maps of the reservoir properties in obtained by performing statistical analysis on the collection of solutions.

Slowness-driven Gaussian-beam prestack depth migration for low-fold seismic data

Geophysics ◽  
2009 ◽  
Vol 74 (6) ◽  
pp. WCA35-WCA45 ◽  
Author(s):  
Chaoshun Hu ◽  
Paul L. Stoffa
Keyword(s):  
Gaussian Beam ◽  
Seismic Data ◽  
Fresnel Zone ◽  
Seismic Energy ◽  
Real Data ◽  
Ocean Bottom ◽  
Prestack Depth Migration ◽  
Seismic Reflection Data ◽  
Depth Migration ◽  
Reflection Data

Subsurface images based on low-fold seismic reflection data or data with geometry acquisition limitations, such as obtained from ocean-bottom seismography (OBS), are often corrupted by migration swing artifacts. Incorporating prestack instantaneous slowness information into the imaging condition can significantly reduce these migration swing artifacts and improve image quality, especially for areas with poor illumination. We combine the horizontal surface slowness information of observed seismic data with Gaussian-beam depth migration to implement a new slowness-driven Gaussian-beam prestack depth migration whereby Fresnel weighting is combined naturally with beam summation. The prestack instantaneous slowness information is extracted from the original OBS or shot gathers using local slant stacks and is combined with a local semblance analysis. During migration, we propagate the seismic energy downward, knowing its instantaneous slowness information. At each image location, the beam summation is localized in a resolution-dependent Fresnel zone; the instantaneous slowness information controls the beam summation. Synthetic and real data examples confirm that slowness-driven Gaussian-beam migration can suppress most noise from inadequate stacking and give a clearer migration result.

Predictive Seismic Reservoir Modelling in the UK Manx Basin

1992 ◽  
Vol 10 (4-5) ◽  
pp. 321-334 ◽  
Author(s):  
C.P. Ross ◽  
S.D. Flack
Keyword(s):  
Seismic Data ◽  
Seismic Reflection ◽  
Pore Fluid ◽  
Early Triassic ◽  
Reservoir Properties ◽  
Seismic Reflection Data ◽  
Reservoir Modelling ◽  
Reflection Data ◽  
Seismic Reservoir ◽  
The Uk

Within the Manx Basin, the primary reservoir is the early Triassic Helsby sandstone. The Helsby occurs in various facies, each with its own characteristic reservoir properties. Although seismic reflection data is insensitive to changes in the pore fluid fill, geophysical modelling has shown that it should be possible to map porosity variations on conventional seismic data.

An improved method to estimate Q based on the logarithmic spectrum of moving peak points

2019 ◽  
Vol 7 (2) ◽  
pp. T255-T263 ◽  
Author(s):  
Yanli Liu ◽  
Zhenchun Li ◽  
Guoquan Yang ◽  
Qiang Liu
Keyword(s):  
Seismic Waves ◽  
Wave Attenuation ◽  
Real Data ◽  
Peak Frequency ◽  
Seismic Reflection Data ◽  
The Real ◽  
Time Frequency ◽  
Reflection Data ◽  
Text Filtering ◽  
The Impact

The quality factor ([Formula: see text]) is an important parameter for measuring the attenuation of seismic waves. Reliable [Formula: see text] estimation and stable inverse [Formula: see text] filtering are expected to improve the resolution of seismic data and deep-layer energy. Many methods of estimating [Formula: see text] are based on an individual wavelet. However, it is difficult to extract the individual wavelet precisely from seismic reflection data. To avoid this problem, we have developed a method of directly estimating [Formula: see text] from reflection data. The core of the methodology is selecting the peak-frequency points to linear fit their logarithmic spectrum and time-frequency product. Then, we calculated [Formula: see text] according to the relationship between [Formula: see text] and the optimized slope. First, to get the peak frequency points at different times, we use the generalized S transform to produce the 2D high-precision time-frequency spectrum. According to the seismic wave attenuation mechanism, the logarithmic spectrum attenuates linearly with the product of frequency and time. Thus, the second step of the method is transforming a 2D spectrum into 1D by variable substitution. In the process of transformation, we only selected the peak frequency points to participate in the fitting process, which can reduce the impact of the interference on the spectrum. Third, we obtain the optimized slope by least-squares fitting. To demonstrate the reliability of our method, we applied it to a constant [Formula: see text] model and the real data of a work area. For the real data, we calculated the [Formula: see text] curve of the seismic trace near a well and we get the high-resolution section by using stable inverse [Formula: see text] filtering. The model and real data indicate that our method is effective and reliable for estimating the [Formula: see text] value.

Potentially Large Subsurface Gas Hydrate Bodies in the Mexican Ridges, Southwestern Gulf of Mexico

2021 ◽  
pp. 1-29
Author(s):  
Papia Nandi ◽  
Patrick Fulton ◽  
James Dale
Keyword(s):  
Gulf Of Mexico ◽  
Gas Hydrate ◽  
Seismic Data ◽  
Poor Quality ◽  
Reflection Point ◽  
Seismic Reflection Data ◽  
Reflection Data ◽  
High Impedance ◽  
Acoustic Velocities ◽  
Seismic Images

As rising ocean temperatures can destabilize gas hydrate, identifying and characterizing large shallow hydrate bodies is increasingly important in order to understand their hazard potential. In the southwestern Gulf of Mexico, reanalysis of 3D seismic reflection data reveals evidence for the presence of six potentially large gas hydrate bodies located at shallow depths below the seafloor. We originally interpreted these bodies as salt, as they share common visual characteristics on seismic data with shallow allochthonous salt bodies, including high-impedance boundaries and homogenous interiors with very little acoustic reflectivity. However, when seismic images are constructed using acoustic velocities associated with salt, the resulting images were of poor quality containing excessive moveout in common reflection point (CRP) offset image gathers. Further investigation reveals that using lower-valued acoustic velocities results in higher quality images with little or no moveout. We believe that these lower acoustic values are representative of gas hydrate and not of salt. Directly underneath these bodies lies a zone of poor reflectivity, which is both typical and expected under hydrate. Observations of gas in a nearby well, other indicators of hydrate in the vicinity, and regional geologic context, all support the interpretation that these large bodies are composed of hydrate. The total equivalent volume of gas within these bodies is estimated to potentially be as large as 1.5 gigatons or 10.5 TCF, considering uncertainty for estimates of porosity and saturation, comparable to the entire proven natural gas reserves of Trinidad and Tobago in 2019.

scholarly journals Improved Interpretation of Deep Seismic Reflection Data in Areas of Complex Geology Through Integration With Passive Seismic Data Sets

2018 ◽  
Vol 123 (12) ◽  
pp. 10,810-10,830
Author(s):  
Michael Dentith ◽  
Huaiyu Yuan ◽  
Ruth Elaine Murdie ◽  
Perla Pina-Varas ◽  
Simon P. Johnson ◽  
...  
Keyword(s):  
Seismic Data ◽  
Seismic Reflection ◽  
Data Sets ◽  
Seismic Reflection Data ◽  
Deep Seismic Reflection ◽  
Reflection Data ◽  
Passive Seismic ◽  
Complex Geology

Late Cretaceous – Cenozoic history of the transition zone between the East European Craton and the Paleozoic Platform, Polish sector of the Baltic Sea, revealed by new offshore regional seismic reflection data (BALTEC project)

2021 ◽  
Author(s):  
Piotr Krzywiec ◽  
Łukasz Słonka ◽  
Quang Nguyen ◽  
Michał Malinowski ◽  
Mateusz Kufrasa ◽  
...  
Keyword(s):  
High Resolution ◽  
Late Cretaceous ◽  
Seismic Data ◽  
Seismic Reflection ◽  
Upper Cretaceous ◽  
Seismic Reflection Data ◽  
East European ◽  
Reflection Data ◽  
Multichannel Seismic Reflection ◽  
Multichannel Seismic Reflection Data

<p>In 2016, approximately 850 km of high-resolution multichannel seismic reflection data of the BALTEC survey have been acquired offshore Poland within the transition zone between the East European Craton and the Paleozoic Platform. Data processing, focused on removal of multiples, strongly overprinting geological information at shallower intervals, included SRME, TAU-P domain deconvolution, high resolution parabolic Radon demultiple and SWDM (Shallow Water De-Multiple). Entire dataset was Kirchhoff pre-stack time migrated. Additionally, legacy shallow high-resolution multichannel seismic reflection data acquired in this zone in 1997 was also used. All this data provided new information on various aspects of the Phanerozoic evolution of this area, including Late Cretaceous to Cenozoic tectonics and sedimentation. This phase of geological evolution could be until now hardly resolved by analysis of industry seismic data as, due to limited shallow seismic imaging and very strong overprint of multiples, essentially no information could have been retrieved from this data for first 200-300 m. Western part of the BALTEC dataset is located above the offshore segment of the Mid-Polish Swell (MPS) – large anticlinorium formed due to inversion of the axial part of the Polish Basin. BALTEC seismic data proved that Late Cretaceous inversion of the Koszalin – Chojnice fault zone located along the NE border of the MPS was thick-skinned in nature and was associated with substantial syn-inversion sedimentation. Subtle thickness variations and progressive unconformities imaged by BALTEC seismic data within the Upper Cretaceous succession in vicinity of the Kamień-Adler and the Trzebiatów fault zones located within the MPS documented complex interplay of Late Cretaceous basin inversion, erosion and re-deposition. Precambrian basement of the Eastern, cratonic part of the study area is overlain by Cambro-Silurian sedimentary cover. It is dissected by a system of steep, mostly reverse faults rooted in most cases in the deep basement. This fault system has been regarded so far as having been formed mostly in Paleozoic times, due to the Caledonian orogeny. As a consequence, Upper Cretaceous succession, locally present in this area, has been vaguely defined as a post-tectonic cover, locally onlapping uplifted Paleozoic blocks. New seismic data, because of its reliable imaging of the shallowest substratum, confirmed that at least some of these deeply-rooted faults were active as a reverse faults in latest Cretaceous – earliest Paleogene. Consequently, it can be unequivocally proved that large offshore blocks of Silurian and older rocks presently located directly beneath the Cenozoic veneer must have been at least partly covered by the Upper Cretaceous succession; then, they were uplifted during the widespread inversion that affected most of Europe. Ensuing regional erosion might have at least partly provided sediments that formed Upper Cretaceous progradational wedges recently imaged within the onshore Baltic Basin by high-end PolandSPAN regional seismic data. New seismic data imaged also Paleogene and younger post-inversion cover. All these results prove that Late Cretaceous tectonics substantially affected large areas located much farther towards the East than previously assumed.</p><p>This study was funded by the Polish National Science Centre (NCN) grant no UMO-2017/27/B/ST10/02316.</p>

Fault whispers: Transmission distortions on prestack seismic reflection data

Geophysics ◽  
2000 ◽  
Vol 65 (2) ◽  
pp. 377-389 ◽  
Author(s):  
Paul J. Hatchell
Keyword(s):  
Seismic Data ◽  
Seismic Waves ◽  
Shallow Gas ◽  
Seismic Reflection Data ◽  
Reflection Data ◽  
Amplitude Versus Offset ◽  
Velocity Changes ◽  
Transmission Distortions ◽  
Amplitude Versus ◽  
Buried Faults

Transmission distortions are observed on prestack seismic data at two locations in the Gulf of Mexico. These distortions produce anomalous amplitude versus offset (AVO) signatures. The locations of the distortion zones are determined using acquisition geometry and ray tracing. No obvious reflection events, such as shallow gas zones, are observed at the predicted locations of the distortion zones. Instead, the distortion zones correlate with buried faults and unconformities. It is postulated that the distortions are produced by velocity changes across buried faults and unconformities. The distortions result from an interference pattern resulting from seismic waves arriving from different sides of the faults. A simple model is developed to explain many of the characteristics of the distortion pattern.

Using instantaneous frequency and colored inversion attributes to distinguish and determine the sandstones facies of the Late Ordovician Mamuniyat reservoir, R-field in Murzuq Basin, Libya

2016 ◽  
Vol 4 (4) ◽  
pp. T507-T519 ◽  
Author(s):  
Yousf Abushalah ◽  
Laura Serpa
Keyword(s):  
Instantaneous Frequency ◽  
Seismic Data ◽  
Acoustic Impedance ◽  
Rock Physics ◽  
Side Lobe ◽  
Petroleum Reservoir ◽  
Seismic Reflection Data ◽  
Frequency Bands ◽  
Reflection Data ◽  
Sandstone Facies

The Mamuniyat petroleum reservoir in southwestern Libya is comprised of clean sandstones and intercalated shale and sand facies that are characterized by spatial porosity variations. Seismic reflection data from the field exhibit relatively low vertical seismic resolution, side lobes of reflection wavelets, reflection interference, and low acoustic impedance contrast between the reservoir and the units underneath the reservoir, which make mapping those facies a difficult task. In the absence of broadband seismic data, optimizing frequency bands of bandlimited data can be used to suppress pseudoreflectors resulting from side-lobe effects and help to separate the clean sandstone facies of the reservoir. We have optimized the data based on our investigation of seismic frequency bands and used instantaneous frequency analysis to reveal the reflection discontinuity that is mainly associated with the reservoir boundary of the sandstone facies of the clean Mamuniyat reservoir. We also preformed rock-physics diagnostic modeling and inverted the seismic data using spectral-based colored inversion into relative acoustic impedance. The inverted impedance matches the up-scaled impedance from the well data and the inversion of relative acoustic impedance confirms the conclusion that was drawn from the instantaneous frequency results. The interpretation of facies distributions based on the instantaneous frequency was supported by the inversion results and the rock-physics models.

Tomographic determination of velocity and depth in laterally varying media

Geophysics ◽  
1985 ◽  
Vol 50 (6) ◽  
pp. 903-923 ◽  
Author(s):  
T. N. Bishop ◽  
K. P. Bube ◽  
R. T. Cutler ◽  
R. T. Langan ◽  
P. L. Love ◽  
...  
Keyword(s):  
Seismic Reflection ◽  
Seismic Velocity ◽  
Real Data ◽  
Seismic Reflection Data ◽  
Near Surface ◽  
Reflection Data ◽  
Tomographic Method ◽  
Recorded Data ◽  
The Difference

Estimation of reflector depth and seismic velocity from seismic reflection data can be formulated as a general inverse problem. The method used to solve this problem is similar to tomographic techniques in medical diagnosis and we refer to it as seismic reflection tomography. Seismic tomography is formulated as an iterative Gauss‐Newton algorithm that produces a velocity‐depth model which minimizes the difference between traveltimes generated by tracing rays through the model and traveltimes measured from the data. The input to the process consists of traveltimes measured from selected events on unstacked seismic data and a first‐guess velocity‐depth model. Usually this first‐guess model has velocities which are laterally constant and is usually based on nearby well information and/or an analysis of the stacked section. The final model generated by the tomographic method yields traveltimes from ray tracing which differ from the measured values in recorded data by approximately 5 ms root‐mean‐square. The indeterminancy of the inversion and the associated nonuniqueness of the output model are both analyzed theoretically and tested numerically. It is found that certain aspects of the velocity field are poorly determined or undetermined. This technique is applied to an example using real data where the presence of permafrost causes a near‐surface lateral change in velocity. The permafrost is successfully imaged in the model output from tomography. In addition, depth estimates at the intersection of two lines differ by a significantly smaller amount than the corresponding estimates derived from conventional processing.

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