AVO inversion of a Gulf of Mexico bright spot—A case study

Geophysics ◽  
1999 ◽  
Vol 64 (5) ◽  
pp. 1480-1491 ◽  
Author(s):  
Patrice Nsoga Mahob ◽  
John P. Castagna ◽  
Roger A. Young
Keyword(s):  
Gulf Of Mexico ◽  
Poisson’S Ratio ◽  
Poisson's Ratio ◽  
Bright Spot ◽  
Inversion Algorithm ◽  
Seismic Line ◽  
Data Set ◽  
The Real ◽  
Hydrocarbon Saturation ◽  
Initial Starting

An iterative and linearized inversion algorithm carried out in the x-t domain has been applied to a prestack seismic data set from the central Gulf of Mexico, offshore Louisiana. Sonic and density curves from a well located close to the seismic line are used to generate the initial starting models for the inversion. We tested the geologically realistic hypothesis that the starting models have an accurate impedance structure outside of the potential pay zone and that the prospective pay zone will have mechanical properties consistent with the presence or absence of hydrocarbons. The inversion, performed with starting models with pay zones with a Poisson’s ratio appropriate for 100% brine saturation or with a Poisson’s ratio intermediate between expected values for full brine and hydrocarbon saturation, does not converge to the real seismic gather. However, with a starting model having a Poisson’s ratio appropriate for hydrocarbon saturation in the target zone, there is convergence from the initial to the real seismic gather.

scholarly journals Multidimensional scaling for the evaluation of a geostatistical seismic elastic inversion methodology

Geophysics ◽  
2014 ◽  
Vol 79 (1) ◽  
pp. M1-M10 ◽  
Author(s):  
Leonardo Azevedo ◽  
Ruben Nunes ◽  
Pedro Correia ◽  
Amílcar Soares ◽  
Luis Guerreiro ◽  
...  
Keyword(s):  
Multidimensional Scaling ◽  
Metric Space ◽  
Synthetic Data ◽  
Real Data ◽  
Seismic Inversion ◽  
Inversion Algorithm ◽  
Data Set ◽  
The Real ◽  
Geostatistical Inversion ◽  
Impedance Models

Due to the nature of seismic inversion problems, there are multiple possible solutions that can equally fit the observed seismic data while diverging from the real subsurface model. Consequently, it is important to assess how inverse-impedance models are converging toward the real subsurface model. For this purpose, we evaluated a new methodology to combine the multidimensional scaling (MDS) technique with an iterative geostatistical elastic seismic inversion algorithm. The geostatistical inversion algorithm inverted partial angle stacks directly for acoustic and elastic impedance (AI and EI) models. It was based on a genetic algorithm in which the model perturbation at each iteration was performed recurring to stochastic sequential simulation. To assess the reliability and convergence of the inverted models at each step, the simulated models can be projected in a metric space computed by MDS. This projection allowed distinguishing similar from variable models and assessing the convergence of inverted models toward the real impedance ones. The geostatistical inversion results of a synthetic data set, in which the real AI and EI models are known, were plotted in this metric space along with the known impedance models. We applied the same principle to a real data set using a cross-validation technique. These examples revealed that the MDS is a valuable tool to evaluate the convergence of the inverse methodology and the impedance model variability among each iteration of the inversion process. Particularly for the geostatistical inversion algorithm we evaluated, it retrieves reliable impedance models while still producing a set of simulated models with considerable variability.

Elastic impedance parameterization and inversion with Young’s modulus and Poisson’s ratio

Geophysics ◽  
2013 ◽  
Vol 78 (6) ◽  
pp. N35-N42 ◽  
Author(s):  
Zhaoyun Zong ◽  
Xingyao Yin ◽  
Guochen Wu
Keyword(s):  
Parameter Estimation ◽  
Young’S Modulus ◽  
Seismic Data ◽  
Poisson’S Ratio ◽  
Young's Modulus ◽  
Incident Angle ◽  
P Wave ◽  
Poisson's Ratio ◽  
Data Set ◽  
Elastic Impedance

Young’s modulus and Poisson’s ratio are related to quantitative reservoir properties such as porosity, rock strength, mineral and total organic carbon content, and they can be used to infer preferential drilling locations or sweet spots. Conventionally, they are computed and estimated with a rock physics law in terms of P-wave, S-wave impedances/velocities, and density which may be directly inverted with prestack seismic data. However, the density term imbedded in Young’s modulus is difficult to estimate because it is less sensitive to seismic-amplitude variations, and the indirect way can create more uncertainty for the estimation of Young’s modulus and Poisson’s ratio. This study combines the elastic impedance equation in terms of Young’s modulus and Poisson’s ratio and elastic impedance variation with incident angle inversion to produce a stable and direct way to estimate the Young’s modulus and Poisson’s ratio, with no need for density information from prestack seismic data. We initially derive a novel elastic impedance equation in terms of Young’s modulus and Poisson’s ratio. And then, to enhance the estimation stability, we develop the elastic impedance varying with incident angle inversion with damping singular value decomposition (EVA-DSVD) method to estimate the Young’s modulus and Poisson’s ratio. This method is implemented in a two-step inversion: Elastic impedance inversion and parameter estimation. The introduction of a model constraint and DSVD algorithm in parameter estimation renders the EVA-DSVD inversion more stable. Tests on synthetic data show that the Young’s modulus and Poisson’s ratio are still estimated reasonable with moderate noise. A test on a real data set shows that the estimated results are in good agreement with the results of well interpretation.

scholarly journals THE IMPACT OF UNCERTAINTY ON SUBSIDENCE AND COMPACTION PREDICTION

2009 ◽  
Vol 12 (6) ◽  
pp. 84-95
Author(s):  
Dzung Quoc Ta ◽  
Al-Harthy, M. ◽  
Hunt, S ◽  
Sayers, J.
Keyword(s):  
Gulf Of Mexico ◽  
Young’S Modulus ◽  
Deep Water ◽  
Poisson’S Ratio ◽  
Young's Modulus ◽  
Fluid Pressure ◽  
Poisson's Ratio ◽  
Pore Fluid Pressure ◽  
Water Field ◽  
The Impact

This paper presents the stochastic approach using Monte Carlo simulation as applied to compaction and subsidence estimation in an offshore oil and gas deep-water field in the Gulf of Mexico. The results reveal both the impact of using probability distributions to estimate compaction and subsidence for a disk shaped-homogenous reservoir as well as taking into account Young's modulus, Poisson's ratio and the reduction of pore fluid pressure. The uncertainty reservoir model is also compared with numerical simulation commercial software - Eclipse 300. The stochastic-based simulation results confirm that the deterministic results obtained from the coupled geomechanical - fluid flow model are in the range of acceptable distribution for stochastic simulation. The sensitive analysis shown that Young's modulus has more impact on compaction than Poisson's ratio. The results also presented that values of Young's modulus in this deep-water field in Gulf of Mexico lying beyond 140,000psi are insignificant to compaction and subsidence. Based on output results of compaction and subsidence with the stochastic model, potential reservoirs presenting subsidence and compaction are described as an uncertainty range within distribution of Young's modulus, Poisson's ratio and the reduction of pore fluid pressure in large-scale regional model.

Multiparameter 𝓁1 norm waveform fitting: Interpretation of Gulf of Mexico reflection seismograms

Geophysics ◽  
1999 ◽  
Vol 64 (4) ◽  
pp. 1023-1035 ◽  
Author(s):  
Hugues A. Djikpéssé ◽  
Albert Tarantola
Keyword(s):  
Gulf Of Mexico ◽  
Poisson’S Ratio ◽  
Seismic Refraction ◽  
Synthetic Seismograms ◽  
Poisson's Ratio ◽  
Inversion Method ◽  
Earth Model ◽  
Additional Parameter ◽  
Shear Properties ◽  
Waveform Fitting

Estimation of the elastic properties of the crust from surface seismic recordings is of great importance for the understanding of lithology and for the detection of mineral resources. Although in marine reflection experiments only P-waves are recorded, information on shear properties of the medium is contained in multioffset reflection seismograms. Being able to retrieve both dilatational and shear properties gives stronger constraints on the lithology. It is therefore desirable to recover isotropic elastic parameters from multioffset seismograms. Unfortunately, most classical waveform fitting methods used for extracting shear properties of the subsurface are based on a 1-D earth model assumption and on linear approximations of the wave equations. In this paper, a 2.5-D elastic waveform inversion method is used to extract the variations of acoustic impedance and Poisson’s ratio from marine multioffset reflection seismograms collected in the Gulf of Mexico area. A complete seismic profile is interpreted, including complex physical phenomena apparent in the data, such as unconsolidated sediment reflections and seismic refraction events. The amplitude of the reflections cannot be explained by one parameter related to the dilatational properties (P-impedance) only, when trying to minimize the least absolute fit between observed and synthetic seismograms. When adding an additional parameter related to shear properties (Poisson’s ratio), the fit between observed and synthetic seismograms improves. The resulting 2-D models of P-impedance and Poisson’s ratio contrasts are anticorrelated almost everywhere in depth, except where hydrocarbons are present. The estimation of physical P-impedance and Poisson’s ratio models by a full waveform fitting allows lithology characterization and, therefore, the delineation of a shale‐over‐gas sand reservoir.

scholarly journals Time-average velocity estimation through surface-wave analysis: Part 2 — P-wave velocity

Geophysics ◽  
2017 ◽  
Vol 82 (3) ◽  
pp. U61-U73 ◽  
Author(s):  
Laura Valentina Socco ◽  
Cesare Comina
Keyword(s):  
Wave Velocity ◽  
Poisson’S Ratio ◽  
Average Velocity ◽  
P Wave ◽  
Poisson's Ratio ◽  
S Wave ◽  
Seismic Line ◽  
Velocity Models ◽  
P Wave Velocity ◽  
Time Average

Surface waves (SWs) in seismic records can be used to extract local dispersion curves (DCs) along a seismic line. These curves can be used to estimate near-surface S-wave velocity models. If the velocity models are used to compute S-wave static corrections, the required information consists of S-wave time-average velocities that define the one-way time for a given datum plan depth. However, given the wider use of P-wave reflection seismic with respect to S-wave surveys, the estimate of P-wave time-average velocity would be more useful. We therefore focus on the possibility of also extracting time-average P-wave velocity models from SW dispersion data. We start from a known 1D S-wave velocity model along the line, with its relevant DC, and we estimate a wavelength/depth relationship for SWs. We found that this relationship is sensitive to Poisson’s ratio, and we develop a simple method for estimating an “apparent” Poisson’s ratio profile, defined as the Poisson’s ratio value that relates the time-average S-wave velocity to the time-average P-wave velocity. Hence, we transform the time-average S-wave velocity models estimated from the DCs into the time-average P-wave velocity models along the seismic line. We tested the method on synthetic and field data and found that it is possible to retrieve time-average P-wave velocity models with uncertainties mostly less than 10% in laterally varying sites and one-way traveltime for P-waves with less than 5 ms uncertainty with respect to P-wave tomography data. To our knowledge, this is the first method for reliable estimation of P-wave velocity from SW data without any a priori information or additional data.

3-D AVO analysis and modeling applied to fracture detection in coalbed methane reservoirs

Geophysics ◽  
1997 ◽  
Vol 62 (6) ◽  
pp. 1683-1695 ◽  
Author(s):  
Antonio C. B. Ramos ◽  
Thomas L. Davis
Keyword(s):  
Poisson’S Ratio ◽  
Coalbed Methane ◽  
Spatial Location ◽  
Azimuthal Anisotropy ◽  
P Wave ◽  
Poisson's Ratio ◽  
Seismic Survey ◽  
Data Set ◽  
Avo Analysis ◽  
Coalbed Methane Reservoir

Over the years, amplitude variation with‐offset (AVO) analysis has been used successfully to predict reservoir properties and fluid contents, in some cases allowing the spatial location of gas‐water and gas‐oil contacts. In this paper, we show that a 3-D AVO technique also can be used to characterize fractured reservoirs, allowing spatial location of crack density variations. The Cedar Hill Field in the San Juan Basin, New Mexico, produces methane from the fractured coalbeds of the Fruitland Formation. The presence of fracturing is critical to methane production because of the absence of matrix permeability in the coals. To help characterize this coalbed reservoir, a 3-D, multicomponent seismic survey was acquired in this field. In this study, prestack P‐wave amplitude data from the multicomponent data set are used to delineate zones of large Poisson's ratio contrasts (or high crack densities) in the coalbed methane reservoir, while source‐receiver azimuth sorting is used to detect preferential directions of azimuthal anisotropy caused by the fracturing system of coal. Two modeling techniques (using ray tracing and reflectivity methods) predict the effects of fractured coal‐seam zones on angle‐dependent P‐wave reflectivity. Synthetic common‐midpoint (CMP) gathers are generated for a horizontally layered earth model that uses elastic parameters derived from sonic and density log measurements. Fracture density variations in coalbeds are simulated by anisotropic modeling. The large acoustic impedance contrasts associated with the sandstone‐coal interfaces dominate the P‐wave reflectivity response. They far outweigh the effects of contrasts in anisotropic parameters for the computed models. Seismic AVO analysis of nine macrobins obtained from the 3-D volume confirms model predictions. Areas with large AVO intercepts indicate low‐velocity coals, possibly related to zones of stress relief. Areas with large AVO gradients identify coal zones of large Poisson's ratio contrasts and therefore high fracture densities in the coalbed methane reservoir. The 3-D AVO product and Poisson's variation maps combine these responses, producing a picture of the reservoir that includes its degree of fracturing and its possible stress condition. Source‐receiver azimuth sorting is used to detect preferential directions of azimuthal anisotropy caused by the fracturing system of coal.

Acoustic properties of carbonates: Effects of rock texture and implications for fluid substitution

Geophysics ◽  
2008 ◽  
Vol 73 (2) ◽  
pp. B51-B65 ◽  
Author(s):  
Klaas Verwer ◽  
Hendrik Braaksma ◽  
Jeroen A. Kenter
Keyword(s):  
Shear Modulus ◽  
Wave Velocity ◽  
Poisson’S Ratio ◽  
Acoustic Properties ◽  
P Wave ◽  
Poisson's Ratio ◽  
Fluid Substitution ◽  
Data Set ◽  
Rock Types ◽  
Rock Texture

More than 250 plugs from outcrops and three nearby boreholes in an undisturbed reef of Miocene (Tortonian) age were quantitatively analyzed for texture, mineralogy, and acoustic properties. We measured the P- and S-waves of carbonate rocks under dry (humidified) and brine-saturated conditions at [Formula: see text] effective pressure with an ultrasonic pulse transmission technique [Formula: see text]. The data set was compared with an extensive database of petrophysical measurements of a variety of rock types encountered in carbonate sedimentary sequences. Two major textural groups were distinguished on the basis of trends in plots of compressional-wave velocity versus Poisson’s ratio (a specific ratio of P-wave over S-wave velocity). In granular rocks, the framework of depositional grains is the main medium for acoustic-wave propagation; in crystalline rocks, this medium is provided by a framework of interlocking crystals formed during diagenesis. Rock textures are connected to primary depositionalparameters and a diagenetic overprint through the specific effects on Poisson’s ratio. Calculating acoustic velocities using Gassmann fluid substitution modeling approximates measured saturated velocities for 55% of the samples (3% error tolerance); however, it shows considerable errors because shear modulus changes with saturation. Introducing brine into the pore space may decrease the shear modulus of the rock by approximately [Formula: see text] or, alternatively, increase it by approximately [Formula: see text]. This change in shear modulus is coupled with the texture of the rock. In granular carbonates, the shear modulus decreases; in crystalline and cemented carbonates, it increases with saturation. The results demonstrate the intimate relationship between elastic behavior and the depositional and diagenetic properties of carbonate sedimentary rocks. The results potentially allow the direct extraction of granular and crystalline rock texture from acoustic data alone and may help predict rock types from seismic data and in wells.

P- and S-wave velocity models of shallow dry sand formations from surface wave multimodal inversion

Geophysics ◽  
2016 ◽  
Vol 81 (4) ◽  
pp. R197-R209 ◽  
Author(s):  
Paolo Bergamo ◽  
Laura Valentina Socco
Keyword(s):  
Surface Wave ◽  
Wave Velocity ◽  
Power Law ◽  
Poisson’S Ratio ◽  
Real Data ◽  
P Wave ◽  
Poisson's Ratio ◽  
S Wave ◽  
Data Set ◽  
Seismic Characterization

Surficial formations composed of loose, dry granular materials constitute a challenging target for seismic characterization. They exhibit a peculiar seismic behavior, characterized by a nonlinear seismic velocity gradient with depth that follows a power-law relationship, which is a function of the effective stress. The P- and S-wave velocity profiles are then characterized by a power-law trend, and they can be defined by two power-law exponents [Formula: see text] and two power-law coefficients [Formula: see text]. In case of depth-independent Poisson’s ratio, the P-wave velocity profile can be defined using the [Formula: see text] power-law parameters and Poisson’s ratio. Because body wave investigation techniques (e.g., P-wave tomography) may perform ineffectively on such materials because of high attenuation, we addressed the potential of surface-wave method for a reliable seismic characterization of shallow formations of dry, uncompacted granular materials. We took into account the dependence of seismic wave velocity on effective pressure and performed a multimodal inversion of surface-wave data, which allowed the [Formula: see text] and [Formula: see text] profiles to be retrieved. The method requires the selection of multimodal dispersion curve points referring to surface-wave frequency components traveling within the granular media formation and their inversion for the S-wave power-law parameters and Poisson’s ratio. We have tested our method on a synthetic dispersion curve and applied it to a real data set. In both cases, the surficial layer was made of loose dry sand. The test on the synthetic data set confirmed the reliability of the proposed procedure because the thickness and the [Formula: see text], [Formula: see text] profiles of the sand layer were correctly estimated. For the real data, the outcomes were validated by other geophysical measurements conducted at the same site and they were in agreement with similar studies regarding loose sand formations.

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