Model Parameterization and P-wave AVA Direct Inversion for Young’s Impedance

Zong, Zhaoyun; Yin, Xingyao

doi:10.1007/s00024-017-1529-7

Cited by 15 publications

(5 citation statements)

References 18 publications

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“…The physical property parameter prediction method based on linearized rock physics inversion applies to linear or slightly nonlinear rock physical models (Zhang et al, 2020b;Pan et al, 2021). For the highly nonlinear rock physical model, the empirical formula method is used to predict the porosity (Zong and Yin, 2017;Chen et al, 2017;Pan et al, 2017;. It is to obtain a statistical empirical relationship between porosity and rock elastic parameters (such as P-wave velocity, S-wave velocity, density, and elastic impedance) by using rock physics test data and logging data and then use this statistical empirical relationship to convert the elastic parameters obtained by seismic inversion into porosity parameters.…”

Section: Porosity Inversionmentioning

confidence: 99%

Rock Physical Modeling of Tight Sandstones Based on Digital Rocks and Reservoir Porosity Prediction From Seismic Data

et al. 2022

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Digital rock physics (DRP) has become an important tool to analyze the characteristics of pore structures and minerals and reveal the relationships between microscopic structures and the physical properties of reservoirs. However, it is greatly difficult to upscale the rock physical parameters, such as P-wave velocity, S-wave velocity, and elastic moduli, from DRP to large-scale boreholes and reservoirs. On the other hand, theoretical rock physical modeling can establish the internal relationship between the elastic properties and physical parameters of tight sandstones, which provides a theoretical basis for seismic inversion and seismic forward modeling. Therefore, the combination of digital rock physics and rock physical modeling can guide the identification and evaluation of the gas reservoir’s “sweet spot.” In this study, the CT images are used to analyze the mineral and pore characteristics. After that, the V-R-H model is used to calculate the equivalent elastic moduli of rocks containing only the mineral matrix, and then, the differential equivalent medium (DEM) model is used to obtain the elastic moduli of dry rocks containing minerals and pores. Subsequently, the homogeneous saturation model is used to fill the fluids in the pores and the Gassmann equation is used to calculate the equivalent elastic moduli of the saturated rock of tight sandstones. Rock physical modeling is calibrated, and the reliability of the rock physical model is verified by comparing those with the logging data. Afterward, the empirical relationship of rock porosity established from CT images and rock elastic moduli is obtained, and then, the elastic parameters obtained by seismic data inversion are converted into porosity parameters by using this empirical relationship. Finally, the porosity prediction of large-scale reservoirs in the study area is realized to figure out the distribution of gas reservoirs with high porosity. The results show that the H3b and H3c sections of the study area exhibit higher porosity than H3a. For the H3b reservoir, the northeast and middle areas of the gas field are potential targets since their porosity is larger than that of others, from 10% to 20%. Because of the effects of the provenance from the east direction, the southeast region of the H3c reservoir exhibits higher porosity than others.

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Section: Porosity Inversionmentioning

confidence: 99%

Rock Physical Modeling of Tight Sandstones Based on Digital Rocks and Reservoir Porosity Prediction From Seismic Data

et al. 2022

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“…Since Biot [1940Biot [ , 1956Biot [ , 1957Biot [ , 1962 proposed the theory of seismic wave propagation in porous medium, many geophysical experts have carried out in-depth research. Yin et al [2014Yin et al [ , 2015Yin et al [ , 2016 and Zong and Yin [2017] combined this with pre-stack seismic inversion to realize the fluid identification based on the data and model driven. When the seismic wave impinges perpendicularly at the interface of porous medium, some scholars [Geertsma and Smit, 1961;Silin et al, 2004;Silin and Goloshubin, 2010] analyzed the reflection and transmission problems.…”

Section: Introductionmentioning

confidence: 99%

The Characteristics of Reflection and Transmission Coefficients of Porous Medium Saturated with an Ideal Fluid

Zhou

Yin

Zong

2020

Annals of Geophysics

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The underground rock is composed of rock skeleton and pore fluids. When seismic waves propagate in underground medium, it will show complicated change influenced by pore and pore fluids in rocks. It is very important to study the characteristics of reflection and transmission coefficients of seismic waves at the interface and to analyze the properties of the lithology and pore fluids of porous medium, which can reveal the oil and gas bearing in underground medium. Based on the relationship among wave functions, displacement and stress in porous medium, the equation of reflection and transmission coefficients at the interface of porous medium saturated with an ideal fluid is derived. A geological model with sandstone porous medium in the top layer and mudstone porous medium in the bottom layer, the rock skeleton parameters of which vary with porosities, is established. Based on the equation and the model, the variation of reflection and transmission coefficients with the incident angle at the interface of porous medium is studied under the conditions of different pore fluids filling and different porosities. The study shows that the existence of the pore and pore fluids will impede the reflected and transmitted abilities of seismic waves at the interface of porous medium. Combining with the theory of rock physics and well data, the porosities and pore fluids of porous medium can be identified qualitatively by studying the variation of the reflected fast P-and SVwaves with incident angle. The values of reflection and transmission coefficients of slow P-wave are very small, but the variation of that is relatively large due to the influence of the pore and pore fluids. FIGURE 2. The variation of the bulk modulus (a) and shear modulus (b) of rock skeleton with porosities. Properties vp (m/s) vs (m/s) ρ (kg / m 3 ) Sandstone 5592 3767 2170 Mudstone 3390 1625 2523TABLE 3. Equivalent medium model. Where, vp, vs and ρ rep− resent equivalent P−wave velocity, S−wave velocity and density, respectively.

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“…Sharma and Chopra (2015) determine the lithology and brittleness of rocks with a new attribute, which is the product of Young's modulus and density. Similarly to the P-and S-wave * E-mail: panxinpeng1990@gmail.com impedances, the product of Young's modulus and density can be termed as Young's impedance (Zong and Yin 2017). However, the estimation of Young's impedance attribute from surface seismic data is quite arduous and unstable due to the requirements of the information of large incident angles or offsets (Downton 2005;Kabir et al 2006).…”

Section: Introductionmentioning

confidence: 99%

Amplitude variation with incident angle and azimuth inversion for Young's impedance, Poisson's ratio and fracture weaknesses in shale gas reservoirs

Pan

Zhang

2019

Geophysical Prospecting

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By analogy with P‐ and S‐wave impedances, the product of Young's modulus and density can be termed as Young's impedance, which indicates the rock lithology and brittleness of unconventional hydrocarbon reservoirs. Poisson's ratio is also an effective indicator of rock brittleness and fluid property of unconventional reservoirs, and fracture weaknesses indicate the fracture properties (fracturing intensity and fracture fillings) in fracture‐induced unconventional reservoirs. We aim to simultaneously estimate the Young's impedance, Poisson's ratio and fracture weaknesses from wide‐azimuth surface seismic data in a fracture‐induced shale gas reservoir, and use the horizontal transversely isotropic model to characterize the fractures. First, the linearized PP‐wave reflection coefficient in terms of Young's impedance, Poisson's ratio, density and fracture weaknesses is derived for the case of a weak‐contrast interface separating two weakly horizontal transversely isotropic media. In addition, an orthorhombic anisotropic case is also discussed in this paper. Then a Bayesian amplitude variation with incident angle and azimuth scheme with a model constraint is used to stably estimate Young's impedance, Poisson's ratio and fracture weaknesses with only PP‐wave azimuthal seismic data. The proposed approach is finally demonstrated on both synthetic and real data sets with reasonable results.

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Model Parameterization and P-wave AVA Direct Inversion for Young’s Impedance

Cited by 15 publications

References 18 publications

Rock Physical Modeling of Tight Sandstones Based on Digital Rocks and Reservoir Porosity Prediction From Seismic Data

Rock Physical Modeling of Tight Sandstones Based on Digital Rocks and Reservoir Porosity Prediction From Seismic Data

The Characteristics of Reflection and Transmission Coefficients of Porous Medium Saturated with an Ideal Fluid

Amplitude variation with incident angle and azimuth inversion for Young's impedance, Poisson's ratio and fracture weaknesses in shale gas reservoirs

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