Modulus decomposition of compressional and shear velocities in sand bodies

Murphy, William F.; Reischer, Andrew; Hsu, Kai

doi:10.1190/1.1443408

Cited by 153 publications

(80 citation statements)

References 34 publications

(40 reference statements)

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“…However, we have chosen to retain the use of the term β 2 M for the difference between the dry and saturated cases to emphasize its independence from the first term. (Note that Murphy et al (1993) call this term K P , or pore space modulus). Using β 2 M, we can rewrite the equation for P-wave velocity (equation 1) in the saturated case as…”

Section: Biot-gassmann Theory Of Velocity In Porous Rocksmentioning

confidence: 99%

See 1 more Smart Citation

Fluid‐property discrimination with AVO: A Biot‐Gassmann perspective

Russell¹,

Hedlin

Hilterman³

et al. 2003

GEOPHYSICS

286

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This paper draws together basic rock physics, AVO, and seismic amplitude inversion to discuss how fluid discrimination can be performed using pre-stack seismic data. From both Biot and Gassmann theories for porous, fluid-saturated rocks, a general formula is first derived for fluid-property discrimination given that both the P and S impedances are available. In essence, an AVO inversion is transformed into the elastic properties of the pore space. This formula provides a more sensitive discriminator of the pore-fluid saturant than the acoustic impedance and is especially applicable in hard-rock environments. The formulation can be expressed with either the Lamé constants and density, or the bulk and shear moduli and density. Numerical and well-log examples illustrate the applicability of this approach. The combination of an AVO inversion and the parameters of the formula are then discussed to show how this technique can be implemented using pre-stack seismic data. Finally, a shallow gas-sand example from Alberta and a well-log example from Eastern Canada are shown to illustrate the techniques.

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Section: Biot-gassmann Theory Of Velocity In Porous Rocksmentioning

confidence: 99%

“…Goodway et al (1997) proposed the lambda-mu-rho technique, which has met with much success. Hedlin (2000) proposed the pore-modulus method, which was based on work by Murphy et al (1993). Most recently, Hilterman (2001 SEG Distinguished Instructor Short Course) introduced the concept of the fluid discriminant.…”

Section: Introductionmentioning

confidence: 99%

Fluid‐property discrimination with AVO: A Biot‐Gassmann perspective

Russell¹,

Hedlin

Hilterman³

et al. 2003

GEOPHYSICS

286

View full text Add to dashboard Cite

show abstract

“…1 rigidity and arrangement (geometry, compaction, and aspect ratio) of the mineral grains. Murphy et al (1993) define empirical relationships between porosity in sandstones and the ratio of rigidity and shear moduli. In addition to these rock frame properties, the compressibility of fluids inside pores needs to be considered.…”

Section: Introductionmentioning

confidence: 99%

Estimation of rock physics properties from seismic attributes — Part 1: Strategy and sensitivity analysis

2016

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The quantitative estimation of rock physics properties is of great importance in any reservoir characterization. We have studied the sensitivity of such poroelastic rock physics properties to various seismic viscoelastic attributes (velocities, quality factors, and density). Because we considered a generalized dynamic poroelastic model, our analysis was applicable to most kinds of rocks over a wide range of frequencies. The viscoelastic attributes computed by poroelastic forward modeling were used as input to a semiglobal optimization inversion code to estimate poroelastic properties (porosity, solid frame moduli, fluid phase properties, and saturation). The sensitivity studies that we used showed that it was best to consider an inversion system with enough input data to obtain accurate estimates. However, simultaneous inversion for the whole set of poroelastic parameters was problematic due to the large number of parameters and their trade-off. Consequently, we restricted the sensitivity tests to the estimation of specific poroelastic parameters by making appropriate assumptions on the fluid content and/or solid phases. Realistic a priori assumptions were made by using well data or regional geology knowledge. We found that (1) the estimation of frame properties was accurate as long as sufficient input data were available, (2) the estimation of permeability or fluid saturation depended strongly on the use of attenuation data, and (3) the fluid bulk modulus can be accurately inverted, whereas other fluid properties have a low sensitivity. Introducing errors in a priori rock physics properties linearly shifted the estimations, but not dramatically. Finally, an uncertainty analysis on seismic input data determined that, even if the inversion was reliable, the addition of more input data may be required to obtain accurate estimations if input data were erroneous.

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“…For example / can be computed from sonic or density logs. Similarly several numerical relations are available to estimate the drain rock modulus (Zhu and McMechan 1990;Murphy et al 1993;Zinszner and Pellerin 2007). In the present FSM we have used the Murphy et al (1993)'s relation:…”

Section: Formulation Of Fluid Substitution Modeling (Fsm)mentioning

confidence: 99%

Rock physics modeling to assess the impact of spatial distribution pattern of pore fluid and clay contents on acoustic signatures of partially-saturated reservoirs

2015

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The identification of pore fluid type, saturation and distribution pattern within the pore space is of great significance as several seismic and petrophysical properties of porous rocks vary largely by fluid type, saturation and fluid distribution pattern. With the help of rock physics modeling, the impact of fluid saturation as well as fluid distribution pattern on seismic velocities, acoustic impedances and seismic amplitudes is estimated on porous rock of early Cretaceous Mississauga sands. For this purpose two saturation patterns: uniform and patchy saturations are considered within the pore spaces. The primary goal of this study is to understand the vertical and horizontal trends of numerous seismic parameters such as P-wave velocity (V P ), S-wave velocity (V S ), their impedances, V P /V S ratio, bulk density (q b ), seismic reflectivity etc. as a function of fluid saturation, saturation pattern (patchy or homogeneous), porosity (/) and clay content. The results reveal that the seismic parameters and offset dependent amplitudes are very sensitive to pore fluid saturation and distribution patterns and physical properties. As the hydrocarbons (oil/gas) saturation increases, the compressional wave velocity decreases. P-wave velocity is 20-40 % higher in case of patchy saturation than of homogeneous saturation. Similarly, reservoir porosity and clay matrix control the elastic response of porous rock due to which seismic velocities decrease with increase in porosity and clay content.

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Modulus decomposition of compressional and shear velocities in sand bodies

Cited by 153 publications

References 34 publications

Fluid‐property discrimination with AVO: A Biot‐Gassmann perspective

Fluid‐property discrimination with AVO: A Biot‐Gassmann perspective

Estimation of rock physics properties from seismic attributes — Part 1: Strategy and sensitivity analysis

Rock physics modeling to assess the impact of spatial distribution pattern of pore fluid and clay contents on acoustic signatures of partially-saturated reservoirs

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