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ABSTRACT The estimation of fluid properties from indirect geophysical data is limited by, and should account for, the uncertainty of the measurements. However only in recent years has this lead to results in this field tied to their corresponding uncertainty of outcome. This study presents a stochastic inversion, from geophysical data, and a quantified probability of the fluid modulus within target layers of two different hydrocarbon bearing fields. The probabilistic inversion method based on Gassmann's equation, as described by White and Castagna (2002), is applied.
- Europe > Norway > North Sea (0.48)
- North America > United States > Texas (0.47)
- North America > United States > Texas > Frio Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Sognefjord Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Heather Formation (0.99)
- (10 more...)
A Case Study Of Fluid Modulus Inversion For Miocene Sandstone Reservoir, Gulf of Mexico
Fouad, Khaled (Institute for Exploration and Development Geosciences, U. of Oklahoma) | Castagna, John P. (Institute for Exploration and Development Geosciences, U. of Oklahoma) | Lamb, William (Institute for Exploration and Development Geosciences, U. of Oklahoma) | White, Luther (Institute for Exploration and Development Geosciences, U. of Oklahoma) | Siegfried, Bob (Gas Technology Institute)
Summary In this paper, we apply the stochastic inversion technique described in White et al. (2002), which uses seismic amplitudes and statistical rock properties information, to generate probability distributions of the fluid modulus and fluid density in a prospective reservoir. A case study on a deep Gulf of Mexico Miocene sandstone reservoir shows that valuable stochastic estimations of fluid modulus can be achieved from compressional-wave reflectivities, even without well control. Introduction Measuring the fluid modulus and density in a prospective reservoir from seismic amplitude is a challenging task. Although seismic amplitudes contain information related to properties of fluids saturating rocks adjacent to a reflection boundary, they are strongly affected by rock frame properties of the reservoir and seal impedance among other perturbing factors (Castagna et al. 1993).
- North America > United States > Utah (0.19)
- North America > United States > Oklahoma > Cleveland County > Norman (0.16)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (0.89)
Summary A probabilistic inversion approach is combined with Gassmann’s equations to determine pore fluid modulus using elastic wave velocities. Numerical examples show that, even when uncertainties in input parameters are relatively large, useful estimates of fluid modulus can sometimes be obtained. More importantly, uncertainties in estimated fluid moduli and measures of information content can be calculated. For a well log data example, inverted fluid moduli compare favorably to moduli derived from conventional well log analysis. Introduction Seismic direct hydrocarbon indication using amplitude anomalies is based on the relationship between seismic impedance and pore fluid properties. Seismic impedance depends on both the pore fluid modulus (Kf) and the fluid density among other factors.
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.52)