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In some areas, seismic data can exhibit the effects of strong azimuthal anisotropy (AA). One of the major causes of AA can be anomalous horizontal stress regimes, which can be modeled as horizontally transverse isotropy (HTI). The Stybarrow field, located offshore NW Australia in the Carnarvon sedimentary basin, is one such area, where strong horizontal stress conditions have been present throughout the basin’s tectonic history. We find evidence for AA in repeat 3D seismic data acquired at two separate azimuths over the Stybarrow field. AA is observed in amplitude versus offset (AVO) reflection amplitude difference maps and cross plots, and is consistent with dipole shear logs and borehole breakout data in the area. We model azimuthal AVO responses using Ruger’s HTI AVO equation, using the anisotropy parameters derived from dipole shear logs, and compare the results with AVO data from the two 3D seismic surveys. Certain fault blocks (but not all) exhibit the same AAVO trend in the seismic data as those modeled from log data, consistent with a stress-induced HTI anisotropic model interpretation.

Oilfield Places: Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Stybarrow Oil Field (0.99)

SPE Disciplines: Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)

Shragge, Jeffrey (CPGCO2) | Lumley, David (CPGCO2)

Time-lapse analysis of 4D seismic data acquired at different stages of hydrocarbon production or fluid/gas injection has been very successful at capturing detailed reservoir changes (e.g., pressure, saturation, fluid flow). Conventionally, 4D seismic analysis is performed in the time-migrated domain assuming a fixed migration velocity model; however, this scenario is violated when the subsurface velocity is significantly altered by production/injection effects resulting in large time-shift anomalies and complex 4D wavefield coda. For these scenarios we argue that one should use a robust 4D analysis procedure involving iterative wave-equation prestack depth migration and time-lapse velocity analysis. We adapt 3D image-domain wave-equation migration velocity analysis (WEMVA) to such time-lapse scenarios to backproject discrepancies (residuals) in migrated baseline, monitor, and time-lapse images to estimate 4D velocity model perturbations. We highlight the differences between the 3D and 4D WEMVA inversion problems, and how we constrain 4D perturbation estimates to preferentially be updated within the reservoir zone. We demonstrate the benefits of various 4D WEMVA strategy in a set of synthetic experiments that involve estimating time-lapse model perturbations arising from a thin layer (<20m) of injected CO

analysis, approach, artificial lift system, baseline, difference, estimate, Figure, formation evaluation, gas injection method, gas lift, image, inversion, migration, Migration Velocity analysis, model, monitor, perturbation, reservoir simulation, slowness, slowness model, slowness perturbation, velocity, Wemva

Oilfield Places: Europe > Norway > North Sea > Central North Sea > Sleipner Gas and Condensate Field (0.99)

SPE Disciplines: Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)

Knowledge of the pressure dependence of elastic rock properties is useful for time-lapse monitoring of hydrocarbon, groundwater, and CO

SPE Disciplines:

- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (0.68)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Integration of geomechanics in models (0.61)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (0.48)

Pevzner, Roman (Curtin University) | Galvin, Robert J. (Curtin University) | Madadi, Mahyar (Curtin University) | Urosevic, Milovan (Curtin University) | Caspari, Eva (Curtin University) | Gurevich, Boris (Curtin University) | Lumley, David (University of Western Australia) | Shulakova, Valeriya (CSIRO) | Cinar, Yildiray (University of New South Wales) | Tcheverda, Vladimir (Trofimuk Institute of Geology)

A key objective of Stage 2 of the CO2CRC Otway Project is to explore the ability of geophysical methods to detect and monitor injection of greenhouse gas into a saline formation. For this purpose, injection of some 10,000 – 30,000 t of gas mixture (80/20% CO

Oilfield Places:

- Oceania > Australia > Victoria > Otway Basin (0.99)
- Oceania > Australia > Victoria > Naylor Field (0.99)
- Oceania > Australia > South Australia > Otway basin (0.99)
- Oceania > Australia > Victoria > Paaratte Gas Field (0.98)

SPE Disciplines: Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)

The effect of single-phase fluid saturation on the seismic bulk modulus of a rock is well understood; however, the behavior becomes more complex when multiple fluids are present. Several fluid mixing theories have been developed (e.g., Voigt, Reuss, and Hill) and each is valid in certain situations; however, in some scenarios it is unclear which theory to select, or indeed whether any are accurate. The critical wave propagation behavior depends on the manner that fluids are spatially distributed within the rock, compared to a seismic wavelength. We apply elastic finite-difference modeling to different rock-fluid distribution scenarios and replicate behavior described by various theoretical, empirical and lab data results. Significantly, our results compare well with observations from lab experiments, yet do not rely on poroelastic or squirt-flow models whose parameters are difficult to estimate in real reservoir settings. Our elastic scattering approach is less computationally expensive than poroelastic modeling and can be more easily applied to actual reservoir rock and fluid distributions. Our results provide us with a powerful new tool to analyze and predict the effects of multiple fluids and ‘patchy’ saturation on elastic moduli and seismic velocities. They also challenge assumptions about the controlling factors on saturated bulk moduli, suggesting they are more strongly affected by the spatial fluid distribution properties and wave scattering, than by pore-scale fluid flow effects.