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Petroleum, United States

Sava P.,Colorado School of Mines | Vlad I.,Fusion Petroleum Technologies Inc.
Geophysics | Year: 2011

Extended common-image-point (CIP) gathers contain all of the necessary information for decomposition of reflectivity as a function of the reflection and azimuth angles at selected locations in the subsurface. This decomposition operates after the imaging condition applied to wavefields reconstructed by any type of wide-azimuth migration method, e.g., using downward continuation or time reversal. The reflection and azimuth angles are derived from the extended images using analytic relations between the space-lag and time-lag extensions. The transformation amounts to a linear Radon transform applied to the CIPs obtained after applying the extended imaging condition. If information about the reflector dip is available at the CIP locations, then only two components of the space-lag vectors are required, thus reducing computational cost and increasing the affordability of the method. Applications of this method include the study of subsurface illumination in areas of complex geology where ray-based methods are not usable and the study of amplitude variation with reflection and azimuth angles if the subsurface illumination is sufficiently dense. Migration velocity analysis could also be implemented in the angle domain, although an equivalent implementation in the extended domain is less costly and more effective. © 2011 Society of Exploration Geophysicists. Source

Bevc D.,Fusion Petroleum Technologies Inc. | Zarantonello S.E.,Algorithmica Llc | Harris J.M.,Stanford University
72nd European Association of Geoscientists and Engineers Conference and Exhibition 2010: A New Spring for Geoscience. Incorporating SPE EUROPEC 2010 | Year: 2010

We present results of an integrated simulation study to assess the effectiveness of surface seismic imaging for monitoring CO2 sequestration. We considered two scenarios. In the first, injected CO2 remained confined within a shallow coal formation. In the second, the sequestered CO2 gas leaked through a semipermeable shale layer to an overlying sand unit sealed above. The reservoir and seismic simulations required the construction of 3D geologic and facies models, the estimations of seismic velocities based on rock physics correlations, and the development of geostatistical dual-porosity reservoir descriptions of the coal and overlying shale and sand units. We ran the 3D reservoir simulations with an equation-of-state compositional reservoir simulator with the capability to model adsorption of injected CO2 in coal, desorption of CH4, and matrix shrinkage-swelling effects. We generated synthetic seismograms by simulating the propagation of acoustic waves through the 3D heterogeneous media, and used reverse time migration to create 3D seismic images corresponding to the state of the reservoir at the beginning and end of ten years of CO2 injection. The resulting seismic images clearly identified the regions of CO2 gas saturation, closely matching the gas saturation profiles predicted by the reservoir simulator. © 2010, European Association of Geoscientists and Engineers. Source

Huffman A.R.,Fusion Petroleum Technologies Inc. | Meyer J.,Fusion Petroleum Technologies Inc. | Gruenwald R.,Repsol | Buitrago J.,Repsol | And 4 more authors.
SPE Middle East Oil and Gas Show and Conference, MEOS, Proceedings | Year: 2011

In recent years, methods have been developed to enable robust pressure prediction in the presence of multiple pressure mechanisms including undercompaction, unloading processes (secondary pressure mechanisms) and at great depth, the onset of secondary chemical compaction. These models utilize geological and geophysical information to constrain the calibration models and the depths at which they must be applied to develop a multilayer pressure calibration model that will accurately predict pressures for prospect-level analysis and pre-drill prediction. These models are then integrated with the velocity field and the geological and geophysical information to predict pore pressures and fracture pressures at greater depths than have been previously feasible. This methodology has been tested in multiple basins and has been proven to be effective in helping drilling engineers improve well performance through more effective mud and casing program designs that significantly reduces well costs and rig time. Recent application of elastic and acoustic inversion in complex carbonate environments have also proven effective in predicting pressures in environments where the shales can be separated from the carbonates. The approach requires that the inverted data be separated into the shale and carbonate velocity trends to allow the shales to be used for effective stress prediction while the complete velocity field is used for time-depth conversion. These studies have revealed that pore pressure prediction from mixed lithology (carbonate and shale) environments is feasible using advanced inversion methods. Successful pressure prediction in this type of geology requires seismic data that is of sufficient quality to enable a robust acoustic and/or elastic inversion to be performed that can separate the shale velocities for effective stress calculation, and perform time-depth conversion from the complete velocity field. As the amount of shale present in the geologic section becomes smaller, the ability to predict pressures decreases. The presence of marls also presents a problem because the carbonate material within the shale suppresses the sensitivity of the shale velocity to pore pressure. Copyright 2011, Society of Petroleum Engineers. Source

Gruenwald R.,REMSA | Buitrago J.,REMSA | Dessay J.,REMSA | Diaz C.,REMSA | And 3 more authors.
72nd European Association of Geoscientists and Engineers Conference and Exhibition 2010: A New Spring for Geoscience. Incorporating SPE EUROPEC 2010 | Year: 2010

As part of the exploration process for a prospective area in the Sirte Basin, offshore Libya, geopressure prediction was performed on 200 km2 of 3D seismic data in two subsets of 100 km2 each from the NC202 survey. Fluid and fracture pressure interpretation was based on well control and seismic interval velocities. Offset well control included one well located within the seismic survey area. This well contained no RFT or MDT data, but did have mud weights (MW), leak-off tests and wireline logs. A second well near the survey was tied by a 2D seismic line. This well contained MDT and DST data. © 2010, European Association of Geoscientists and Engineers. Source

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