Conventional marine acquisition uses a streamer towed at a constant depth. The resulting receiver ghost notch gives the maximum recoverable frequency. To push this limit, the streamer must be towed at a quite shallow depth, but this compromises the low frequencies. Variable-depth streamer (VDS) acquisition is an acquisition technique aimed at achieving the best possible signal-to-noise ratio at low frequencies by towing the streamer very deeply, but by using a depth profile varying with offset in order not to limit the high-frequency bandwidth by notches as in conventional constant-depth streamer acquisition. The idea is to use notch diversity, each receiver having a different notch, so that the final result, combining different receivers, will have no notches. The key step to process VDS acquisitions is the receiver deghosting. We found that the optimal receiver deghosting, instead of being a preprocessing step, should be done postimaging, by using a dual-input, migration and mirror migration, and a new joint deconvolution algorithm that produces a 3D real amplitude deghosted output. This method can be applied poststack, the inputs being the migration and mirror migration images and the output being the deghosted image. Using a multichannel joint deconvolution, the inputs are the migrated and mirror migrated image gathers and the outputs are the prestack deghosted image gathers. This method preserves the amplitude-versus-offset behavior, as the deghosted output can be seen on synthetic examples to be equal to a reference computed by migrating the data modeled without any reflecting water surface. A real data set was used to illustrate this method, and another one was used to check the possibility of performing prestack elastic inversion on the deghosted gathers.

An integrated workflow, including careful seismic data conditioning, pre-stack elastic inversion and seismic lithology classification has been applied to predict the distribution of channel sands in a complex turbiditic reservoir. Three partial stacks, with angles in the range 8-50 degrees, have been calibrated using elastic logs at three well locations. A well-based feasibility shows that reservoir sands can in theory be identified from a cross plot of Poisson's ratio versus P-wave impedance. In practice, seismic lithology discrimination is challenging due to a complex AVA response, which is affected by the difference in seismic frequency content between near and ultra far angles. Our simultaneous elastic inversion procedure is able to account for the angle-dependent change in seismic bandwidth and delivers high-resolution estimates of both Pand S-wave impedances, which have been used to calculate a sand lithology cube. The inversion was performed in a layered stratigraphic framework that has been automatically extracted from seismic dip information. This has yielded 3-D images of reservoir elastic properties that better conform to the complex shapes of the channelized sand deposits.

A permanent reservoir monitoring system has been installed for Shell at the end of 2010, on a medium heavy-oil onshore field situated in the north-east of The Netherlands, in the context of re-development of oil production by Gravity Assisted Steam Flood. The first challenge was to continuously monitor, with seismic reflection, the lateral and vertical expansion of the steam chest injected in the reservoir during production over more than a year. As the 4D seismic attributes obtained from monitoring fit the measurements made at observation, production and injector wells, the 2D monitoring system was extended to 3D in April 2012. The second challenge was quantify seismic amplitude variations in terms of petro-acoustic parameters. For that purpose 4D inversion was performed on continuous 2D and 3D seismic monitoring data in order to quantify the lateral and vertical expansion of the steam chest on a daily basis. The 4D inversion results not only point out that the inversion enables to quantify the 4D effects in terms of P-impedance variations, but also greatly improves the vertical location of these events. Moreover, the percentage of maximum impedance variations and the thickness where these variations are observed are in good agreement with the petro-elastic model.

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Independent inversion of base and monitor seismic surveys can yield estimates of elastic properties that are inconsistent with expected production effects. We therefore propose a global time-lapse inversion scheme, involving joint inversion of base and monitor data. All vintages and input angle stacks are combined in a single objective function, which is optimized using simulated annealing to estimate the time-variant distribution of elastic attributes that best matches all available data. The multi-vintage nature of the optimization allows us to incorporate flexible, user-defined rock physics constraints on the evolution of V p , V s and density between consecutive surveys. There are no restrictions on the number of input angle stacks or number of monitor surveys. The constrained, global inversion solution can therefore be easily updated as new data become available. We apply the global 4-D inversion with rock physics coupling to data from the Brage Field and compare results with a workflow involving separate inversions of base and monitor data. The global 4-D inversion results are combined with a time-lapse Bayesian fluid classification scheme to map production-induced fluid movements and quantify associated uncertainty.