Cross‐equalization data processing for time‐lapse seismic reservoir monitoring: A case study from the Gulf of Mexico

Geophysics ◽  
2001 ◽  
Vol 66 (4) ◽  
pp. 1015-1025 ◽  
Author(s):  
J. E. Rickett ◽  
D. E. Lumley

Nonrepeatable noise, caused by differences in vintages of seismic acquisition and processing, can often make comparison and interpretation of time‐lapse 3‐D seismic data sets for reservoir monitoring misleading or futile. In this Gulf of Mexico case study, the major causes of nonrepeatable noise in the data sets are the result of differences in survey acquisition geometry and binning, temporal and spatial amplitude gain, wavelet bandwidth and phase, differential static time shifts, and relative mispositioning of imaged reflection events. We attenuate these acquisition and processing differences by developing and applying a cross‐equalization data processing flow for time‐lapse seismic data. The cross‐equalization flow consists of regridding the two data sets to a common grid; applying a space and time‐variant amplitude envelope balance; applying a first pass of matched filter corrections for global amplitude, bandwidth, phase and static shift corrections, followed by a dynamic warp to align mispositioned events; and, finally, running a second pass of constrained space‐variant matched filter operators. Difference sections obtained by subtracting the two data sets after each step of the cross‐equalization processing flow show a progressive reduction of nonrepeatable noise and a simultaneous improvement in time‐lapse reservoir signal.

Geophysics ◽  
2018 ◽  
Vol 83 (4) ◽  
pp. M41-M48 ◽  
Author(s):  
Hongwei Liu ◽  
Mustafa Naser Al-Ali

The ideal approach for continuous reservoir monitoring allows generation of fast and accurate images to cope with the massive data sets acquired for such a task. Conventionally, rigorous depth-oriented velocity-estimation methods are performed to produce sufficiently accurate velocity models. Unlike the traditional way, the target-oriented imaging technology based on the common-focus point (CFP) theory can be an alternative for continuous reservoir monitoring. The solution is based on a robust data-driven iterative operator updating strategy without deriving a detailed velocity model. The same focusing operator is applied on successive 3D seismic data sets for the first time to generate efficient and accurate 4D target-oriented seismic stacked images from time-lapse field seismic data sets acquired in a [Formula: see text] injection project in Saudi Arabia. Using the focusing operator, target-oriented prestack angle domain common-image gathers (ADCIGs) could be derived to perform amplitude-versus-angle analysis. To preserve the amplitude information in the ADCIGs, an amplitude-balancing factor is applied by embedding a synthetic data set using the real acquisition geometry to remove the geometry imprint artifact. Applying the CFP-based target-oriented imaging to time-lapse data sets revealed changes at the reservoir level in the poststack and prestack time-lapse signals, which is consistent with the [Formula: see text] injection history and rock physics.


2019 ◽  
Author(s):  
Dmitry Popik ◽  
Roman Pevzner ◽  
Stanislav Glubokovskikh ◽  
Valeriya Shulakova ◽  
Sasha Ziramov

Geophysics ◽  
2003 ◽  
Vol 68 (3) ◽  
pp. 803-814 ◽  
Author(s):  
Madhumita Sengupta ◽  
Gary Mavko ◽  
Tapan Mukerji

The goal of this paper is to interpret and analyze time‐lapse seismic data quantitatively to better understand subsurface fluid saturations and saturation scales. We present a case study of a time‐lapse seismic survey. Water and gas were injected into an oil‐producing reservoir, and repeat seismic surveys were collected to monitor the subsurface fluids over a period of 14 years. In this study, we show that the subresolution spatial distribution of fluids, not captured by traditional flow simulators can impact the seismic response. Although there is a good qualitative match between the fluid changes predicted by the flow simulator and the fluid changes interpreted from the seismic data, the simulator predicts smooth saturation profiles that do not quantitatively match the time‐lapse seismic changes. We find that downscaling smooth saturation outputs from the flow simulator to a more realistic patchy distribution is required to provide a good quantitative match with the near‐ and far‐offset time‐lapse data, even though the fine details in the saturation distribution are below seismic resolution. We downscaled the smooth saturations from the simulator by incorporating high spatial frequencies from well logs and constraining the saturations to the total mass balance predicted by the flow simulator. The computed seismic response of the downscaled saturation distributions matched the real time‐lapse seismic data much better than the saturation distributions taken directly from the simulator. This study demonstrates the feasibility of using seismic and well‐log data to constrain subblock saturation scales, unobtainable from flow simulation alone. This important result has the potential to significantly impact and enhance the applicability of seismic data in reservoir monitoring.


1998 ◽  
Author(s):  
Dan Ebrom ◽  
Paul Krail ◽  
Larry Scott

1999 ◽  
Author(s):  
J.J. Shyeh ◽  
D.H. Johnston ◽  
J.E. Eastwood ◽  
M. Khan ◽  
L.R. Stanley

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