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Elastic Prestack Waveform Inversion: Case Studies
Vassiliou, Anthony (GeoEnergy Inc) | Lau, August (Apache Corp.) | Yin, Chuan (Apache Corp.) | Greenspon, Mike (Apache Corp.) | Hilliard, Mark (ConocoPhillips)
Summary During the last five years elastic prestack waveform inversion has been applied on a number of case studies. Recently isotropic elastic prestack waveform inversion has been extended to VTI anisotropic prestack waveform inversion. The case studies in this presentation refer to development of onshore oil and gas fields in North America. Seismic inversion has been deployed to derisk the drill locations and also generate improved reserve estimates prior to drilling. Prestack waveform inversion estimates elastic parameters by matching the seismic waveforms on each gather with the NMO correction removed over the complete zone of interest. In one particular case study we have compared a prestack waveform inversion with the results of an angle stack inversion.
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic modeling (1.00)
- Management > Professionalism, Training, and Education > Communities of practice (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Knowledge management (1.00)
Summary Redevelopment of old fields in the U.S. onshore Gulf Coast requires identifying reservoir compartments and inter-well connectivity, as well as verification of fluid content in undrilled areas. New drill locations are mainly attic locations in water drive reservoirs and reservoir compartments that were not penetrated by existing wells. Seismic inversion can be used as another tool to de-risk drill locations and improve pre-drill reserve estimates. Seismic inversion allows estimating elastic parameters directly without having to interpret phase reversals or other complicated AVO response characteristics. Poisson ratio is the best discriminator for fluid content in the study area based on well log evaluation and fluid substitution modeling An angle stack based inversion was done to see if a Poisson ratio volume could assist in evaluating and finding drill locations. Numerous low Poisson ratio anomalies were identified, but most tied into wet sands in existing wells. It was determined that this method was not reliable enough. A full waveform prestack inversion was then completed and this method seems to be more stable and reliable when tied into existing well control. Introduction Oil and gas production in the study area is from Upper Miocene age sediments in both normal pressured and geopressured environments. AVO class II and III is the dominant hydrocarbon signature. Reservoirs depths range from 2000-20,000 feet. The 3D survey was acquired in 1995 with far offsets to 19980 feet with an average of 30 fold. The data set is a Kirchoff prestack time migration done in 2006. A continuous velocity analysis every CMP was used to generate a 3D velocity volume. The key well has a full log suite from 3500-14550 feet that includes compressional velocity, shear velocity (dipole sonic), and density. This well was used in both inversions to determine the wavelet and the well to seismic amplitude scaling. A synthetic seismogram at the key well location was used to verify the well tie and a wavelet was extracted at the key well location. Angle Stack Inversion The inversion inputs: • 6 angle stacks – 2-9, 9-16, 16-23, 23-30, 30-37, and 37-44 degrees • Compressional velocity (Vp) background model generated by smoothing the continuous seismic velocity analysis volume. • Shear velocity (Vs) background computed by Vs=0.778*Vp-3120 (m/sec) • Density background model provided by third party using continuous velocity analysis and well control. • Wavelet estimation for each angle stack Inversion workflow: 1. CMP gather conditioning (TVF+ trim statics + AGC) 2. Log calibration and wavelet estimation 3. Simultaneous AVO relative inversion 4. Generate low frequency model 5. Simultaneous absolute AVO inversion Inversion outputs: • Acoustic Impedance, Poisson ratio, and Density volumes Flattening the seismic gathers was a serious issue. Prestack Waveform Inversion The inversion inputs: • Denoised prestack time migrated gathers with NMO removed • Compressional velocity (Vp) background model used the continuous seismic velocity analysis volume. • Shear background model computed from Vs= 0.8*Vp- 1.0 (km/sec) • Density background model (Rho) computed by Rho=2.1+(0.368*(Vp-2.88) (g/cc) Outputs from the inversion: • Vp, Vs, and Density volumes
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling > Seismic Inversion (1.00)
SUMMARY We present a migration method in the temporal frequency domain that can propagate both downgoing and upgoing waves. The method can handle arbitrary velocity model, and we demonstrate its ability to image overturned events and steep reflectors. Our algorithm has the advantage of migrating the data sequentially in depth and frequency, leading to significant advantages compared to Reverse Time Migration when combined with migration velocity analysis. We also show that the method can easily generate offset and angle gathers. INTRODUCTION We present an enhancement to the depth extrapolation algorithm introduced in Sandberg and Beylkin (2009). The method in Sandberg and Beylkin (2009) uses spectral projector as a way to suppress the evanescent waves without modifying the propagating waves. By using spectral projectors, the depth extrapolation scheme propagates both up and downgoing waves, which is necessary to properly image overturned events. Furthermore, no approximations in the mathematical formulation are necessary for laterally varying media. We note that traditional downward extrapolation algorithms rely on operator splitting to overcome the instability introduced by evanescent waves. Such methods carry two penalties: first, in addition to the evanescent waves, they also suppress the upgoing propagating waves and, second, the mathematical formulation of operator splitting is only exact in a media without lateral variations, thus introducing additional errors if lateral variations are present. In the algorithm described in Sandberg and Beylkin (2009), we use only the incident wave field as a source, thus ignoring scattered waves acting as secondary sources. In this paper, we modify the algorithm in Sandberg and Beylkin (2009) in order to take a proper account of such secondary reflections recorded at the surface. These modifications further improve imaging of steep and overturned events. Assuming that we can separate the incident and the scattered fields at the surface, the resulting algorithm is a downward continuation method that handles arbitrary medium complexity, propagates both upgoing and downgoing waves, and images steep reflectors and overturned events. We demonstrate the algorithm by migrating data generated for a challenging model and also compute angle gathers that are easily generated using our modified approach. We note that the imaging condition in Reverse Time Migration (RTM) does use the secondary reflections recorded at the surface. With the modifications described here, our method and RTM now use the same information available at the surface surface and, as a result, the two methods may now be carefully compared as we plan to do in the near future. Finally, we note that downward extrapolation algorithms that rely on operator splitting do not treat secondary reflections correctly (due to the suppression of upgoing propagating waves), thus making it difficult, if not impossible, to use such data for imaging FULL-WAVE-EQUATION DEPTH EXTRAPOLATION FOR MIGRATION The introduction of the spectral projector P is the key element of our approach in Sandberg and Beylkin (2009) since without this operator the problem is notoriously unstable due to the presence of positive eigenvalues of L associated with the evanescent waves.