scholarly journals Seismic imaging of reservoir flow properties: Time‐lapse amplitude changes

Geophysics ◽  
2004 ◽  
Vol 69 (6) ◽  
pp. 1425-1442 ◽  
Author(s):  
Don W. Vasco ◽  
Akhil Datta‐Gupta ◽  
Ron Behrens ◽  
Pat Condon ◽  
James Rickett
Keyword(s):  
Seismic Data ◽  
Large Scale ◽  
Seismic Imaging ◽  
Asymptotic Methods ◽  
Time Lapse ◽  
Flow Properties ◽  
Reservoir Permeability ◽  
Amplitude Data ◽  
Reservoir Flow ◽  
Iterative Inversion

Asymptotic methods provide an efficient means by which to infer reservoir flow properties, such as permeability, from time‐lapse seismic data. A trajectory‐based methodology, similar to ray‐based methods for medical and seismic imaging, is the basis for an iterative inversion of time‐lapse amplitude changes. In this approach, a single reservoir simulation is required for each iteration of the algorithm. A comparison between purely numerical and the trajectory‐based sensitivities demonstrates their accuracy. Analysis of a set of synthetic amplitude changes indicates that we are able to recover large‐scale reservoir permeability variations from time‐lapse amplitude data. In an application to actual time‐lapse amplitude changes from the Bay Marchand field in the Gulf of Mexico, we are able to reduce the misfit by 81% in 12 iterations. The time‐lapse observations indicate lower permeabilities are required in the central portion of thereservoir.

scholarly journals Seismic imaging of reservoir flow properties: Resolving water influx and reservoir permeability

Geophysics ◽  
2008 ◽  
Vol 73 (1) ◽  
pp. O1-O13 ◽  
Author(s):  
D. W. Vasco ◽  
Henk Keers ◽  
Jalal Khazanehdari ◽  
Anthony Cooke
Keyword(s):  
Effective Means ◽  
Time Lapse ◽  
Multiple Time ◽  
Upward Movement ◽  
Model Assessment ◽  
Flow Properties ◽  
Model Parameter ◽  
Water Influx ◽  
Reservoir Permeability ◽  
Reservoir Flow

Methods for geophysical-model assessment — in particular, the computation of model-parameter resolution — indicate the value and the limitations of time-lapse data in estimating reservoir flow properties. A trajectory-based method for computing sensitivities provides an effective means to compute model-parameter resolution. We examine the common situation in which water encroaches into a reservoir from below, as caused by the upward movement of an oil-water contact. Though the techniques described are not limited to this case, we treat the situation in which the time-lapse response is primarily caused by changes in saturation. Using straightforward techniques, we find that, by including reflections off the top and bottom of a reservoir tens of meters thick, we can infer reservoir permeability based upon time-lapse data. We find that, for the case of water influx from below, using multiple time-lapse snapshots does not necessarily improve the resolution of reservoir permeability. An application to time-lapse data from the Norne field in the North Sea illustrates that we can resolve the permeability near a producing well using reflections from three interfaces associated with the reservoir.

scholarly journals Seismic imaging of reservoir flow properties: Time‐lapse pressure changes

Geophysics ◽  
2004 ◽  
Vol 69 (2) ◽  
pp. 511-521 ◽  
Author(s):  
Don W. Vasco
Keyword(s):  
Sparse Matrix ◽  
Fluid Pressure ◽  
Linear Partial Differential Equation ◽  
Time Lapse ◽  
Flow Properties ◽  
Linear Inverse Problem ◽  
Reservoir Permeability ◽  
Reservoir Flow ◽  
Sparse Matrix Techniques ◽  
Pressure Changes

Time‐lapse fluid pressure and saturation estimates are sensitive to reservoir flow properties such as permeability. In fact, given time‐lapse estimates of pressure and saturation changes, one may define a linear partial differential equation for permeability variations within the reservoir. The resulting linear inverse problem can be solved quite efficiently using sparse matrix techniques. An application to a set of crosswell saturation and pressure estimates from a CO2 flood at the Lost Hills field in California demonstrates the utility of this approach. The pressure and saturation estimates are mapped into reservoir permeability variations between the boreholes. The resulting permeability estimates agree with a permeability log in an adjacent well and are in accordance with water and CO2 saturation changes imaged in the interwell region.

On the use of quasi-static deformation to understand reservoir fluid flow

Geophysics ◽  
2005 ◽  
Vol 70 (4) ◽  
pp. O13-O27 ◽  
Author(s):  
Don W. Vasco ◽  
Alessandro Ferretti
Keyword(s):  
Fluid Flow ◽  
Surface Deformation ◽  
Equations Of Motion ◽  
Time Lapse ◽  
Oil Field ◽  
Static Deformation ◽  
Flow Properties ◽  
Reservoir Volume ◽  
Reservoir Permeability ◽  
Surface Displacements

Deformation above a producing reservoir provides a valuable source of information concerning fluid flow and flow properties. Quasi-static deformation occurs when the displacements are so slow that we may neglect inertial terms in the equations of motion. We present a method for inferring reservoir volume change and flow properties, such as permeability, from observations of quasi-static deformation. Such displacements may represent surface deformation such as tilt, leveling, interferometric synthetic aperture radar (InSAR), or bathymetry observations or subsurface deformation, as inferred from time-lapse seismic surveys. In our approach, the equation for fluid flow in a deforming reservoir provides a mapping from estimated fractional volume changes to reservoir permeability variations. If the reservoir behaves poroelastically over the interval of interest, all the steps in this approach are linear. Thus, the inference of reservoir permeability from deformation data becomes a linear inverse problem. In an application to the Wilmington oil field in California, we find that observed surface displacements, obtained by leveling and InSAR, are indeed compatible with measured reservoir volume fluxes. We find that the permeability variations in certain layers coincide with fault-block boundaries suggesting that, in some cases, faults are controlling fluid flow at depth.

The Western Australia Modeling project — Part 2: Seismic validation

2019 ◽  
Vol 7 (4) ◽  
pp. T793-T807 ◽  
Author(s):  
Jeffrey Shragge ◽  
David Lumley ◽  
Julien Bourget ◽  
Toby Potter ◽  
Taka Miyoshi ◽  
...  
Keyword(s):  
Western Australia ◽  
Seismic Data ◽  
Large Scale ◽  
Seismic Imaging ◽  
Surface Model ◽  
Near Surface ◽  
North West ◽  
Additional Information ◽  
Imaging Results ◽  
Scenario Testing

Large-scale 3D modeling of realistic earth models is being increasingly undertaken in industry and academia. These models have proven useful for various activities such as geologic scenario testing through seismic finite-difference (FD) modeling, investigating new acquisition geometries, and validating novel seismic imaging, inversion, and interpretation methods. We have evaluated the results of the Western Australia (WA) Modeling (WAMo) project, involving the development of a large-scale 3D geomodel representative of geology of the Carnarvon Basin, located offshore of WA’s North West Shelf (NWS). Constrained by a variety of geologic, petrophysical, and field seismic data sets, the viscoelastic WAMo 3D geomodel was used in seismic FD modeling and imaging tests to “validate” model realizations. Calibrating the near-surface model proved to be challenging due to the limited amount of well data available for the top 500 m below the mudline. We addressed this issue by incorporating additional information (e.g., geotechnical data, analog studies) as well as by using soft constraints to match the overall character of nearby NWS seismic data with the modeled shot gathers. This process required undertaking several “linear” iterations to apply near-surface model conditioning, as well as “nonlinear” iterations to update the underlying petrophysical relationships. Overall, the resulting final WAMo 3D geomodel and accompanying modeled shot gathers and imaging results are able to reproduce the complex full-wavefield character of NWS marine seismic data. Thus, the WAMo model is well-calibrated for use in geologic and geophysical scenario testing to address common NWS seismic imaging, inversion, and interpretation challenges.

scholarly journals Near-surface real-time seismic imaging using parsimonious interferometry

2021 ◽  
Vol 11 (1) ◽  
Author(s):  
Sherif M. Hanafy ◽  
Hussein Hoteit ◽  
Jing Li ◽  
Gerard T. Schuster
Keyword(s):  
Fluid Flow ◽  
Real Time ◽  
Temporal Resolution ◽  
Seismic Imaging ◽  
Time Lapse ◽  
Rock Properties ◽  
Recording Time ◽  
Near Surface ◽  
Arrival Times ◽  
Order Of Magnitude

AbstractResults are presented for real-time seismic imaging of subsurface fluid flow by parsimonious refraction and surface-wave interferometry. Each subsurface velocity image inverted from time-lapse seismic data only requires several minutes of recording time, which is less than the time-scale of the fluid-induced changes in the rock properties. In this sense this is real-time imaging. The images are P-velocity tomograms inverted from the first-arrival times and the S-velocity tomograms inverted from dispersion curves. Compared to conventional seismic imaging, parsimonious interferometry reduces the recording time and increases the temporal resolution of time-lapse seismic images by more than an order-of-magnitude. In our seismic experiment, we recorded 90 sparse data sets over 4.5 h while injecting 12-tons of water into a sand dune. Results show that the percolation of water is mostly along layered boundaries down to a depth of a few meters, which is consistent with our 3D computational fluid flow simulations and laboratory experiments. The significance of parsimonious interferometry is that it provides more than an order-of-magnitude increase of temporal resolution in time-lapse seismic imaging. We believe that real-time seismic imaging will have important applications for non-destructive characterization in environmental, biomedical, and subsurface imaging.

Line length balancing to evaluate multi-phase submarine landslide development: an example from the Storegga Slide, Norway

2019 ◽  
Vol 500 (1) ◽  
pp. 531-549 ◽  
Author(s):  
Suzanne Bull ◽  
Joseph A. Cartwright
Keyword(s):  
Seismic Data ◽  
Large Scale ◽  
Line Length ◽  
Proximal Region ◽  
Submarine Landslide ◽  
Landslide Development ◽  
Multi Phase ◽  
Storegga Slide ◽  
2D And 3D ◽  
3D Seismic Data

AbstractThis study shows how simple structural restoration of a discrete submarine landslide lobe can be applied to large-scale, multi-phase examples to identify different phases of slide-lobe development and evaluate their mode of emplacement. We present the most detailed analysis performed to date on a zone of intense contractional deformation, historically referred to as the compression zone, from the giant, multi-phase Storegga Slide, offshore Norway. 2D and 3D seismic data and bathymetry data show that the zone of large-scale (>650 m thick) contractional deformation can be genetically linked updip with a zone of intense depletion across a distance of 135 km. Quantification of depletion and accumulation along a representative dip-section reveals that significant depletion in the proximal region is not accommodated in the relatively mild amount (c. 5%) of downdip shortening. Dip-section restoration indicates a later, separate stage of deformation may have involved removal of a significant volume of material as part of the final stages of the Storegga Slide, as opposed to the minor volumes reported in previous studies.

Elastic inverse scattering for fluid variation with time-lapse seismic data

Geophysics ◽  
2015 ◽  
Vol 80 (2) ◽  
pp. WA61-WA67 ◽  
Author(s):  
Zhaoyun Zong ◽  
Xingyao Yin ◽  
Guochen Wu ◽  
Zhiping Wu
Keyword(s):  
Shear Modulus ◽  
Inverse Scattering ◽  
Seismic Data ◽  
Scattering Theory ◽  
Time Lapse ◽  
Monitoring Data ◽  
Prestack Inversion ◽  
Fluid Factor ◽  
Reference Medium ◽  
The Difference

Elastic inverse-scattering theory has been extended for fluid discrimination using the time-lapse seismic data. The fluid factor, shear modulus, and density are used to parameterize the reference medium and the monitoring medium, and the fluid factor works as the hydrocarbon indicator. The baseline medium is, in the conception of elastic scattering theory, the reference medium, and the monitoring medium is corresponding to the perturbed medium. The difference in the earth properties between the monitoring medium and the baseline medium is taken as the variation in the properties between the reference medium and perturbed medium. The baseline and monitoring data correspond to the background wavefields and measured full fields, respectively. And the variation between the baseline data and monitoring data is taken as the scattered wavefields. Under the above hypothesis, we derived a linearized and qualitative approximation of the reflectivity variation in terms of the changes of fluid factor, shear modulus, and density with the perturbation theory. Incorporating the effect of the wavelet into the reflectivity approximation as the forward solver, we determined a practical prestack inversion approach in a Bayesian scheme to estimate the fluid factor, shear modulus, and density changes directly with the time-lapse seismic data. We evaluated the examples revealing that the proposed approach rendered the estimation of the fluid factor, shear modulus, and density changes stably, even with moderate noise.

scholarly journals Pitfalls and limitations in seismic attribute interpretation of tectonic features

2015 ◽  
Vol 3 (1) ◽  
pp. SB5-SB15 ◽  
Author(s):  
Kurt J. Marfurt ◽  
Tiago M. Alves
Keyword(s):  
Seismic Data ◽  
Seismic Attributes ◽  
Seismic Attribute ◽  
3D Data ◽  
Amplitude Data ◽  
Seismic Sections ◽  
Push Down ◽  
Data Coherence ◽  
Level Of Experience ◽  
Tectonic Features

Seismic attributes are routinely used to accelerate and quantify the interpretation of tectonic features in 3D seismic data. Coherence (or variance) cubes delineate the edges of megablocks and faulted strata, curvature delineates folds and flexures, while spectral components delineate lateral changes in thickness and lithology. Seismic attributes are at their best in extracting subtle and easy to overlook features on high-quality seismic data. However, seismic attributes can also exacerbate otherwise subtle effects such as acquisition footprint and velocity pull-up/push-down, as well as small processing and velocity errors in seismic imaging. As a result, the chance that an interpreter will suffer a pitfall is inversely proportional to his or her experience. Interpreters with a history of making conventional maps from vertical seismic sections will have previously encountered problems associated with acquisition, processing, and imaging. Because they know that attributes are a direct measure of the seismic amplitude data, they are not surprised that such attributes “accurately” represent these familiar errors. Less experienced interpreters may encounter these errors for the first time. Regardless of their level of experience, all interpreters are faced with increasingly larger seismic data volumes in which seismic attributes become valuable tools that aid in mapping and communicating geologic features of interest to their colleagues. In terms of attributes, structural pitfalls fall into two general categories: false structures due to seismic noise and processing errors including velocity pull-up/push-down due to lateral variations in the overburden and errors made in attribute computation by not accounting for structural dip. We evaluate these errors using 3D data volumes and find areas where present-day attributes do not provide the images we want.

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