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.

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 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.

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.

scholarly journals Estimating reservoir permeability with borehole radar

Geophysics ◽  
2020 ◽  
Vol 85 (4) ◽  
pp. H51-H60
Author(s):  
Feng Zhou ◽  
Iraklis Giannakis ◽  
Antonios Giannopoulos ◽  
Klaus Holliger ◽  
Evert Slob
Keyword(s):  
Water Saturation ◽  
Time Lapse ◽  
Drilling Mud ◽  
Invasion Depth ◽  
Initial Water ◽  
Oil Drilling ◽  
Reservoir Evaluation ◽  
Reservoir Permeability ◽  
Borehole Radar ◽  
Porosity And Permeability

In oil drilling, mud filtrate penetrates into porous formations and alters the compositions and properties of the pore fluids. This disturbs the logging signals and brings errors to reservoir evaluation. Drilling and logging engineers therefore deem mud invasion as undesired and attempt to eliminate its adverse effects. However, the mud-contaminated formation carries valuable information, notably with regard to its hydraulic properties. Typically, the invasion depth critically depends on the formation porosity and permeability. Therefore, if adequately characterized, mud invasion effects could be used for reservoir evaluation. To pursue this objective, we have applied borehole radar to measure mud invasion depth considering its high radial spatial resolution compared with conventional logging tools, which then allows us to estimate the reservoir permeability based on the acquired invasion depth. We investigate the feasibility of this strategy numerically through coupled electromagnetic and fluid modeling in an oil-bearing layer drilled using freshwater-based mud. Time-lapse logging is simulated to extract the signals reflected from the invasion front, and a dual-offset downhole antenna mode enables time-to-depth conversion to determine the invasion depth. Based on drilling, coring, and logging data, a quantitative interpretation chart is established, mapping the porosity, permeability, and initial water saturation into the invasion depth. The estimated permeability is in a good agreement with the actual formation permeability. Our results therefore suggest that borehole radar has significant potential to estimate permeability through mud invasion effects.

The role of geomechanical modeling in the measurement and understanding of geophysical data collected during carbon sequestration

2021 ◽  
Vol 40 (6) ◽  
pp. 413-417
Author(s):  
Chunfang Meng ◽  
Michael Fehler
Keyword(s):  
Pore Pressure ◽  
Fault Location ◽  
Mechanical Response ◽  
Fluid Pressure ◽  
Geophysical Data ◽  
Fluid Injection ◽  
Coupled Flow ◽  
Cap Rock ◽  
Stress And Deformation ◽  
Pressure Changes

As fluids are injected into a reservoir, the pore fluid pressure changes in space and time. These changes induce a mechanical response to the reservoir fractures, which in turn induces changes in stress and deformation to the surrounding rock. The changes in stress and associated deformation comprise the geomechanical response of the reservoir to the injection. This response can result in slip along faults and potentially the loss of fluid containment within a reservoir as a result of cap-rock failure. It is important to recognize that the slip along faults does not occur only due to the changes in pore pressure at the fault location; it can also be a response to poroelastic changes in stress located away from the region where pore pressure itself changes. Our goal here is to briefly describe some of the concepts of geomechanics and the coupled flow-geomechanical response of the reservoir to fluid injection. We will illustrate some of the concepts with modeling examples that help build our intuition for understanding and predicting possible responses of reservoirs to injection. It is essential to understand and apply these concepts to properly use geomechanical modeling to design geophysical acquisition geometries and to properly interpret the geophysical data acquired during fluid injection.

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