--> --> Progress and Potential in Building and Populating 3D Static Models of Carbonate Reservoirs, by Charles Kerans; #90029 (2004)

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Progress and Potential in Building and Populating 3D Static Models of Carbonate Reservoirs

Charles Kerans
Bureau of Economic Geology
Jackson School of Geosciences
The University of Texas at Austin

 

The last 20 years have seen important advances in carbonate reservoir characterization, particularly in the areas of stratigraphy, petrophysics, geostatistics, seismic imaging, and 3D modeling and visualization technology. During the past two decades these areas have evolved from conceptualization, through research testing, and finally to accepted technology. The result has been construction of substantially more realistic (i.e. greater similarity to rigorously tested outcrop models) reservoir models that have aided recovery efforts. Seismic imaging of petrophysical properties, characterization of fracture and touching vug pore systems for guiding of permeability multipliers in dual porosity-dual permeability simulators, and techniques for distributing wettability and relative permeability throughout the 3D model are areas that remain in the twilight zone between research and application and represent key areas of future research.

Geologists building stratigraphic frameworks for carbonate reservoirs can now use an understanding of Milankovitch-based high-frequency eustatic setting to predict unit continuity, facies composition, and diagenetic overprint even before a study begins. Examples of greenhouse, transitional, and icehouse reservoir models will illustrate how the range of high-frequency eustatic signals in these different settings has controlled reservoir continuity, relative conformity versus onlap and truncation, and karst development. This remains an underutilized entry-level approach to characterization. The methodology of mapping high-frequency stratigraphic cycles as the starting point for defining petrophysical flow units is another important breakthrough, and the result is that a careful chronostratigraphic characterization can minimize the degree to which non-geologic scaleup occurs in constructing models. These steps go a long ways in permitting construction of geologic models that conform faithfully to known stratigraphic patterns as demonstrated in outcrop-analog studies.

The equivalency or lack there of, between geologic facies and petrophysical “facies” (a.k.a. rock types or rock fabrics) is a major challenge for quantification of geologic models. New approaches are allowing a more seamless link between geologic facies with their spatial connotations with rock fabrics and their link to Phi/K/So. This is best done initially through core calibration and then directly from logs. The creation of rock-fabric-specific permeability transforms reduces the smoothing of high and low permeability values that dominate fluid-flow response.

Seismic imaging and inversion show great promise for guiding spatial trends for distribution of properties even at the fine-scale resolution required for reservoir characterization and simulation. Success of the inversion depends on iterative inversion and geologic interpretation. A well-constrained inversion with 3-5 control horizons can approach the level required for flow unit mapping, or at least for use in guiding of property modeling in the interwell area. Fracture interpretation and modeling remains a difficult task mainly because there is no clear link between size and distribution of fractures and resultant permeability at both local and grid-block scales.

The next two decades demand that geologists, geophysisists, and engineers combine efforts to map and model complex pore systems such as fracture/touching vug systems. Evolution of 3D stratigraphic forward modeling techniques holds promise for creating realistic facies distributions for more geologically intelligent 3D-model population. Diagenetic forward models will combine with existing wireline-log based techniques for predicting pore size and shape distribution in the 3D model. Seismic imaging of ever higher resolution, within a well-constrained geologic framework, should soon allow detailed images of porosity distribution between wells that can be used as a geostatistical conditioning parameter or directly to populate cells in the model.