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Geology in reservoir models

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Reservoir models are constructed by distributing petrophysical properties in 3D space with geologic models as a template. Geologic models are constructed by distributing facies within a sequence stratigraphic framework using the systematic distribution of facies within a depositional model as a guide.

Developing the model

There are many types of facies, and facies selection is normally based on the question to be answered. Water depth and changes in sea level are key questions when building a sequence stratigraphic model, and fossil and other grain types together with depositional textures are keys to estimating water depth. Thus, numerous "depositional" facies are commonly described from core material. Once a sequence model is built, however, the problem is to convert the geologic model into a reservoir model by populating the geologic model with petrophysical data. This problem is best resolved by linking petrophysical measurements to rock fabric or texture, and the number of "rock-fabric" facies needed to quantify the geologic model is generally much lower than depositional facies.

Examples of carbonate rock-fabric facies include:

  • Grain-dominated packstone
  • Medium crystalline dolowackestone
  • Moldic grainstone.

In carbonate reservoirs, rock fabrics include diagenetic overprints as well as depositional textures because diagenesis plays an important role in forming most carbonate pore space. An example of how rock-fabric facies relate to porosity and permeability is illustrated in Fig. 1.[1] The following are used to characterize pore-size distribution:

  • Particle size
  • Sorting
  • Interparticle porosity
  • Vuggy porosity

Petrophysical quantification of a carbonate stratigraphic model is accomplished by mapping rock-fabric facies and interparticle porosity and calculating permeability and initial water saturation from rock-fabric-specific relationships to porosity. An example of a rock-fabric reservoir model is illustrated in Fig. 2.

Petrophysical properties of siliciclastic rocks are often directly related to facies characterized by grain size and sorting because pore space is generally located between grains and the variability of porosity within a facies is small. Porosity generally decreases with decreasing sorting and remains constant with changes in average grain size (see Fig. 2). However, porosity will vary with cementation and compaction. Permeability decreases with decreasing sorting and grain size (Fig. 3), and as porosity decreases even though grain size and sorting remain constant. The finest grain size is found in shales (mudstones) that typically have little permeability. Once the depositional facies are distributed in 3D space, the model can be quantified with petrophysical properties by using grain size, sorting, and porosity characteristics of the depositional facies. As illustrated in Fig. 4[2] (a geologic model from a deepwater sediment fan), depositional facies commonly have similar petrophysical properties that reduce the number of textural facies needed to quantify the geologic model. The distribution of shales (mudstone) is important for reservoir modeling because they typically have little permeability and act as flow barriers in the reservoir.

Fracture porosity can have a large influence on performance of a carbonate or siliciclastic reservoir. Characterizing and modeling fracture porosity is difficult and is beyond the scope of this discussion. The book on fractured reservoirs by Aguilera is suggested as a good general overview of the problem.


  1. 1.0 1.1 Lucia, F.J. 1999. Carbonate Reservoir Characterization, 226. New York: Springer.
  2. 2.0 2.1 Dutton, S.P. et al. 1999. Geologic and Engineering Characterization of Turbidite Reservoirs, Ford Geraldine Unit, Bell Canyon Formation, West Texas, The U. of Texas at Austin, Bureau of Economic Geology Report of Investigations No. 255, 88.

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See also

Reservoir geology

Carbonate reservoir geology

Siliciclastic reservoir geology

Geostatistical reservoir modeling