Summary
A 3D pore-network model of two-phase flow was developed to compute
permeability, relative permeability, and capillary pressure curves from
pore-type, -size, and -shape information measured by means of high-resolution
image analysis of diatomaceous-reservoir-rock samples. The diatomite model is
constructed using pore-type proportions obtained from image analysis of
epoxy-impregnated polished samples and mercury-injection capillary pressure
curves for diatomite cores. Multiple pore types are measured, and each pore
type has a unique pore-size and throat-size distribution that is incorporated
in the model. Network results present acceptable agreement when compared to
experimental measurements of relative permeability. The pore-network model is
applicable to both drainage and imbibition within diatomaceous reservoir rock.
Correlation of network-model results to well log data is discussed, thereby
interpolating limited experimental results across the entire reservoir column.
Importantly, our method has potential to predict the petrophysical properties
for reservoir rocks with either limited core material or those for which
conventional experimental measurements are difficult, unsuitable, or
expensive.
Introduction
Model generation for reservoir simulation requires accurate entering of
physical properties such as porosity, permeability, initial water saturation,
residual-oil saturation, capillary pressure functions, and relative
permeability curves. These functions and parameters are necessary to estimate
production rate and ultimate oil recovery, and thereby optimize reservoir
development. Accurate measurement and representation of such information is,
therefore, essential for reservoir modeling.
Relative permeability and capillary pressure curves are the most important
constitutive relations to represent multiphase flow. Often, it is difficult to
sample experimentally the range of relevant multiphase-flow behavior of a
reservoir. In addition to the availability of rock samples, measurements are
frequently time consuming to conduct, and conventional techniques are not
suitable for all rock types (Schembre and Kovscek 2003). It is impossible,
therefore, to measure all the unique relative permeability functions of
different reservoir-rock types and variations within a rock type. This lack of
constitutive information limits the accuracy of reservoir simulators to predict
oil recovery. Simply put, other available data must be queried for their
relevance to multiphase flow and must be used to interpret the available
relative permeability and capillary pressure information.
© 2007. Society of Petroleum Engineers
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History
- Original manuscript received:
18 January 2005
- Meeting paper published:
30 March 2005
- Revised manuscript received:
26 March 2007
- Manuscript approved:
8 April 2007
- Version of record:
20 December 2007
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