Summary
Many naturally fractured reservoirs are composed of matrix, fractures, and
nontouching vugs (there can also be any other type of nonconnected porosity
that can occur; for example, in intragranular, moldic, and/or fenestral
porosity). An improved triple-porosity model is presented that takes these
different types of porosities into account. The model can be used continuously
throughout a reservoir with segments composed of solely matrix porosity, solely
matrix/fractures, solely fractures/vugs, or the complete triple-porosity
system.
The model improves a previous triple-porosity algorithm by handling
rigorously the scale associated with each: matrix, fractures, and vugs. This
permits determining more-realistic values of the cementation or porosity
exponent, m, for the composite system and consequently improved values
of water saturation and reserves evaluations. The values of m for the
triple-porosity reservoir can be smaller than, equal to, or larger than the
porosity exponent of only the matrix blocks, mb, depending on
the relative contribution of the vugs and fractures to the total porosity
system.
It is concluded that not taking into account the contribution of matrix,
fractures, and vugs in the petrophysical evaluation of triple-porosity systems
can lead to significant errors in the determination of m, and
consequently in the calculation of water saturation, hydrocarbons in place, and
recoveries, and ultimately can lead to poor economic evaluations--either too
pessimistic or too optimistic. This is illustrated with two examples from
Middle East carbonates.
© 2011. Society of Petroleum Engineers
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History
- Original manuscript received:
12 April 2010
- Meeting paper published:
28 June 2010
- Revised manuscript received:
14 December 2010
- Manuscript approved:
21 January 2011
- Published online:
12 August 2011
- Version of record:
15 August 2011
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