Journal of Canadian Petroleum Technology
Volume 49,
Number 9,
September 2010,
pp. 69-76
Summary
A model is developed for petrophysical evaluation of naturally fractured
reservoirs where dip of fractures ranges between zero and 90°, and where
fracture tortuosity is greater than 1.0. This results in an intrinsic porosity
exponent of fractures (mf) that is larger than 1.0.
The finding has direct application in the evaluation of fractured reservoirs
and tight gas sands, where fracture dip can be determined, for example, from
image logs. In the past, a fracture-matrix system has been represented by a
dual-porosity model which can be simulated as a series-resistance network or
with the use of effective medium theory. For many cases both approaches provide
similar results.
The model developed in this study leads to the observation that including
fracture dip and tortuosity in the petrophysical analysis can generate
significant changes in the dual-porosity exponent (m) of the composite
system of matrix and fractures. It is concluded that not taking fracture dip
and tortuosity into consideration can lead to significant errors in the
calculation of water saturation. The use of the model is illustrated with
examples.
© 2010. Society of Petroleum Engineers
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History
- Original manuscript received:
28 March 2008
- Meeting paper published:
18 June 2008
- Revised manuscript received:
5 April 2010
- Manuscript approved:
9 June 2010
- Published online:
1 September 2010
- Version of record:
1 September 2010
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