Summary
A new well-testing-analysis method is presented. The method allows for
calculating the absolute permeability of the formation in the area influenced
by the test and the average saturations in this area. Traditional
pressure-transient-analysis methods have been developed and are completely
adequate for single-phase flow in the reservoir. The proposed method is not
intended for these conditions. The method applies to two-phase flow in the
reservoir (oil and water or oil and gas). Future expansion to three-phase flow
is possible. Current analysis methods yield only the effective permeability for
the dominant flowing phase and the "total mobility" of all phases. The new
method uses the surface-flow rates and fluid properties of the flowing phases
and the same relative permeability relations used in characterizing the
reservoir and predicting its future performance. The method has been verified
by comparing the results from analyzing several synthetic tests that were
produced by a numerical simulator with the input values. Use of the method with
field data is also described.
The new method could be applied wherever values of absolute permeability or
fluid saturations are used in predicting well and reservoir performance.
Probably, the major impact would be in reservoir simulation studies in which
the need to transform well-testing permeability to simulator input values is
eliminated and an additional parameter (fluid saturations) becomes available to
help history match the reservoir performance. This work will also help in
predicting well-flow rates and in situations in which absolute permeability
changes with time (e.g., from compaction).
Results showed that the values of absolute permeability in water/oil cases
could be reproduced within 3% of the correct values and within 5% of the
correct values in gas/oil cases. Errors in calculating the fluid saturations
were even lower. One of the main advantages of this method is that the relative
permeability curves used in calculating the absolute permeability and average
saturations, and later on in using these results in numerical reservoir
simulation studies, are the same, ensuring consistent process. The proposed
method does not address the question of which set of relative permeability
curves should be used. This question should be answered by the engineer
performing the reservoir engineering/simulation study. The proposed method
mainly is meant to provide consistent results for predicting the reservoir
performance using whatever relative permeability relations are being used in
the reservoir simulation model. The method does not induce any additional
errors in determining the average saturation or absolute permeability over what
may result from using these specific relative permeability curves in the
reservoir simulation study.
The impact of this study will be to expand the use of information already
contained in transient data and surface flow rates of all phases. The results
will provide engineers with additional parameters to improve and speed up the
prediction of well and reservoir performances in just about all studies.
© 2010. Society of Petroleum Engineers
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History
- Original manuscript received:
5 February 2008
- Meeting paper published:
30 March 2008
- Revised manuscript received:
25 September 2009
- Manuscript approved:
2 October 2009
- Published online:
19 April 2010
- Version of record:
20 April 2010
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