A Practical Capillary Pressure Correlation Technique (includes associated papers 29241 and 29330 )
- Jeffrey L. Pletcher (Marathon Oil Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- July 1994
- Document Type
- Journal Paper
- 556 - 556
- 1994. Society of Petroleum Engineers
- 2 in the last 30 days
- 65 since 2007
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This article describes correlating laboratory-derived capillary pressure data to different porosity and permeability values.
A problem arises when porosity and permeability of laboratory core samples are not representative of average reservoir properties. Such is the case with the data in Fig. 1a, which shows laboratory- derived (centrifuge) oil/water capillary pressure drainage curves on six core plug samples from a carbonate formation In the Rocky Mountains. None of the core samples has porosity and permeability values close to the reservoir averages of 22.0% and 26.7 md, respectively. Sample C's permeability is close to the average, but its porosity is too high. Sample D's porosity is nearly identical to the average, but its permeability is too high.
The most common method in the literature to correlate capillary pressure data to a different porosity and permeability is the Leverett J function. However, the J function often does not give a good correlation, as was the case here. Amyx et al.’s method seems to have been overlooked as a correlation technique. This method honors both porosity and permeability, unlike some methods that correlate capillary pressure as a function of permeability only. The remainder of this article illustrates how it was used on the subject data set with success. The technique is as follows.
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