Co-estimation of saturation functions (k r and P c) from unsteady-state core-flood experiment in tight carbonate rocks
Abstract The production from oil and gas reservoirs is greatly affected by rock and fluid properties of the porous rock. Capillary pressure (P c) and relative permeability (k r) are two important properties employed in the mathematical simulation reservoirs for predicting oil recovery from undergrou...
| Main Authors: | , |
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| Format: | Article |
| Language: | English |
| Published: |
SpringerOpen
2018-03-01
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| Series: | Journal of Petroleum Exploration and Production Technology |
| Subjects: | |
| Online Access: | http://link.springer.com/article/10.1007/s13202-018-0452-5 |
| Summary: | Abstract The production from oil and gas reservoirs is greatly affected by rock and fluid properties of the porous rock. Capillary pressure (P c) and relative permeability (k r) are two important properties employed in the mathematical simulation reservoirs for predicting oil recovery from underground hydrocarbon resources. In this study, various core-flood experiments were performed using different tight carbonate rock samples for oil–water and oil–gas systems. The objective of this research is to investigate the multi-phase flow functions (k r and P c) in tight formations. The k r curves of each sample were obtained by two different mathematical methods: the history-matching (ant colony optimization) technique and analytical method (JBN). The comparison between the relative permeability of the history-matching technique with that of the JBN method revealed a significant discrepancy between them. The modeling of an experiment using k r of JBN revealed a significant difference between experimental and simulation oil production, whereas the relative permeability of history matching accurately reproduced the experimental oil recovery. This observation highlights the inadequacy of the JBN technique for determination of relative permeability in particular in the tight rock where capillary forces are important. In addition to the relative permeability, the capillary pressure values as a function of saturation were estimated from core-flood tests using a history-matching technique. The comparison between oil–water capillary pressures obtained from centrifuge tests with those of core-flood experiments depicted good agreement, whereas the capillary pressure of oil–gas system measured from core-flood tests was considerably different from centrifuge experiment results. This outcome demonstrated that the capillary pressure obtained from centrifuge experiments in some cases may not be representative of dynamic capillary pressure governing the multi-phase flow in porous media. |
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| ISSN: | 2190-0558 2190-0566 |