Oil rock interaction may lead some wells to a sharp decline in productivity which is not associated with a major drop in reservoir pressure or increase in water cut. Also excessive drawdown is known to cause productivity decline and potentially causes permanent damage to the wells through one or all of the following: Fine migration, asphaltene deposition and/or emulsion formation around the wellbore.

Flooding tests were performed under reservoir conditions of pressure and temperature using filtered reservoir crude oil and synthetic brine generated from a geochemical analysis representative of the reservoir brine.

A major finding of the experimental displacement tests showed that monitoring of pressure gradient across the cores at various flow rates and water cuts have indicated a marked rock fluid interaction rendering Darcy's law inapplicable. Emulsion formation has been monitored through visual observation first using a sight glass ahead of the backpressure regulator followed by observation under ambient conditions.

The nature and distribution of fines inside the cores as well as hydrocarbons deposition were evaluated through post-flood examination of the cores under the microscope as well as by SEM and thin section techniques, and comparison with pre-flood conditions.

The main objective of this paper is to describe the adopted approach, utilizing field data and laboratory experiments to quantify the impact of rock fluid interaction on optimum drawdown.

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