The Effect of Compositional Gradient in Field Development

The existence of fluid’s compositional gradient in a reservoir drives convective flow which brings significant impacts to the operations, e.g., in formulation of injected fluid for well stimulation and enhanced oil Recovery (EOR). However, fluid compositional gradient is not always included in modeling reservoir performance due to PVT sampling limitation and simulation constraint. This work aims to show the significance of compositional convection in oil/gas reservoir and provides our experiences in dealing with this issue in Indonesian’s fields. PHE ONWJ as one of the most prolific producers of oil and gas in Indonesia currently operates an offshore block that has been producing for almost 40 years. Operating in a relatively mature well, PHE ONWJ often encounters significant fluid property change namely oil viscosity and specific gravity that changes overtime as depletion process occur. Data from X field, operated by PHE ONWJ, shows that compositional convection impacts workover and tertiary operations, by deviating from simulation results. We present the evidence of compositional convection using mechanistic models. We firstly adopt field data for setting the initial composition stratification. The stratification is identified through DST or fluid sampling. We secondly perform similarity simulation to analyze the effect of compositional gradient towards oil production. Similarity simulation is performed in the simplified domain for providing generalized solution. This solution is then scaled for the real domain. Finally, we show our approach to encounter the problems. Based on the similarity study inspired by the case of X Field, it shows that the compositional stratification affects geochemistry and near-wellbore flow behavior. The compositional convection develops multiple fluid properties at different depth, which create cross flow among layers. It also causes scale deposition in near wellbore which reduces the permeability and alters rock-fluid interactions, such as wettability and relative permeability. The alteration of near-wellbore geochemistry creates severe flow assurance issues in the wellbore. The mixing of multiple fluids from different layers cause paraffin and scale deposition. In some fields, the mixing triggers severe corrosions which could impact on wellbore integrity. The compositional stratification forces us to develop multiple treatments for different layers in single wellbore. Since the fluid’s properties are different for each layer, the compatibility between injected fluid and reservoir fluids varies.