Abstract
The paper presents an Equation-of-State (EOS) modeling work carried out for a Middle East reservoir fluid for which gas injection was considered for increasing ultimate recovery. The aim of the work was to develop an EOS model that would accurately reproduce the phase behavior in a reservoir on injection of either a hydrocarbon gas (mix of gas condensate and associated rich gas) or a CO2 rich gas. A single EOS model was developed, which provided a good match of data for both injection gases. This EOS model enables compositional reservoir simulation studies to be carried out comparing and contrasting the recovery from the field with each of the two injection gases.
Extensive PVT data was available and to be matched by a 9-component ‘lumped’ EOS model. Available data included classical PVT data as well as gas injection (EOR) data including solubility swelling, equilibrium contact and slim tube tests. A major challenge was to develop a model which, in addition to classical PVT data, which can easily be regressed to, also matched slim tube minimum miscibility pressures (MMPs). A multi-component tie-line method was used considering combined vaporizing/condensing drives, and the tie-line MMP was afterwards verified using a cell-to-cell simulator.
Depth gradient simulations indicated that the transition from liquid-like to vapor-like properties in the reservoir did not take place through a sharp gas-oil contact (GOC), but happened continuously in a‘transition zone’. An EOS model neglecting such‘transition zones’ or simulating a sharp gas-oil contact may lead to severe misinterpretations in reservoir simulations. A segregation model based on irreversible thermodynamics was used to investigate the influence of an observed vertical temperature gradient on the compositional variation with depth.
