The paper presents a C7+ characterization procedure for the PC-SAFT equation of state. The characterization procedure was applied to model both routine and EOR PVT for a Middle East reservoir fluid. The injection gas contained 60 mole% of CO2. No other parameter adjustment was needed than to determine the optimum binary interaction parameters for CO2. Among the data matched was a liquid-liquid critical point on a swelling curve for a CO2 mol% of 43. The PC-SAFT simulation results suggest that the fluid for this CO2 concentration has two critical points. The one at the lower temperature agrees with the critical point found in the swelling test. The study shows that the potential of the PC-SAFT equation of state in the oil industry is not limited to modeling of asphaltene precipitation and other specialized applications. Extensive routine and EOR PVT data including a minimum miscibility pressure has been modeled using the PC-SAFT equation. Unlike cubic equations, a volume correction does not have to be applied to match liquid densities.
CO2 and hydrocarbon gas injection are interesting Enhanced Oil Recovery (EOR) techniques for oil reservoirs. Gas injection may initiate asphaltene precipitation in a reservoir. 1D compositional CO2 gas injection simulations have been conducted to find out where asphaltenes will precipitate and deposit. It was found that asphaltenes will precipitate in the transition zone between injection gas and oil. This transition zone will move forward continuously and no accumulation of asphaltene deposit will take place. Though deposited asphaltenes locally will plug reservoir pores and decrease permeability, this is unlikely to affect the oil recovery. The mobility of the gas and oil phases is high in the gas-oil transition zone where asphaltenes precipitate, and those high mobile phases will manage to bypass a small volume fraction of deposited asphaltenes. With an asphaltene phase present in addition to gas and oil the classical definition of a miscible gas drive cannot be fulfilled. Miscibility can however develop between an injection gas and an oil phase, which through contact with gas has been stripped for asphaltene components.
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.
The paper presents compositional data and PVT data for a Middle East reservoir fluid with a reservoir temperature of 394 K and reservoir pressure of 287 bar. The PVT data was selected and designed to provide the best possible starting point for developing an EOS model that would accurately reproduce the phase behavior of a reservoir fluid subject to injection of either CO2 or a hydrocarbon gas.
To eliminate the uncertainty from use of default molecular weights and densities for the C7+ hydrocarbon fractions the reservoir fluid composition was analyzed using a True Boiling Point (TBP) analysis. PVT experiments, both routine and gas injection (EOR) experiments, were carried out including solubility swelling, equilibrium and multi contact experiments and slim tube tests. With both injection gases the reservoir fluid shows a combined vaporizing/condensing drive mechanism.
A 9-component EOS model was developed for the volume corrected Peng-Robinson equation of state, which shows a good match of all available data. Two methods were used to predict the vaporizing/condensing MMP; (a) a multi-component tie-line MMP algorithm and (b) a compositional 1D simulator. The CO2 MMP is considerably lower than the reservoir pressure while the MMP seen with the hydrocarbon gas is close to the reservoir pressure.