Gas condensate reservoirs are simulated using a compositional simulation model to account for composition and volumetric behavior changes in both the reservoir and surface. The current approach in the industry is to use a tuned equations of state (EOS) model to represent the fluid phase behavior and volumetric properties. However; the drawback is the lack of  consensus on how to tune an EOS model, how many pseudo-components to use or what weight factors to apply to experimental data when tuning an EOS model for use in compositional simulation and modified black oil calculations (MBO). It is also believed that the tuning process is more of an art than a science; therefore, preparing an equation of state for a gas condensate reservoir is not an easy task and needs some engineering experience to assure that the developed EOS model is consistent. The objective of this study was firstly to develop two consistent EOS models for a Libyan gas condensate reservoir at Hamada Field; then secondly to use these two models to find the optimum surface separation conditions to optimize the liquid volume at the surface.

The proposed strategy is based on the results of pressure-volume-temperature (PVT) laboratory tests for a gas condensate reservoir fluid from Hamada Field. Although there are many equations of state available in the industry, the Peng-Robinson EOS (PREOS) has been manifested to be the best among all of equations in stock as a result of that it has been used in this study because of its popularity to each of researchers and engineers. Moreover, the PREOS is claimed to be more suitable for volumetric predictions in this study. The CMG (winprop) software has been used to tune the two EOS models against the available PVT data, match them, and generate consistent EOS models. A good agreement has been reached between the measured laboratory PVT data and the calculated data predicted by the developed models. Finally, these two models have been used to perform the optimization of the liquid volume at surface by finding the optimum separation temperature and pressure at which the oil/or liquid volume is increased considerably. The results of the optimized  models are vital, because the gas coming out of solution releases significant amounts of condensate at the surface facilities. Thus, the optimal primary (Tsp, psp) conditions will obviously depend on the type of stream being processed—i.e., the “gas-oil ratio” (“GOR”) of the stream. In all fields the processed streams will change over time (due to, for example, depletion, gas injection or tie-in of a new reservoir) and optimal separator conditions will also change over time. However, the largest total well stream molar rates will always come earlier in a field’s life, making the early optimal separator conditions most important to the design of surface facilities.