Performance Prediction In Gas Condensate Reservoirs

Abstract

Abstract Gas condensate reservoirs constitute a significant portion of hydrocarbon reserves worldwide. The prediction of reservoir performance and its economic impact requires the accurate modelling of the flow and phase behaviour in such reservoirs. The liquid drop out may lead to recovery problems such as near wellbore permeability impairment and uncertainty in the actual location of the target condensate. In addition, the produced gas becomes lighter and less marketable with time. Such issues can be addressed through improved understanding of the formation of condensate and the multiphase flow of gas and condensate in the reservoir as characterized by relative permeability curves. The appropriate relative permeability curves in turn can be used in reservoir simulators to assist in optimization of field development. Gas Condensate Reservoirs Various types of reservoirs can be classified by the location of their initial reservoir pressure and temperature with respect to the two phase gas/liquid region. This is commonly shown on pressure- temperature diagrams such as the one schematically shown in Figure 1 for a multicomponent hydrocarbon mixture of constant composition. The area inside the envelope formed by the bubble point curve, the critical point (C), and the dew point curve is the the region where both the gas and the liquid phases will exist in equilibrium. The curves within the two phase region show the percentage of the total hydrocarbon volume which is liquid. Fluids initially at locations marked I through V would be classified as black oil, volatile oil, gas condensate, wet gas, and dry gas, respectively. Gas condensate reservoirs are separated from others by two characteristics. First, a liquid phase condenses at reservoir conditions during isothermal depletion. Second, this liquid revapourizes (retrograde behaviour) with further pressure depletion. The condensation starts at the dew point pressure (DPP) shown as point D in Figure 1. The volume of liquid increases to approximately 10% at point R where the retrograde condensation starts. After this point, the liquid volume decreases with continued reduction in pressure. The fluid type should be determined on the basis of laboratory experiments which requires reliable values of reservoir temperature, initial pressure, and a representative fluid sample. In general, .gas condensate reservoirs may be approximately defined as those which produce light coloured to colourless stock tank liquids with API gravities above 45 °API at gas oil ratios in the range of 5,000 to 100,000 scf/stb. The laboratory experiments are the basis for determining the properties of gas condensate fluid properties. However, such experiments cannot be performed for all conditions where values of fluid properties are required for reservoir engineering computations. The common predictive tool for such properties is an equation-of-state (EOS) package. A lumped fluid description coupled with EOS parameters tuned to duplicate the laboratory results can be used to predict the fluid properties separately or in a compositional simulator. Reliable predictions of gas reserves and well productivity are essential to establish a development plan. Overestimating the well productivities may render fulfilling the contractual obligations impossible while underestimating them may lead to increased spending, thus, preventing the development of smaller fields.