Exploring The Fascinating World Of Reservoir Fluid Phase Behaviour

Abstract

Introduction Reservoir fluid phase equilibria affect all aspects of petroleum industry operations, from reservoir development to fluid processing and pipelining. Fluid composition, phase equilibria and physical properties are needed on the upstream side in reserves evaluation, well testing, predicting reservoir performance and optimizing its recovery. As still deeper formations including off-shore structures are drilled, more exotic fluids are encountered. The recently considered plan to produce a reservoir in Alberta containing fluid with H2S in excess of 90% is one such example. The phase equilibria reflect the nature of intermolecular forces, and the behaviour of these highly non-ideal systems presents a severe test of correlations (including the most sophisticated one, the equation of state) developed to describe properties of the typical gas and oil. While a lot of progress has been made in modeling phase equilibria and properties of reservoir fluids, some laboratory measurements still form a basic part of fluid evaluation. This brief note selects to explore the special but quite frequently encountered features of reservoir fluid equilibria-the complex phenomena brought about by close proximity to the critical point. Near-critical fluids and mixtures are encountered in both primary and supplementary recovery processes. Some manifestations of near-critical behaviour are discussed. The reservoir engineer needs to be aware of them, as near-critical conditions have implications for fluid flow, multiple phase formation, data collection, and data interpretation. Reservoir Fluid Spectrum Figure 1, the pressure-temperature diagram, provides a suitable frame of reference for classifying different oil and gas field fluids. The classification is based on the position of a fluid two-phase envelope relative to reservoir and surface conditions of pressure and temperature. The shape of the two-phase region and the relative positions of the critical point (CP), the cricondenbar and cricondentherm (maximum two-phase pressure and temperature, respectively) are determined by fluid composition, specifically by the magnitude and makeup of the C7+ fraction. As the amount of the C7+ fraction increases, the fluid character changes from a dry gas to a wet gas, gas condensate, volatile oil, black oil (and ultimately, a bitumen). At the same time the two-phase envelope extends to higher temperatures. The different production paths implied in the figure by possible reservoir (R) and surface (S) conditions define different fluid types as follows: RI-SI is a dry gas, RI-S2 a wet gas, R2-S2 a gas condensate, R3-82 a volatile oil, and R4-83 a black oil. Turning attention to reservoirs at temperatures close to fluid critical temperature, these are either volatile oils (R3) with bubble point saturation pressures, or gas condensates (R2) with dew point saturation pressures. A rule-of-thumb usually applied in determining the fluid type considers fluids with C7+ content over 12.5% and of producing GOR under 570 m3/m3 to be oils. However, a hypothetical fluid with the phase diagram of Figure 1, i.e., of a fixed C7+ content and fixed surface GOR (corresponding to, e.g., 82) could be either an oil or gas depending entirely on whether the reservoir temperature is R2 or R3! This illustrates that this rule-ofthumb, while quite useful, has to be applied judiciously.