A unified treatment of materials balance computations to estimate hydrocarbons in place is presented. This method generalizes the normal procedures for gas reservoirs to all fluids of interest to the petroleum industry. We show that a plot of average pressure divided by a two-phase deviation factor can be used to compute hydrocarbons in-place. A simple procedure to estimate the required two-phase deviation factors for black oils and volatile oils is discussed. This extends the method of Vo et. al. for gas condensates to these other systems. We concluded, in particular, that data above the phase envelope (single phase information) can be extrapolated and combined with data inside the phase envelop (two-phase information) to obtain initial hydrocarbons in place. The need for accurate fluid property description is emphasized and potential information that is obtainable from accurate fluid descriptions is noted, It is shown that data above the phase envelope can be extrapolated to obtain initial hydrocarbons in place.
Historically, materials balance computations for oil and gas reservoirs have been done differently, probably due to the fact that problems involved in considering the appearance of a second phase are not germane to the evaluation of dry gas reservoirs. The purpose of this paper is to present a unified method for the conduct of materials balance studies for the entire range of fluids of interest (black oils, volatile oils, gas condensates and dry gases) to petroleum production engineers. This objective is attained by computing two-phase compressibility factors from composition data. The principal advantage of our method is that extrapolations to estimate initial hydrocarbons in place can be done with data measured entirely above the phase envelope. Furthermore, our procedure avoids problems associated with properly accounting for mass transfer as fluids separate in the wellbore and in surface equipment. Theoretical considerations are also addressed, in that, errors involved in computations are discussed. A field example for a volatile oil reservoir is presented to justify theoretical conclusions.
Most simulations in this work were done using the model developed by Jones. 1 This model is a fully implicit compositional model and simulates the isothermal flow of fluids in a cylindrical reservoir with the well located at its centre. The reservoir is assumed to be a homogeneous system except for the existence of a skin zone which is modeled as a region of permeability distinct from that or the reservoir.2 The Redlich-Kwong equation of state as modified by Zudkevitch and Joffe3 is used to simulate phase behavior and mass transfer. Fluid viscosities are computed from the Lohrenz, Bray and Clark4 correlations. Gravitational effects are ignored and the well is produced at a constant molar rate or at a constant wellbore pressures. We have used this model for approximately six years in a number of studies (e.g. References 5–7). Verification procedures to ensure the accuracy of simulations done with this model are discussed in Reference 1.
Three fluids are examined in this study: a gas condensate, a volatile oil, and a black oil.