Pressure-Volume-Temperature Correlations For Western Canadian Gases And Oils
Authors: Asgarpour Soheil , McLauchlin Larry , Wong Dale , Cheung Vincent 
Published: March 2010

Empirical correlations for the prediction of reservoir fluid properties have played a significant role in the design of petroleum production facilities and in reservoir engineering studies. Katz(1), In. 1942, developed a correlation from Mid-Continent crudes data to predict formation volume factors. Since then many researchers and investigators have developed either new or improved correlations of this nature. The fundamental concept behind most of the empirical correlations is to estimate fluid properties such as solution gas-oil ratio, formation volume factor, and bubble point pressure as a function of field-measured quantities. These quantities include crude oil API gravity, gas specific gravity, flash gas-oil ratio, reservoir pressure and temperature. Recently the accuracy of several well-known correlations, such as Standing, Lasater, Vazquez(2–4) and others were investigated for 300 different fluid sample from western Canadian oil and gas reservoirs. The results indicated that in many cases the correlations were not accurate. This result was expected as no correlations have ever been developed using fluid properties of western Canadian crudes.

The objective of this study is to develop new sets of correlations to improve the accuracy of estimating physical properties and phase behaviour for western Canadian crudes based on over 10 different samples from this region. Correlations were developed for different geological formations where sufficient data was available to warrant the statistical approach. The new correlations will benefit practicing engineers in their day-to-day duties.

Introduction

The evaluation of the fluid properties plays a significant role in the design of surface operation facilities and reservoir engineering studies. In many occasions when the bubble point pressure, solution gas-oil ratio and formation volume factor are not available for various reasons, it is desirable to be able to estimate these properties from measured parameters in the field such as pressure, temperature, gas specific gravity, oil gravity and flash gasoil ratio.

Development of correlations for the fluid properties based on readily available measured parameters in the field has been the subject of investigation for over forty-five years. Katz(1) in 1952 developed a correlation for formation volume factor based on 117 oil samples from Mid-Continent crudes. Standing(2) developed correlations for bubble-point pressure, formation volume factor as an empirical function of gas-oil ratio, specific gas gravity.oil API gravity, and temperature. In 1957, Lasater(3) developed correlations for bubble-point pressure based on 158 experimentally-measured bubble-points pressure obtained from Canada, the western and mid-continental United States and South America.He expressed the bubble-point pressure in terms of field measured separator gas-oil ratio, tank oil gravity, total gas gravity nd reservoir temperature.

Knopp and Ramsey(5) in 1959 correlated thermally-reduced oil formation volume factors with solution gas-oil ratio. This correlation was made from the differential liberation data of 159 analyses of saturated eastern Venezuelan crudes. Glasco(6) developed correlation for North Sea oil to estimate bubble-point pressure, formation volume factor from field-measured separation gas-oil ratio, gas gravity, stock-tank oil gravity and reservoir temperature. In 1977, Vasquez and Beggs(4) presented correlations for solution gas-oil ratio, formation volume factor, and viscosity.