Search

Summary Limited and uncertain geologic and engineering data at the onset of any new field development are the bane of reservoir characterization and simulation. The problem stems from the uncertainty in various model-input variables, such as reservoir connectivity, fluid viscosity, and endpoint saturations, to name a few. Given this scenario, an ad hoc, one-factor-at-a-time approach to earth and flow-simulation modeling cannot possibly yield unbiased information for making objective business decisions. This study presents three field cases in which both engineering and earth-model variables were varied in a systematic way to assess reservoir performance by use of the experimental design (ED) approach. Results of the field cases show that well requirements (both producers and injectors) turned out to be fewer than anticipated. Equally important, one case study showed that laboratory measurements could minimize uncertainty surrounding oil viscosity and endpoint saturations. At the same time, we learned that the preferred horizontal-well orientation was marginally superior to vertical wells in light of high reservoir anisotropy. In another case, stratigraphy, gas/oil contact (GOC), and aquifer strength became the primary variables for the full-factorial design after the initial screening. Here, we proved that the project could proceed because it met the minimum reserves criterion. Perhaps most importantly, all studies showed how to obtain unbiased information in far fewer flow-simulation runs than one would do using an ad hoc approach.

Abstract Viscosity values (μ) were measured at different temperatures (40, 50, 60, 70, 80 and 90 °C) for a set of dead oils from the Liaohe basin, NE China, covering a viscosity range from 76 to 34,590 mPa •s at 50 °C. A good relationship emerges between temperature and viscosity and a corresponding viscosity temperature correlation with a high coefficient was obtained for every oil sample. Detailed investigations revealed that μT (viscosity values at temperature T = 60, 70, 80 and 90 °C) shows a strong function of μ50 (viscosity value at 50 °C) in the form of μT = a μ50b, in which the parameters a and b show a function of temperature [a = ƒ(T) and b = ƒ1(T)] with high coefficients. Therefore, a new simple correlation for predicting oil viscosity has been deduced as a function of temperature and μ50 in the form of μT = ƒ(T) μ50 ƒ1(T) with only two input parameters: temperature and viscosity at 50 °C. The validity of the model for Liaohe heavy oils has been tentatively confirmed by a set of experimental data from the laboratory of the Liaohe Oil Field with most errors less than 10% for the viscosity prediction at 100 °C. The correlation reported in this paper may provide an alternative method to predict the viscosity for dead oils, especially for heavy oils with μ50 even up to 160,000 mPa •s in the Liaohe basin. Introduction Despite the high viscosity, heavy oil is becoming a more and more important part of the energy supply in the world with the petroleum demand growing and conventional oil depleting. Owing to the extreme importance of viscosity in planning possible EOR schemes, testing wells and designing production equipment and pipelines, it is necessary to estimate it accurately. As for heavy oils, the high viscosity may be one of the most important physical properties and the most serious impediments in various aspects of petroleum engineering. Therefore, much attention has been focused on viscosity determination. A laboratory measure of a crude oil often provides viscosity information at a fixed temperature. However, oil viscosities at other temperatures are often required. Therefore, viscosity prediction for crude oils at a desired temperature by a common laboratory measure will be very useful. A number of empirical viscosity correlations or prediction models based on some specific parameters have been documented in the literature. Many correlations for predicting viscosity of dead oil were reported by Beggs and Robinson(1), Glaso(2), Kartoatmodjo and Schmidt(3), Elsharkawy and Alikhan(4), and Naseri et al.(5). All the prediction models have expressed the dead oil viscosity as a function of oil API gravity and temperature and mainly focused on conventional oils. Limited methods have been reported for viscosity prediction for heavy oils(6, 7), even less for oils with viscosity higher than 20,000 mPa •s. In this paper, a new simple viscosity correlation is proposed based on the temperature-viscosity data of oils from the Liaohe basin, NE China. It will be seen here that the correlation can be used as an alternative method to predict oil viscosity, especially for heavy oils, at a desired temperature using a common viscosity value μ50.