A Review of Bubblepoint Pressure and Oil Formation Volume Factor Correlations
- A.A. Al-Shammasi (Saudi Arabian Texaco)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- April 2001
- Document Type
- Journal Paper
- 146 - 160
- 2001. Society of Petroleum Engineers
- 5.2 Reservoir Fluid Dynamics, 4.1.9 Tanks and storage systems, 5.2.1 Phase Behavior and PVT Measurements, 4.6 Natural Gas, 4.1.2 Separation and Treating, 6.1.5 Human Resources, Competence and Training, 4.1.5 Processing Equipment
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This paper evaluates published correlations and neural-network models for bubblepoint pressure (pb) and oil formation volume factor (Bo) for their accuracy and flexibility in representing hydrocarbon mixtures from different locations worldwide. The study presents a new, improved correlation for pb based on global data. It also presents new neural-network models and compares their performances to numerical correlations.
The evaluation examines the performance of correlations with their original published coefficients and with new coefficients calculated based on global data, data from specific geographical locations, and data for a limited oil-gravity range. The evaluation of each coefficient class includes geographical and oil-gravity grouping analysis. The results show that the classification of correlation models as most accurate for a specific geographical area is not valid for use with these two fluid properties. Statistical and trend performance analysis shows that some published correlations violate the physical behavior of hydrocarbon fluid properties. Published neural-network models need more details to be reproduced. New developed models perform better but suffer from stability and trend problems.
Solutions to reservoir performance problems at various stages of reservoir life require knowledge of the physical properties of reservoir fluids at elevated pressures and temperatures. The pressure/volume/temperature (PVT) properties for reservoir hydrocarbon mixtures are usually obtained from laboratory analysis of preserved or recombined reservoir fluid samples. Because experimental facilities are not always available, other means for estimating PVT properties have been developed; during the last 50 years, many correlations have been developed for this purpose.
PVT properties are a function of temperature, pressure, composition of the hydrocarbon mixture, and the presence of paraffins and impurities. The performance of an empirical model depends mainly on how accurately a correlation model represents this mixture under specific conditions. The purpose of this paper is to study the performance of models available in the literature, based on published experimental data.
The study was carried out to model the pb and the Bo at and below the pb. Both empirical correlations and neural-network models were considered to reach a clearer understanding about what model to use and what to expect. A large global database gathered for this study was used to develop correlation models that predict oil properties better than existing models.
Since the 1940's, engineers in the United States have realized the importance of developing empirical correlations for PVT properties. Studies carried out in this field resulted in the development of new correlations. Several studies of this kind were published by Katz,1 Standing,2 Lasater,3 and Cronquist.4 For several years, these correlations were the only source available for estimating PVT properties when experimental data were unavailable. In the last 20 years there has been an increasing interest in developing new correlations for crude oils obtained from various regions in the world. Vazquez and Beggs,5 Glaso,6 Al-Marhoun,7,8 and Abdul-Majeed and Salman9 carried out some of the recent studies. The following presents a review of the best-known correlation models published in the literature. A summary of these published correlation models is provided in the Appendix (Tables 1 and 2), including the forms of correlation used, errors reported by each author, and details of the data used for each development.
In 1942, Katz1 published a graphical correlation for predicting Bo. Katz1 used U.S. midcontinent crude to develop his correlations. The graphical correlation uses reservoir temperature, pressure, solution gas/oil ratio (GOR), oil gravity, and gas gravity. The correlations were presented only in graphical form and were hard to use because they required the use of graphs and calculations in combination.
In 1947, Standing2,10,11 published his correlations for pb and for Bo. The correlations were based on laboratory experiments carried out on 105 samples from 22 different crude oils in California, U.S.A. The correlations treated the pb and the Bo as a function of the reservoir temperature, GOR, oil gravity, and gas gravity. Standing's2,10,11 correlations were the first to use these four parameters, which now are commonly used to develop correlations. In fact, these correlations are the most widely used in the oil industry.
Lasater3 in 1958 presented a new correlation model based on 158 samples from 137 reservoirs in Canada, the U.S., and South America. His correlation was only for pb. It is based on standard physical chemical equations of solutions. It uses Henry's law constant and the observation that the bubblepoint ratio at different temperatures is equal to the absolute temperatures ratio for hydrocarbon systems not close to the critical point. The correlation was presented in graphical form and was used as a lookup chart. An advantage of Lasater's3 correlation is the wide variety of data sources used to develop the correlation.
In 1972, Cronquist4 presented a ratio correlation based on 80 data points from 30 Gulf Coast reservoirs. The correlation is useful for the analysis of depletion-drive reservoirs when PVT analysis is not available. The method was presented in graphical form and requires an estimation of average reservoir properties.
In 1976, Vazquez and Beggs5 published correlations for GOR and Bo. They started categorizing oil mixtures into two categories, above 30°API gravity and below 30°API gravity. They also pointed out the strong dependence on gas gravity and developed a correlation to normalize the gas-gravity measurement to a reference separation pressure of 100 psi. This eliminated its dependence on separation conditions. More than 6,000 data points from 600 laboratory measurements were used in developing the correlations.
Glaso6 in 1978 developed correlations for pb, formation volume factor, GOR, and oil viscosity for North Sea hydrocarbon mixtures. The main feature of Glaso's6 correlations is that they account for paraffinicity by correcting the flash stock-tank-oil gravity to an equivalent corrected value with reservoir temperature and oil viscosity. They also account for the presence of nonhydrocarbons on saturation pressure by using correction factors for the presence of CO2, N2, and H2S in the total surface gases. A total of 45 oil samples, most of which came from the North Sea region, were used in the development of these correlations.
In 1988, Al-Marhoun8 published new correlations for estimating pb and Bo for Middle East oils. A total of 160 data sets from 69 Middle Eastern reservoirs were available for the correlation development. Al-Marhoun's7,8 correlations were the first to be developed for Middle East reservoirs.
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