Classifications of Crude Oil
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This document discusses various systems for classifying crude oil and hydrocarbon resources. It describes classification based on chemical composition, including proportions of paraffins, naphthenes and aromatics. It also discusses physical property-based classification systems including API gravity, viscosity, density and pour point. Reservoir characterization aims to identify and quantify reservoir properties that control fluid distribution and migration in order to accurately describe the reservoir and optimize hydrocarbon recovery. Future resources are expected to come from unconventional reservoirs with low permeability.
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Classifications of Crude Oil
- 2. 2.1 Introduction 2.2 Classification Systems 2.2.1 Classification as a Hydrocarbon Resource 2.2.2 Classification by Chemical Composition 2.2.3 Correlation Index 2.2.4 Density 2.2.5 API Gravity 2.2.6 Viscosity 2.2.7 Carbon Distribution 2.2.8 Viscosity–Gravity Constant 2.2.9 UOP Characterization Factor 2.2.10 Recovery Method 2.2.11 Pour Point 2.3 Miscellaneous Systems 2.4 Reservoir Classification 2.4.1 Identification and Quantification 2.4.2 Future
- 3. Composition of crude oil:
- 6. Hydrocarbon resources divide into two classes: (1) Naturally occurring hydrocarbons (petroleum, natural gas, and natural waxes) (2) Hydrocarbon sources (oil shale and coal)
- 7. The hydrocarbons found in petroleum are classified into the following types: (1) Paraffins (2) Cycloparaffins (naphthenes) (3) Aromatics
- 8. Petroleum (Crude oils) are classified as: (1) Paraffin base - contained more than 5% wax (2) Asphalt base - distillation residue contained less than 2% wax
- 9. CI = 473.7d – 456.8 + 48,640/K, K - petroleum fraction is the average boiling point determined by the standard Bureau of Mines distillation method d - specific gravity OR CI = 87552/TB + 473.7G – 456.8 TB - mean average boiling point, °R G - specific gravity at 60°F CI = 0 - straight-chain paraffins CI = 100- benzene
- 10. Values for the Correlation Index: 0-15 : predominance of paraffin hydrocarbons in the fraction. 15-50 : predominance of either naphthenes or of mixtures of paraffins, naphthenes, and aromatics. more than 50 : predominance of aromatic species.
- 11. Light: less than 870 kg/m3 (greater than 31.1°API) Medium: 870 to 920 kg/m3 (31.1°API to 22.3°API) Heavy: 920 to 1000 kg/m3 (22.3°API to 10°API) Extra-heavy: greater than 1000 kg/m3 (less than 10° API)
- 12. The formula to calculate API gravity from Specific Gravity (SG) is: SG – specific gravity at 60°F
- 13. The API values for each “weight” are as follows: Light – API > 31.1 Medium – API between 22.3 and 31.1 Heavy – API < 22.3 Extra Heavy – API < 10.0 Heavy oils were considered those petroleum-type materials that had gravity somewhat less than 20° API Tar sand bitumen falling into the 5° to 10° API range
- 14. Briefly, materials having viscosity less than 10,000 centipoises (cp) are conventional petroleum and heavy oil Tar sand bitumen has a viscosity greater than 10,000 cp
- 15. A high value of %CA at 500°C (930°F) boiling point usually indicates a high content of asphaltenes in the residue A high value of %CnP at 500°C (930°F) boiling point usually indicates a waxy residue.
- 16. For oil types: d is the specific gravity at 60° F v is the Saybolt viscosity at 39°C (100°F). For heavy oil (viscous crude oil): The lower the index number, the more paraffin the feedstock.
- 17. K = (TB)1/3/d Where: TB is the average boiling point in degrees Rankine (° F + 460) d is the specific gravity at 60° F Highly paraffin oils have K in the range 12.5 to 13.0 Cyclic (naphthene) oils have K in the range 10.5 to 12.5 Aromatics: 9.0- 10.5
- 19. When the reservoir temperature exceeds the pour point, the oil is fluid in the reservoir and therefore mobile. When the reservoir temperature is lower than the pour point, this indicates that the bitumen is solid within the deposit and therefore immobile.
- 21. Other classification methods: Chromatographic data - classification of crude oil on the basis of polarity Gas chromatography, Fourier transform infrared spectroscopy, proton magnetic resonance, urea adduction, and solid liquid chromatograph y – classification of petroleum wax Pyrolysis–gas chromatography - classification of kerogen
- 23. Petroleum reservoir characterization is the process of identifying and quantifying those properties of a given petroleum reservoir which affect the distribution and migration of fluids within that reservoir. These aspects are controlled by the geological history of the reservoir. Further, the ultimate goal of a hydrocarbon reservoir characterization study is the development of a reasonable physical description of a given reservoir. This physical description can then be used as a basis for simulation studies, which, in turn, are used to assess the effectiveness of various recovery strategies. An accurate physical description of the reservoir will often lead to the maximum production of hydrocarbons from the reservoir.
- 24. Future energy resources will be found in what are currently considered to be unconventional reservoirs, especially low- permeability reservoirs in shale, siltstone, fine-grained sand, and carbonates.
- 25. Reported by: Pam Cudal BSPE-3C Summer 2016 April 18, 2016