Introduction
The various reservoir fluid classifications are: undersaturated oil, bubble point oil, volatile oil, retrograde condensate, and dry or wet gas. Special cases such as Heavy Oil are separated.
Bitumen:
Initially in oil phase, oil phase has nearly constant compressibility and very high viscosity >100,000 mPa.s, such that oil is initially immobile.
Heavy Oil:
Heavy crude oil is highly viscous oil that cannot easily flow from production wells under normal reservoir conditions. It is referred to as "heavy" because its density or specific gravity is higher than that of light crude oil. Heavy crude oil has been defined as any liquid petroleum with an API gravity less than 20°.
Undersaturated oil:
The reservoir fluid is initially above the bubble point and below the critical temperature. A fluid above the bubble point is an undersaturated liquid, and this type of reservoir fluid is termed an undersaturated oil.
Saturated (bubble point) oil:
In some cases, the reservoir fluid is initially at the bubble point. This is an indication that the reservoir fluid is already in the two-phase region and has separated into an oil layer (oil zone) and a gas layer (primary gas cap). The oil is saturated with gas and is therefore at its bubble point. The gas is saturated with liquid and is therefore at its dew point.
Volatile oil:
If an oil is near its critical point, its properties begin to resemble gas properties, and it is termed a volatile oil.
Retrograde Condensate:
A retrograde-condensate gas reservoir initially contains a single-phase fluid, which changes to two phases (condensate and gas) in the reservoir when the reservoir pressure decreases.
Wet Gas:
A wet-gas reservoir is defined as producing a single gas composition throughout the life of the well. Condensate will form either while flowing to the surface or in lease-separation equipment.
Gas:
A dry-gas reservoir is defined as producing a single composition of gas that is constant in the reservoir, wellbore, and lease-separation equipment throughout the life of a field. Some liquids may be recovered by processing in a gas plant. Although producers of gas, Coal Seam Gas (CSG) and Tight Gas and Shale are discussed else-where.
Classification of Reservoir Fluids
After Blasingame [2023] and Tewari et al [2019], some general “Rules of thumb” for classification are:
|
Type |
Property |
|---|---|
|
Extra-Heavy Oil |
4 < API < 10 |
|
Heavy Oil |
10 < API < 20 Often negligible solution gas |
|
Black Oil Reservoirs (Low Shrinkage) |
GOR < 1,000 scf/STB Density < 45 API Reservoir Temp < 250 oF Color: Dark Green to Black C7+ composition > 30% |
|
Volatile Oil Reservoirs |
1000 < GOR < 8,000 scf/STB Density 45 - 60 API Oil FVF > 2.00 (high shrinkage oils) Color: Light Brown to Green. Sometimes bright Gold. C7+ composition > 12.5% |
|
Gas Condensate |
7,000 < GOR < 100,000 scf/STB Density > 60 API Light in color C&+ composition < 12.5% |
|
Dry Gas Reservoirs |
GOR > 100,000 scf/STB No liquid produced at surface |
See Also:
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Number of Fluids Flowing in the Reservoir
The mathematical expressions and algorithms that are used to predict the volumetric performance and pressure behaviour of a reservoir vary depending upon the number of mobile fluids in the reservoir. Given the descriptions above, there is a number of scenarios for petroleum systems:
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Single phase flow (oil, gas, or water). Transient models are often used for single phase flow analysis, either as PTA or RTA projects.
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Two (2) phase flow (oil-water, oil-gas, or gas-water). PSS models are often used for 2 phase flow analysis.
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Three (3) phase flow (oil, water, and gas) . PSS models are often used for 2 phase flow analysis.
References:
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Baker, R., Yarranton, H. Jensen, J. (2015) Practical Reservoir Engineering and Characterization, Gulf Publishing.
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Ahmed, T., Meehan, D. N (2004) Advanced Reservoir Engineering, Gulf Professional Publishing
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Raj Deo Tewari, Abhijit Y. Dandekar, and Jaime Moreno Ortiz, Petroleum Fluid Phase Behavoir: Characterization, Processes, and Applications.