Types of Reservoir Fluids Reservoir fluids are classified based on their composition, phase behavior, and physical properties. The primary types include:
1. Black Oil – A high-viscosity crude oil with dissolved gas that separates under lower pressures.
2. Volatile Oil – A lighter crude oil with a higher gas-to-oil ratio (GOR) and significant gas liberation as pressure decreases.
3. Gas Condensate – A hydrocarbon mixture that exists as gas in the reservoir but condenses into liquid when pressure drops.
4. Dry Gas – Composed mainly of methane with little or no condensable hydrocarbons.
5. Wet Gas – Contains significant heavier hydrocarbons that may condense at surface conditions.
Key Reservoir Fluid Properties Several physical and chemical properties define the behavior of reservoir fluids:
1. Density and Specific Gravity
Density is the mass per unit volume and varies with temperature and pressure.
Specific gravity compares the fluid’s density to water (for oil) or air (for gas).
2. Viscosity
Measures fluid resistance to flow.
High-viscosity fluids flow slower, affecting production rates and recovery efficiency.
3. Formation Volume Factor (FVF)
The ratio of fluid volume in the reservoir to its volume at surface conditions.
Important for estimating recoverable reserves.
4. Solution Gas-Oil Ratio (GOR)
The amount of gas dissolved in crude oil at reservoir conditions.
Affects phase behavior and production strategy.
5. Bubble Point Pressure
The pressure at which gas begins to come out of solution in oil.
Crucial for maintaining reservoir pressure and avoiding premature gas liberation.
6. Dew Point Pressure
The pressure at which gas condensate starts forming in a gas reservoir.
Helps in designing production and processing facilities.
7. Compressibility
Defines how fluid volume changes with pressure.
Higher compressibility in gas leads to significant volume changes under varying pressures.
8. Interfacial Tension (IFT)
Affects fluid interactions at phase boundaries.
Important in enhanced oil recovery (EOR) methods.