6 Reasons Why You Should Accurately Calculate the Solution Gas-Oil Ratio

Updated on 1 Dec 2021
Dependency between PVT properties of black oil

Why it’s essential to obtain more precise values of your reservoir solution gas-oil ratio? This post would help you easily understand the dependency between your PVT properties.

In the case of unavailable experimental PVT data, you would rely on PVT empirical correlations in the petroleum literature to calculate any black oil property. All black oil correlations require multiple field data as input:

  1. Stock-tank oil gravity, °API
  2. Gas specific gravity, γg
  3. Solution gas-oil ratio at bubble point pressure, Rsb
  4. Reservoir temperature, T
  5. Reservoir pressure, p

The first black oil property you need to calculate is the oil bubble point pressure, Pb, at reservoir temperature. That is because almost any black oil PVT property tends to behave at pressures less than bubble point pressure, entirely different from the way it behaves at pressures greater than bubble point pressure.

The second black oil property you need to calculate is the solution gas-oil ratio at pressures less than bubble point pressure, Rs. The solution gas-oil ratio on its own is directly affecting six subsequent PVT properties, as described in the chart above. That is why accuracy is critical when calculating the solution gas-oil ratio.

Here are the six black oil PVT properties that are strongly dependent on the values estimated for the solution gas-oil ratio:

Bo — Oil Formation Volume Factor

At pressures less than bubble point pressure, the saturated oil formation volume factor depends on the value you already calculated for the solution gas-oil ratio, Rs.

That is why any PVT correlation you will use for the oil formation volume factor must calculate the solution gas-oil ratio, Rs, at first.

While at pressures greater than bubble point pressure, the under-saturated oil formation volume factor depends only on the under-saturated oil compressibility, co.

µo — Oil Viscosity

At pressures less than bubble point pressure, the saturated oil viscosity depends on the dead-oil-viscosity, μod, and the value you already calculated for solution gas-oil ratio, Rs.

That is why any PVT correlation you will use for the oil viscosity must calculate both the dead-oil-viscosity, μod, and the solution gas-oil ratio, Rs, at first.

While at pressures greater than bubble point pressure, the under-saturated oil viscosity depends only on the oil viscosity at the bubble point pressure, μob.

ρo — Oil Density

At pressures less than bubble point pressure, the saturated oil density depends on the value you already calculated for the solution gas-oil ratio, Rs, and the saturated oil formation volume factor, Bo.

That is why any PVT correlation you will use for the oil density must calculate both the solution gas-oil ratio, Rs, and the oil formation volume factor, Bo, at first.

While at pressures greater than bubble point pressure, the under-saturated oil density depends only on the under-saturated oil compressibility, co.

co — Oil Compressibility

At pressures less than bubble point pressure, the saturated oil compressibility depends on the value you already calculated for the solution gas-oil ratio, Rs, and the saturated oil formation volume factor, Bo.

That is why any PVT correlation you will use for the oil compressibility must calculate both the solution gas-oil ratio, Rs, and the oil formation volume factor, Bo, at first.

While at pressures greater than bubble point pressure, the under-saturated oil compressibility is independent of any other black oil property.

Bt — Total/Two-Phase Formation Volume Factor

At pressures less than bubble point pressure, the total/two-phase formation volume factor depends on the value you already calculated for the solution gas-oil ratio, Rs, the oil formation volume factor, Bo, and the gas formation volume factor, Bg.

That is why calculating the total/two-phase formation volume factor needs calculating the solution gas-oil ratio, Rs, the oil formation volume factor, Bo, and the gas formation volume factor, Bg, at first.

While at pressures greater than bubble point pressure, the value for the total/two-phase formation volume factor is the same as the value estimated for the under-saturated oil formation volume factor because all the gas is still soluble in the liquid phase.

σo — Gas-Oil Surface/Interfacial Tension

At any pressure, the gas-oil surface/interfacial tension depends on the value you already calculated for the solution gas-oil ratio, Rs, the oil formation volume factor, Bo, and the gas formation volume factor, Bg.

That is why any PVT correlation you will use for the gas-oil surface/interfacial tension must calculate the solution gas-oil ratio, Rs, the oil formation volume factor, Bo, and the gas formation volume factor, Bg, at first.

Conclusion

This table aims to describe the dependency between different PVT properties of your reservoir black oil.

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