ESP Gas Handling - Free Gas, Void Fraction, and Gas Separation

Overview

Free gas at the pump intake is the primary cause of ESP performance degradation and failure. When reservoir pressure drops below the bubble point, dissolved gas evolves from solution and enters the pump as a two-phase mixture. Understanding and managing gas is critical for reliable ESP operation.

Gas affects ESP performance in three ways:

1. Head degradation -- gas reduces the density of the pumped fluid, lowering the head generated per stage
2. Gas locking -- at high gas fractions, the pump loses its ability to generate head entirely
3. Surging and instability -- intermittent gas slugs cause fluctuating motor load and vibration

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Free Gas at Pump Intake

Gas Liberation

When the pump intake pressure ($P_{intake}$) falls below the bubble point pressure ($P_b$), gas comes out of solution. The amount of free gas depends on the difference between $P_b$ and $P_{intake}$.

Free Gas Volume

The free gas volume at pump intake conditions is calculated from the total produced gas minus the gas remaining in solution:

$$Q_{g,free} = Q_o \left( R_{sb} - R_s(P_{intake}) \right) \times \frac{B_g(P_{intake})}{1}$$

Where:

• $Q_o$ = oil production rate at stock-tank conditions (STB/d)
• $R_{sb}$ = solution GOR at bubble point (scf/STB)
• $R_s(P_{intake})$ = solution GOR at pump intake pressure (scf/STB)
• $B_g(P_{intake})$ = gas formation volume factor at intake conditions (bbl/scf)

The gas formation volume factor converts standard-condition gas volume to in-situ volume:

$$B_g = \frac{0.00504 \times Z \times T}{P_{intake}}$$

Where $T$ is in degrees Rankine and $P_{intake}$ is in psia.

Total Liquid Volume at Intake

The total liquid volume at pump intake conditions includes oil and water at in-situ conditions:

$$Q_{l,total} = Q_o \times B_o(P_{intake}) + Q_w \times B_w(P_{intake})$$

Where:

• $B_o$ = oil formation volume factor at intake pressure
• $Q_w$ = water production rate (STB/d)
• $B_w$ = water formation volume factor at intake pressure

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Void Fraction

Definition

The void fraction (also called gas volume fraction or in-situ gas-liquid ratio) is the fraction of the total fluid volume at pump intake that is occupied by free gas:

$$\lambda_g = \frac{Q_{g,free}}{Q_{g,free} + Q_{l,total}}$$

Where all volumes are at pump intake conditions (pressure and temperature).

Void Fraction Thresholds

The void fraction determines the severity of gas interference and the required mitigation:

Note: These thresholds are approximate and vary by pump type. Radial-flow stages tolerate less gas than mixed-flow stages.

Stage-Type Gas Tolerance

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Gas-Liquid Mixture Density

Mixture Density at Intake

The density of the gas-liquid mixture entering the pump determines the hydrostatic gradient above the pump and affects horsepower calculations:

$$\rho_{mix} = \rho_l (1 - \lambda_g) + \rho_g \lambda_g$$

Where:

• $\rho_l$ = liquid density at intake conditions (lb/ft^3)
• $\rho_g$ = gas density at intake conditions (lb/ft^3)
• $\lambda_g$ = void fraction (dimensionless)

The mixture specific gravity:

$$SG_{mix} = SG_l (1 - \lambda_g) + SG_g \lambda_g$$

Since $SG_g \ll SG_l$, the mixture SG is approximately:

$$SG_{mix} \approx SG_l (1 - \lambda_g)$$

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Gas Separator Efficiency

Purpose

A downhole gas separator (also called a gas handler or vortex separator) is installed below the pump intake to mechanically separate free gas from the liquid before it enters the pump stages. Separated gas is vented up the casing-tubing annulus.

Separator Efficiency Definition

$$\eta_{sep} = \frac{Q_{g,separated}}{Q_{g,free}}$$

Where:

• $\eta_{sep}$ = separator efficiency (dimensionless, 0 to 1)
• $Q_{g,separated}$ = gas volume removed by the separator
• $Q_{g,free}$ = total free gas volume at intake

Effective Void Fraction After Separation

After gas separation, the void fraction entering the pump is reduced:

$$\lambda_{g,eff} = \frac{Q_{g,free}(1 - \eta_{sep})}{Q_{g,free}(1 - \eta_{sep}) + Q_{l,total}}$$

Typical Separator Efficiencies

Factors Affecting Separator Efficiency

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Turpin Correction Factor

Background

Turpin et al. (1986) developed empirical factors to predict ESP performance degradation due to free gas. The Turpin factor estimates the reduction in pump efficiency and head as a function of void fraction and pump geometry.

Turpin Factor

The Turpin gas handling factor is a function of the intake gas volume fraction and the pump-specific geometry parameter:

$$F_{Turpin} = f(\lambda_g, \text{pump type})$$

The correction is applied as:

$$H_{corrected} = H_{water} \times F_{Turpin}$$$$\eta_{corrected} = \eta_{water} \times F_{Turpin}$$

Application

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Dunbar Correction Factor

Background

Dunbar (1989) extended the gas handling analysis with correction factors that account for additional parameters including intake pressure level, pump speed, and stage geometry. The Dunbar factor provides a more detailed correction for specific operating conditions.

Dunbar Factor

$$F_{Dunbar} = f(\lambda_g, P_{intake}, N, \text{stage geometry})$$

The Dunbar correction accounts for:

• Pressure level: Higher intake pressures reduce gas volume (compressibility), improving pump tolerance
• Rotational speed: Higher speeds improve gas-liquid mixing within stages
• Stage design: Mixed-flow stages handle gas better than radial-flow stages

Comparison of Correction Methods

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Gas Handling Recommendation Logic

Decision Framework

Mitigation Strategies

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Practical Considerations

Natural Gas Separation in Annulus

Before reaching the pump, some free gas naturally separates in the casing-tubing annulus due to buoyancy. The natural separation efficiency depends on:

• Annular velocity (lower is better for separation)
• Fluid viscosity (lower is better)
• Gas bubble size distribution
• Casing-tubing annular area

A rough estimate of natural separation efficiency:

$$\eta_{natural} \approx 1 - \frac{v_{mixture}}{v_{terminal}}$$

Where $v_{terminal}$ is the terminal rise velocity of gas bubbles in the liquid, estimated from Stokes' law or Harmathy's correlation.

Temperature Effects

Gas volume at intake is sensitive to temperature:

$$Q_{g} \propto \frac{Z \times T}{P}$$

Higher bottomhole temperatures increase the in-situ gas volume, worsening the void fraction. This must be accounted for in the gas handling calculations.

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Related Topics

• ESP System Design Overview -- Complete design workflow including gas analysis step
• ESP Pump Performance -- Head and efficiency curves affected by gas
• ESP Viscosity Corrections -- Combined viscosity and gas effects
• ESP Motor and Cable Sizing -- Motor sizing with gas-affected loads
• PVT Overview -- PVT correlations for Rs, Bo, Bg at intake conditions

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References

1. Turpin, J.L., Lea, J.F., and Bearden, J.L. (1986). "Gas-Liquid Flow Through Centrifugal Pumps -- Correlation of Data." Proceedings of the Third International Pump Symposium, Texas A&M University, pp. 13-20.

2. Dunbar, C.E. (1989). "Determination of Proper Type of Gas Separator." Microcomputer Applications in Artificial Lift Workshop, SPE Dallas Section.

3. Lea, J.F. and Bearden, J.L. (1982). "Effect of Gaseous Fluids on Submersible Pump Performance." Journal of Petroleum Technology, 34(12), pp. 2922-2930. SPE-9218-PA.

4. Takacs, G. (2009). Electrical Submersible Pumps Manual: Design, Operations, and Maintenance. Gulf Professional Publishing.

5. Romero, M. (1999). "An Evaluation of an Electric Submersible Pumping System for High GOR Wells." SPE-53991-MS, SPE Latin American and Caribbean Petroleum Engineering Conference, Caracas, Venezuela.