Table of Contents
Importance of Component Partitioning Between Phases
(C) Brine (Aqueous) Phase Partitioning
Why Hydrocarbon Streams Must Be Saturated with Water
H₂O Saturation in OLI Studio: ScaleChem
An Important Note of Caution on the First Approach: Effect of Salinity on Vapor Pressure
Objective
When oil, gas, and brine are in equilibrium at a specific temperature and pressure, components distribute among the different phases according to their respective partition coefficients. This partitioning behavior is fundamental to various petroleum system processes, including reservoir engineering, production chemistry, and phase behavior modeling.
Properly accounting for the water solubility in the gas and oil phases is essential for maintaining a correct mass balance and avoiding errors that could lead to operational issues. Failure to consider this can cause incorrect brine compositions, increasing the risk of scale formation and corrosion.
Importance of Component Partitioning Between Phases
The partitioning of components between oil, gas, and brine is controlled by thermodynamic principles, influenced by:
- Temperature
- Pressure
- Salinity of the aqueous phase
- Hydrocarbon composition and phase interactions
A key consideration in this partitioning is the solubility of water in gas and oil phases, which impacts:
- Gas–water and oil–water equilibrium in reservoirs
- Formation of hydrates and emulsions
- Inorganic scale precipitation
- Corrosion in pipelines and processing equipment
- Gas-to-oil ratio (GOR) and production efficiency
Partitioning occurs due to the minimization of chemical potential and phase equilibrium constraints. Each phase has a distinct behavior:
(A) Gas Phase Partitioning
- Light hydrocarbons (C₁–C₄) dominate in the gas phase.
- Water vapor is always present in natural gas due to its vapor pressure, with solubility varying based on pressure and temperature.
- Heavier hydrocarbons (C₅+) have very low volatility and do not significantly partition into the gas phase.
- Brine salts (NaCl, KCl, CaCl₂) are virtually insoluble in the gas phase.
(B) Oil Phase Partitioning
- Oil is a complex mixture of hydrocarbons (C₅–C₆₀+), asphaltenes, resins, and waxes.
- Water solubility in oil is generally low but increases with temperature and oil composition (especially when polar compounds such as acids or bases are present).
- Brine components (salts) are insoluble in oil, though some polar organic compounds (e.g., carboxylates) may partially dissolve.
(C) Brine (Aqueous) Phase Partitioning
- Water is the dominant phase, dissolving salts and some hydrocarbons (especially lighter gases like methane and CO₂).
- CO₂ and H₂S are highly soluble in water due to their polarity and ability to react with water to form weak acids.
- Oil components generally exhibit very low solubility in brine, with the exception of certain polar fractions.
Why Hydrocarbon Streams Must Be Saturated with Water
In hydrocarbon processing, compositional data for gas, oil, and total hydrocarbon PVT properties are typically provided as "dry compositions," meaning that they do not account for the water dissolved in these phases.
The Issue: Mass Balance Errors
- If dry compositions are used as input without adding the correct amount of dissolved water, the system's overall mass balance will be water-deficient.
- When the system is equilibrated at a given temperature and pressure, water will automatically shift from the brine phase to the gas and oil phases to reach equilibrium.
- This results in an artificial increase in the ion concentration in the brine, which can have serious operational consequences.
Operational Risks Due to Incorrect Mass Balances
-
Increased Inorganic Scale Precipitation
- As brine loses water, the ionic strength increases, pushing the system toward supersaturation for common scale-forming salts such as:
- Calcium carbonate (CaCO₃)
- Barium sulfate (BaSO₄)
- Strontium sulfate (SrSO₄)
- This leads to higher scale formation risks, which can clog pipelines, block production equipment, and reduce flow efficiency.
- As brine loses water, the ionic strength increases, pushing the system toward supersaturation for common scale-forming salts such as:
-
Enhanced Corrosion Risks
- A more concentrated brine can accelerate corrosion mechanisms, particularly in the presence of dissolved CO₂ and H₂S, which form acidic solutions.
- Localized corrosion (pitting, crevice corrosion) is more likely under these conditions.
-
Altered Phase Behavior and Incorrect Predictions
- Reservoir and PVT simulations rely on accurate phase behavior predictions.
- If water solubility is ignored, phase equilibrium calculations will be incorrect, leading to inaccurate gas-to-oil ratios (GORs) and phase distribution predictions.
To avoid these issues, it is necessary to adjust hydrocarbon compositions by saturating the gas and oil phases with the appropriate amount of dissolved water. This ensures:
- A correct total mass balance in the system.
- Proper partitioning behavior of ions and gases.
- More accurate predictions of phase behavior in reservoirs and pipelines.
H₂O Saturation in OLI Studio: ScaleChem
In OLI Studio: ScaleChem, there are two methods to account for water partitioning in the gas and oil phases.
First Approach
The first and most straightforward approach is to use the automatic saturation feature available in the "Reconcile" tab. To do this, select "H₂O" in the "Saturate with" option.
If this option is not visible, you can enable it by navigating to:
Tools → Options → General → Enable saturation option for oil and gas analysis.
For practical application, you can refer to the attached example file:
Water_Saturation_Example_Automatic_Saturation.oad
This file allows you to experiment with the automatic saturation feature by toggling it on and off, observing how it impacts brine volumes and scale risk calculations. This hands-on approach helps in understanding the influence of water saturation on scaling tendencies and system behavior.
Second Approach
The second approach to accounting for water partitioning in OLI Studio: ScaleChem involves creating a pure water stream by adding a brine that contains no ions. This pure water, often referred to as "makeup water," is introduced during the saturation stage to ensure that the hydrocarbon phases reach equilibrium without altering the total volume of free water.
The volume of makeup water added is carefully calibrated to fully saturate the gas and oil phases while maintaining the correct brine volume balance. This ensures that the final free brine volume at equilibrium matches the measured brine volume under the given temperature and pressure conditions, preventing artificial increases or decreases in the system's water content.
For practical application, you can refer to the associated example file:
Water_Saturation_Example_Makeup_Water.oad
In this example, during the "Saturate" step, a total of 10 m³ of brine (measured at 15°C and 1 atm) is introduced along with 7.3 m³/day of makeup water. This volume is precisely calculated to saturate the gas and oil phases while maintaining the expected free water volume of 10 m³/day at standard conditions (15°C and 1 atm).
This method ensures accurate mass balance and prevents errors that could lead to incorrect scale risk predictions or brine volume estimations.
An Important Note of Caution on the First Approach: Effect of Salinity on Vapor Pressure
Water saturation in the gas and oil phases is directly influenced by the salinity of the aqueous phase due to changes in water vapor pressure. The fundamental principle behind this relationship is Raoult’s Law and the salting-out effect, which govern how dissolved salts reduce water's tendency to partition into the hydrocarbon phase.
Vapor pressure is the pressure exerted by a vapor in equilibrium with its liquid phase. Pure water has a higher vapor pressure than saline water because dissolved salts lower the activity of water molecules, reducing the number of molecules available to escape into the vapor phase. This is described by Raoult’s Law:
Psolution = xwater × Ppure water
Where:
- Psolution = Vapor pressure of water in the saline solution
- xwater = Mole fraction of water in the solution
- Ppure water = Vapor pressure of pure water
As salinity increases, xwater decreases, lowering the vapor pressure of water. This means less water is available to transfer into the gas and oil phases.
In OLI Studio: ScaleChem, the salting-out effect is fully accounted for in phase equilibrium calculations. This ensures that water partitioning between phases correctly reflects the impact of salinity on water vapor pressure.
However, a key limitation arises when using the automatic saturation option for gas and oil. This option calculates water saturation in the hydrocarbon phases assuming pure water, without considering the reduction in water solubility due to dissolved salts (salting-out effect). As a result, when working with high-salinity brines, the automatically calculated water saturation values in the gas and oil phases may be overestimated compared to the true equilibrium values.
To assess whether this overestimation is significant, it is recommended to compare the automatically calculated water saturation values with the recalculated values after all fluids have been recombined and the system has been equilibrated at the given temperature and pressure conditions. Since the salting-out effect is correctly applied in the final equilibrium calculations, any discrepancies in initial water saturation values will be adjusted when the system reaches its true phase equilibrium.
Using the second approach (adding makeup water) ensures that hydrocarbon phases are saturated with water in a way that correctly accounts for salinity effects from the outset, eliminating any discrepancies. However, in low- to moderate-salinity brines, the impact of this effect is minor and does not significantly influence scaling or corrosion risk assessments. It becomes most relevant in high-salinity environments, where ignoring the salting-out effect in preliminary saturation calculations could lead to incorrect predictions of phase behavior and water distribution.