As discussed in other blog posts, flow assurance refers to the successful and economical flow of petroleum fluids from the reservoir to the surface facilities. The goal of fluid modeling strategies is to ensure a smooth and uninterrupted transportation of produced fluids through the production system, especially in offshore environments.

Along this path, pressure and temperature conditions can vary a lot, and the mixture of water, hydrocarbons, and solids,can generate an environment in which many flow assurance issues can occur, such as [1]:

• Asphaltene deposition
• Wax deposition
• Formation of hydrates
• Corrosion and erosion
• Emulsions
• Slugging

Fluid Behavior for Flow Assurance Issues

In addition to environmental conditions, flow obstacles can depend on  the type of fluid and the fluid composition. In addition, the phase equilibrium that the fluid experiences due to changes in pressure and temperature from the reservoir to the outlet pipeline can determine whether flow challenges will appear. To illustrate this point, the fluid behavior that causes some of these flow assurance problems will be described later.

Asphaltenes

Asphaltenes are high molecular weight, aromatic, organic substances that are soluble in aromatic solvents (e.g., toluene, diesel), but are precipitated by the addition of molecular-weight alkenes (e.g., n-heptane/n-pentane). The asphaltene solubility is highly dependent on the fluid composition and temperature, but it is less dependent on the pressure. Furthermore, its solubility is higher for heavier and more aromatic oils [1]. Figure below shows an example of asphaltene solubility according to pressure and temperature conditions.

Waxes

Waxes are typically long-chain, normal alkane compounds that are naturally present in crude oil [3]. The formation of wax crystals depends significantly on temperature change; that is, if the temperature of the system is lower than the Wax Appearance Temperature (WAT), waxes will emerge. Pressure and composition also affect wax formation, but not as much as  temperature does. This relationship between pressure, temperature, and the wax formation is illustrated in Figure 2 below. In general, the wax fraction can be characterized by its melting point temperature, its molecular weight, or the corresponding chain length [1].

Gas hydrates

Gas hydrates are solutions of gases in crystalline solids called clathrates. Molecules of hydrate-forming gases (primarily methane, ethane, propane, carbon dioxide, and hydrogen sulfide) occupy the void spaces (cages) in the water-crystal lattice. Hydrates can form at temperatures considerably higher than the freezing point of pure water [2]. An example of a hydrate formation curve is presented in the figure below.

Steps for Fluid Modeling

With this, the thermodynamic and hydrodynamic characteristics in a flowline system and the risk of hydrocarbon-solid formation and deposit are defined, in general, through the following steps: 

1. Fluid sampling 
2. Characterization of fluid composition
3. Simulation of the phase equilibrium in order to screen for hydrocarbon solids
4. Experimental measurements on asphaltenes, waxes, and hydrates
5. Multiphase flow simulation in order to determine if the conditions for the appearance of flow assurance issues may happen
6. Application of control operations, such as pigging and injection of inhibitors

In upcoming blog posts, we’ll explore in more detail how simulation tools can help O&G professionals through these steps by accurately creating a fluid modeling and helping to identify and mitigate recurring flow assurance issues. Stay tuned!

References: 

[1] Whitson, Curtis H., and Michael R. Brulé. Phase behavior. Vol. 20. Richardson, TX: Henry L. Doherty Memorial Fund of AIME, Society of Petroleum Engineers, 2000.

[2] Ahmed, Tarek. Equations of state and PVT analysis. Elsevier, 2007.

[3] Bai, Yong, and Qiang Bai. Subsea engineering handbook. Gulf Professional Publishing, 2018.

[4] McAleese, Stuart. Operational aspects of oil and gas well testing. Elsevier, 2000.