Flow assurance

In the oil and gas industry, flow assurance refers to ensuring successful and economical flow of a hydrocarbon stream from reservoir to the point of sale. The term was coined by Petrobras in the early 1990s ahead of a DeepStar Program meeting, in Portuguese as Garantia do Escoamento (pt:Garantia do Escoamento), meaning literally "guarantee of flow", or flow assurance.

Flow assurance is extremely diverse, encompassing many discrete and specialized subjects and bridging across the full gamut of engineering disciplines. Besides network modeling and transient multiphase simulation, flow assurance involves effectively handling many solid deposits, such as, gas hydrates, asphaltene, wax, scale, and naphthenates. Flow assurance is the most critical task during deep water energy production because of the high pressures and low temperature (~4 degree Celsius) involved. The financial loss from production interruption or asset damage due to flow assurance mishap can be astronomical. What compounds the flow assurance task even further is that these solid deposits can interact with each other, and can cause catastrophic blockage formation in pipelines and result in flow assurance failure.

Flow assurance includes thermal investigation of pipelines, making sure the temperature is above the hydrate's formation temperature. Other important aspects of flow assurance are the estimation of stable production limits, and evaluation of erosion due to sand and corrosion in pipelines and equipment.

Hydrate Management Solutions

Gas hydrates are commonly managed through a combination of operational, thermal, and chemical methods. The selection of an appropriate hydrate mitigation strategy depends on factors such as reservoir conditions, water production rates, operating pressure and temperature, tieback distance, and economic considerations. In many offshore developments, chemical inhibition is the primary method used to prevent hydrate formation within production systems.

Thermodynamic Inhibitors

Thermodynamic hydrate inhibitors (THIs)

THIs reduce the temperature at which hydrates can form, thereby shifting hydrate equilibrium conditions outside the operating envelope of the production system. The most widely used THIs are methanol and monoethylene glycol (MEG).

Methanol

Methanol is typically injected into production streams during normal operations or transient events such as start-up and shut-down. It is effective at preventing hydrate formation but is generally not recovered after use, resulting in higher operating costs and logistics requirements. Methanol is often favoured for temporary or intermittent inhibition applications.

Monoethylene glycol (MEG)

MEG is commonly used in offshore developments where continuous hydrate control is required. Unlike methanol, MEG can be recovered, regenerated, and reinjected through dedicated reclamation systems, making it economically attractive for long-distance subsea tiebacks and fields with long production lifetimes. MEG systems require significant capital investment but can reduce long-term chemical consumption. Normally this requires detailed modelling via flow assurance studies or modelling softwares such as PVTSim, OLGA, Multiflash and others.

Low-Dosage Hydrate Inhibitors

Low-dosage hydrate inhibitors (LDHIs) are chemicals designed to prevent hydrate-related flow assurance problems at significantly lower concentrations than thermodynamic inhibitors. LDHIs are generally classified into two categories: kinetic hydrate inhibitors (KHIs) and anti-agglomerants (AAs).

Kinetic hydrate inhibitors (KHIs)

Kinetic hydrate inhibitors (KHIs) delay the nucleation and growth of hydrate crystals, allowing production fluids to remain hydrate-free for a specified residence time. KHIs are most effective in systems with moderate subcooling and relatively low water cuts.

Anti-agglomerants (AAs)

Anti-agglomerants (AAs), sometimes grouped within the broader LDHI category, allow hydrate particles to form while preventing them from clustering into larger masses that could block pipelines. These chemicals are typically applied in hydrocarbon-rich systems where dispersed hydrate particles can be transported safely with the fluid stream. The suitability of KHIs, anti-agglomerants, MEG, or methanol is highly dependent on field-specific operating conditions. Factors such as water production, fluid composition, operating temperatures and pressures, production interruptions, and subsea infrastructure design are typically evaluated when selecting a hydrate management strategy. Often, a combination of methods is employed to provide reliable flow assurance throughout the life of a field.