Subsea flowlines are the subsea pipes used to connect a manifold to the surface facility in order to convey fluids to or from the host. They are arteries of the offshore production system, used to transport production, well testing, water injection, gas lift or gas injection. Their integrities play a central role in maintaining sustained production.
Subsea flowline materials and components
The flowlines may be made of flexible pipe or rigid pipe. Most of the subsea flowlines are made of rigid pipe, mainly out of carbon steel material with appropriate API grades, typically X65 (yield strength min 65 KSI). Some carbon steel flowlines have internal clad with corrosion-resistant alloy to prevent corrosion. Most flexible pipes are used in Brazil and they are mainly made of corrosion resistant alloy.
Flowlines may be single pipe, dual or in some cases multiple lines bundled inside a carrier pipe. For situations where pigging is required, flowlines are connected by crossover spools and valves configured to allow pigs to be circulated.
Subsea flowlines are increasingly being required to operate at high pressures and temperatures. The higher pressure condition results in the technical challenge of providing a higher material grade of pipe for high pressure, high-temperature (HP/HT) flowline projects, which will cause sour service if the product includes H2S and saltwater. In addition, the higher temperature operating condition will cause the challenges of corrosion, down-rated yield strength, and insulation coating. Flowlines subjected to HP/HT will create a high effective axial compressive force due to the high fluid temperature and internal pressure that rises when the flowline is restrained.
Key factors impacting subsea flowline design
One key function of the flowline is to be the conduit to carry production fluid from the wells to the platform. The flow capacity is dependent on the flowline diameter, fluid temperature/viscosity, pressure, and distance. This is typically done by thermal/hydraulic calculations using PIPESIM or OLGA. The flowline design needs to meet the expected production forecast.
Single or dual
Besides improved production capacity, dual flowlines are sometimes used to provide production flexibilities or manage flow assurance risks. Dual flowlines can also facilitate flowline pigging and cleaning. However, dual flowline configuration typically requires much more upfront capital cost than single flowline.
Seafloor geological features or hazards and locations of subsea structures determine the flowline pathway.
Flowline wall thickness needs to be able to withstand the max internal pressure after taking into consideration of the corrosion allowance.
Depending on the corrosion environment, the flowline internal may need to be cladded with corrosion resistant alloys if corrosion inhibitor alone cannot protect internal corrosion.
The longer the design life, the more corrosion allowance the flowline needs to have.
The subsea flowlines may need to be insulated to avoid flow assurance problems associated with the cooling of the produced fluid as it travels along the seabed. Heat retention can also be accomplished by burying the flowline. It should be noted that most subsea wells cannot economically retain sufficient heat during flowing conditions to stay out of the hydrate risk region. Therefore, subsea gas flowlines are usually not designed for heat retention and the hydrate risk is typically managed via hydrate inhibitors (low dosage hydrate inhibitor or thermodynamic hydrate inhibitor.
Sour service is required if H2S level is high enough to exceed 0.05psi partial pressure per NACE requirement.