Pipeline Design and Hydraulics

Categories

• Flowlines — wellhead to manifold or facility, often multiphase.
• Gathering lines — collecting from several wells or pads.
• Trunk and transmission lines — long distance, high pressure, single phase.
• Distribution — to end users at lower pressure.
• Subsea flowlines and risers, with their own design and installation disciplines.

Hydraulics

The pressure available must overcome friction along the line and any elevation change. Friction rises steeply with velocity — roughly with its square — and falls steeply with diameter, so a modest increase in diameter reduces pressure drop dramatically. This is why line sizing is fundamentally an economic optimisation: a larger pipe costs more capital and less energy, and the optimum depends on throughput, distance, power cost and the expected profile over life.

Design velocity matters in both directions. Too high causes erosion, noise, vibration and excessive pressure loss; too low allows water to accumulate at low points, causing corrosion, and allows solids to settle.

Multiphase flow

Flowlines carrying gas and liquid together behave in ways single-phase intuition does not predict. The flow regime — stratified, slug, annular, bubble or mist — depends on the gas and liquid rates, the pipe diameter and the inclination, and it determines pressure drop, liquid holdup and the stability of delivery.

Slug flow is the practical concern. Liquid accumulates in low points and is periodically swept out as a slug, arriving at the facility as a surge that upsets separation and can overwhelm level control. In risers, severe slugging can produce very large slugs with long cycle times. Mitigation includes slug catchers sized for the predicted slug volume, topsides choking, active control, and line routing that avoids unnecessary undulation.

Wall thickness and materials

Wall thickness is set by design pressure, diameter, material grade and a design factor that varies with location class — a line through a populated area is designed more conservatively than one through open country. A corrosion allowance is added, and for offshore lines, collapse under external pressure during installation and operation frequently governs rather than internal pressure.

Carbon steel of an appropriate grade is standard, with sour service requirements where hydrogen sulphide is present. Internal corrosion is managed by dehydration, inhibitor injection, internal coating or corrosion-resistant alloy or cladding where the economics justify it.

External protection

Buried and subsea lines are protected by an external coating as the primary barrier and by cathodic protection as the secondary — sacrificial anodes or an impressed current system providing protection wherever the coating is damaged. The two work together: coating does most of the work, and cathodic protection covers the defects. Monitoring cathodic protection potentials along the route is a routine integrity activity, and a section that has lost protection is a section that is corroding.

Pumping and compression

Liquid lines use pump stations spaced along the route; gas lines use compressor stations. Station spacing is another capital-versus-energy optimisation, and stations are also the natural points for metering, pigging, isolation and monitoring.