An explosion where the flame front travels at supersonic speeds as a shock wave. Explosions of this nature are often triggered by a high-power explosive device. Typically, detonation explosions are significantly more damaging than deflagration explosions.
Term used by NFPA and DOT to classify certain liquids that will burn, on the basis of flash points. NFPA and DOT generally define “combustible liquids” as having a flash point of 37.8°c or higher. They do not ignite as easily as flammable liquids; however, they can be ignited under certain conditions, and must be handled with caution.
The maximum allowable human exposure limit for an airborne substance which is not to be exceeded even momentarily.
The maximum concentration of vapor that could be attained in the air in a closed space above a liquid at ambient temperature and pressure. If a chemical has a high ambient saturation concentration, it has a strong ability to displace air, and the concentration of the chemical’s vapor in the air above the liquid will be high. If it has a low ambient saturation concentration, the vapor concentration will be low.
This property changes with temperature—a liquid at a higher temperature will have a higher ambient saturation concentration. A chemical that is a gas at ambient temperature and pressure has an ambient saturation concentration of 100% (1,000,000 ppm).
Without water. A chemical shipped or stored without water, rather
than in solution, is in anhydrous form (anhydrous ammonia is a common example)
The number of times per unit time that the volume of air within a
building is completely replaced by new outdoor air when doors and windows are closed. Usually expressed as number of air changes per hour
A computer model that predicts the movement and dispersion of a gas in the atmosphere.
The pipeline system has been divided into two sections for ease of reference. The section between the wellheads and the Pressure Reduction Platform are referred to as flowlines and the section between the Pressure Reduction Platform and the Onshore Plant as pipelines.
Such as = 3 x 16” 120 km flowlines
Hydrates are a physical combination of water and other small molecules that form a solid material with an ice-like appearance but significantly different in structure and properties than ice.
The hydrate inhibition solution must ensure that hydrates do not form
The combined flow of oil and gas in a pipeline presents many design and operational difficulties not present in single phase liquid or vapour flow. Frictional pressure drops are harder to estimate.
Liquid is likely to gather at low points in the pipeline and reduce the pipeline capacity to a point when slugs of liquid are pushed ahead by the gas.
The movement of large liquid slugs along the pipeline can cause additional pipeline stresses and the pipeline terminal facilities must be designed to receive such volumes of liquid by provision of large, specially designed vessels or energy absorbing pipework, known as slug-catchers.
The type of flow in a pipe is known as its flow regime.
Pipelines are seldom horizontal, as they have to follow the undulations of the seabed or the countryside, and often have vertical sections as they rise to join platforms or enter process streams.
In view of this, there can be complex flows regimes
The key difference between single-phase flow and two-phase flow is that it is much more difficult to determine pressure drops for two-phase flow. This is complicated if you consider that a difference in incline of several degrees, never mind 90º; can change entirely the nature of the flow regime.
Undulating terrain will generally not be a problem for single-phase pipelines; however, it can materially affect pressure drop in two-phase pipelines if there are a large number of. rises and falls, which the pipeline must cross.
Some two-phase regimes are caused by liquid condensation or fall-out from the gas due to reducing temperature and pressure along the length of the pipeline. For onshore gas lines liquid knock-outs can be provided at intervals such that liquids can be drained off by blow-down of the line.
Well flow lines often work in a two-phase regime, particularly because the well fluids usually contain both oil and gas and there may be no facility at the wellhead (E.g. at sub-sea wells) prior to the fluid reaching the gathering station (or platform).
Despite the problems associated with the prediction of two-phase estimates, more and more pipelines are being designed for such flow systems. For example when hydrocarbon condensate is separated from the gas at offshore platforms, it is invariably spiked back into the gas for transport to the shore in the pipeline. This is mainly because the economics would not support a separate line for condensate sales.
