Do not forget that untreated natural gas always contains water vapour and that it is in 99 out of 100 cases not reported as a percentage. Water in gas is particularly important in low pressure gas (p< 4 bar) separated from hot crude oil (T> 40 C).

As a rule of thumb one can say that there is 1 1/2 times as much normal butane as iso-butane in natural gas. If not, watch out!

Designers of (downstream) facilities must not forget that PEOPLE add to virgin gas and crude oil, occasionally or on a permanent basis, such matters as : methanol, glycol, corrosion-inhibitor, mud, rust, sand, welding rods, welding beads, 2x4s, helmets, water, mercury, lubricating oil, and occasionally a welder, etc and that this is not normally reported nor shows up in reported compositions unless it was specifically asked for. It causes valves to scour, compressors to get damaged, mole-sieve material to poison, filters to block and glycol and other liquids to foam.

Be critical when a gas composition does not show any H2S. Always check whether it was measured as zero or not measured at all and simply not reported. Small quantities of H2S (in the parts per million mass range) in gas produced during well-tests may not be noticed for some time as H2S may react with the steel it sees before it reaches the sample point.

The difference between a gas that has been separated from crude oil (associated gas) and reservoir fluid from a condensate reservoir is very easy identifiable. The associated gas has decreasing quantities of hydrocarbons. In other words: mol % C1>C2>C3>C4>C5>C6>C7>C8>C9. With condensate reservoir fluid there is practically always a declining mol % till say C5 but thereafter the mol % goes up to go down again thereafter. In graph form see below:

The significance of this observation is that when a reservoir fluid composition of a condensate reservoir fluid is presented without that increase in the heavier components that then most probably the composition of the first stage separator gas rather than the reservoir fluid is given.