I have a question for my colleagues in the design field: what is the basis for setting the pressures of the primary and secondary oil, gas, and water separators at oilfield sites?

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I have this idea: the operating pressure of the secondary separator – where an external transfer pump is used to transport the liquid product from there – takes into account the saturated vapor pressure of the light hydrocarbons, primarily propane. The operating pressure of the secondary separator should be lower than the saturated vapor pressure of propane at its operating temperature, in order to allow for the removal of more propane; this will result in a more stable crude oil that can be stored directly after secondary separation. I’m not sure whether the pressure setting for the secondary separator takes this into consideration. Since there is a pump at the outlet of the secondary separator, it isn’t necessary for very high pressures there. I’d like to hear everyone’s views on the basis for setting the operating pressure of the separator. Another question is whether degassing mainly takes place in the primary separator – the vast majority of dissolved gas can be removed in the primary separator, with the secondary separator serving primarily a stabilizing function. Here, the operating pressure in the primary separator is 400 KPa, while it is designed to be 30 KPa in the secondary separator, but in practice it is 70 KPa. I would appreciate it if everyone could help answer this: I think that with the pressure rising from 400 to 70 or 30 KPa, not much methane can be removed; the main removal occurs of propane. I’m not sure if this reasoning is correct