[Adelaidewonderer]

Does anyone know about the quality of oil (energy content) that is coming out of oil fields as they are depleted. Take ghawar for example, is the oil that is coming up now, as good as the oil that was coming up in the 1960's?? I understand the watercut is becoming greater as the field ages (due to extraction process), but just what of the actual oil???

[rockdoc123]

This is not always a simple answer as all oil fields are different. And in Saudi Arabia that is especially so. Some fields have oil that is completely saturated (high gas content in solution at reservoir T&P) others are undersaturated (low gas content), others have free gas caps at reservoir conditions, others form gas caps immediately upon production as they are at or near the bubble point. Some reservoirs are the same gravity of crude from top to bottom (either all heavy, all medium or all light) while others have a gravity gradient (either heavy at the top and lighter at the bottom due to biodegradation or lighter at the top and heavier at the bottom due to fresh water washing). Some heavy oils are like molasses ( high viscosity), other oils with the same API can have quite low viscosities ( eg. the API of Cold Lake crudes is very similar to that of some of the Llanos basin crudes in Colombia but Cold Lake crudes have viscosities around 2000 cp or higher and require steam to get them to move whereas Colombian heavy crudes can have viscosities as low as 60 cp and flow on their own power). Some crudes have high wax content and need to be kept at a certain temperature to avoid solidification, others have high extra species content such as sulphur or vanadium and require treatment. With regards to water, again it isn't always the same story. In Ghawar, as an example the water gradually encroaches as a bottom drive due to the excellent vertical and lateral permeabilities but it is also problematic as water cones prematurely along fractures (the reason Aramco went to the MRC wells). And how much water is produced at any time in a fields history has to do with relative mobility ratios and wettability. This can be complex as you might have a reservoir with low water saturation and strong water drive that produce at high water cut right from the start (the Cretaceous sand reservoirs in East Africa work like this) whereas it is also possible to have reservoirs with extremely high water saturation which are oil wet rather than water wet in which case you produce almost no water at all.
And generally speaking water production is not a problem other than cost as you just have to keep disposing of ever increasing amounts of water through your separators and back into injection wells or percolation pits.
For these reasons there is no simple answer....some reservoirs can get more difficult to produce at high quality with time if the intial production practices are poor (eg. Turner Valley in Alberta where they blew off the gas cap and essentially depressured the oil leg resulting in poor recoveries, another one might be the Occidental pools in Peru where they went after the low hanging fruit first (the lighter oil) and left the heavier and more viscous oil to the last. But your mileage may vary. This is precisely why good reservoir engineers are worth their weight in gold and also why through time recovery factors in pools increase (eg. Ain Dur in the northern reaches of Ghawar where the assumed recovery factor increased from 35% to what will likely be 73%).

answer seems complex but so is the subject matter.

[papa moose]

answer seems complex but so is the subject matter.

I think i can paraphrase...
"Sometimes it gets better, sometimes it gets worse, sometimes it stays the same."

[sparky]

.
There has been a trend to use the sweet light grades first ,refineries love them
the heavy and sour crudes are far from satisfying they require greater cost to process
there is a clear trend toward the rubbish oil , the good stuff is expensive now