Ashley was talking about condensates and here's wh

Ashley was talking about condensates and here's what he's talking about explained by a practicing petroleum reservoir engineer,

Fundamentally, the distinction between "oil" and "condensate" is artificial and arbitrary. Both are the liquid hydrocarbon phases resulting from "flashing" reservoir hydrocarbon fluids to surface pressure and temperature. That's the function of various "separator" vessels through which wellstream production is processed. Those "standard" (AKA "stocktank") conditions depend on contracts and local regulations, but for laymen it's enough to consider that 1 atmosphere pressure and "room" temperature (e.g. in OK & TX it's 14.65 psia/60F, in LA it's 15.025 psia/60F, some places it's 1 atm [14.696 psia] and 25C, yada yada...).

For common use,   They're both "crude" in the sense that their compositions are whatever came from the well with no processing other than simple separation -- which is what that means in the term "crude oil". If the hydrocarbons in the reservoir were in the liquid phase, we tend to use the label "oil" for both that reservoir liquid and the liquid that remains after "dissolved gas" is liberated when pressure is reduced by production and separation. If the reservoir hydrocarbons were vapor, we tend to use the label "condensate" for liquids condensed when temperature and/or pressure are reduced (especially the latter). If (as very commonly happens) the reservoir contains both phases, we use whichever label suits us at the moment, usually leaning toward the primary phase that flows into the well (or did when production began).

Petroleum (oil and gas and condensate) fluids are mixtures of many, many different hydrocarbons. Reservoir fluids are different from reservoir to reservoir (and even within the same reservoir -- variations across reservoir compartments and compositional gradients are not uncommon), running the full spectrum from nearly solid tars (e.g. Athabasca in Canada), to heavy "dead" oils with very little light components (e.g. the heavy oils in the Midway-Sunset field of central California), to medium oils with varying amounts of "dissolved gas" (a useful but philosophically imprecise concept) (e.g. many Gulf Coast oils), to the nice stuff that's generally the pricing standard (e.g. most midcontinent crudes and the once-benchmark West Texas Intermediate), to volatile oils
that "shrink" dramatically when they liberate gas as pressure is reduced, to rich "retrograde" gas condensate fluids that condense much liquid as pressure is reduced (hence the retrograde moniker), to leaner gas fluids that yield condensate only as they're cooled (many gas fields), to dry gases all the way to nearly pure methane (e.g. the Arkoma basin).

Some folks (e.g. the link below) use five classifications for petroleum reservoir fluids: "black oil", "volatile oil", "retrograde gas-condensate", "wet gas", and "dry gas". The distinctions are useful, but the boundaries are hardly distinct. The term "black oil" is particularly imprecise and context-dependent; to a reservoir simulation engineer like me, that means the simplifying assumption that the fluid can be characterized by only two components, one of which can exist in only one phase whose properties we can characterize the other component dissolves in that phase; that phase is "black" as in box, not color. Usually the non-partitioning phase is the "heavy" component (separator oil may contain dissolved gas, but the gas phase contains no oil), but it works the other way, too (separator gas can contain condensate vapor, but condensate can dissolve no gas). When it's applicable, the black-oil assumption saves *lots* of computational effort.

Labeling hydrocarbons as "oil" or "condensate" is pretty arbitrary. Even the "oil" vs "gas" distinction is only relevant at conditions where both could coexist together. Many reservoirs are at temperatures and pressures where only a single phase can exist, and there are quite a few for which the temperature is so close to the critical temperature of the mixture that it's not at all obvious whether reducing the pressure will evolve bubbles of vapor or droplets of liquid (those can be pretty tricky to produce efficiently). There are some for which the temperature, pressure, and/or composition variation with depth give them fluids which are "gas" in top (because they condense liquid on depressurization), "oil" in the bottom (because the evolve vapor on depressurization), with no gas-oil contact in between.

"Condensates" tend toward the lighter end of the spectrum, "crudes" to the heavier. Since most hydrocarbon liquids are pretty close to (CH₂)_n formula, the "energy" (heating value) content per pound is fairly constant (to a decent first approximation, about 17000 BTU/lb IIRC; for reference a thousand cubic feet of lean natural gas delivered for home uses yields about 1 million BTUs [and weighs about 46 pounds {yes, that's 22000 BTU/lb, but it's mostly CH₄). That is, a barrel of 50 API (a density measure) condensate from Hugoton has less energy than a barrel of 12 API crude from Midway-Sunset (API gravity is lower when density is higher).

"Condensates" tend to be lighter in color, too, all the way to water-clear and often to straw-yellow or light green, though some are deep black. "Oils" run a broad range of colors from deep black to light straw, with varying tints of green, brown, red, and even blue.

As to price, the "sweet spot" is somewhere in the middle of the range (the price you hear on the news is for either "light sweet crude" or "West Texas Intermediate". Lighter crudes (& condensates) are easier to process for many products (gasoline, gas, petrochemicals) but have less total energy content.