Crude oil vs Condensate

[Ginarley]

Hi all

A random question, but can anyone inform me of the differences between condensate and crude oil in terms of energy content and oil product refining?

So far as I understand (and this may well be wrong) crude is direct from the ground whereas condensate is a byproduct of natural gas extraction? I think condensate is "lighter" (whatever that means) than crude?

I also note that energy data publications (well NZ ones anyway) seem to lump the two together suggesting they aren't too different.

Cheers
Ian

[DavidS]

As a practicing petroleum reservoir engineer, I'll offer the following that's probably more than you wanted to read:

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, your assessment is pretty close. 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.

This link probably bears more than you care to read about the matter, but it does have some phase diagrams that might help understand the spectrum.

[DavidS]

I'm in the "upstream" (exploration & production) end of the businesss so I'm less of an authority on refining processing, but this might help:

Light condensates tend toward short-chain alkane hydrocarbons (C5-C9), often more "normal" straight chain than branched isomers. Some are pretty close to low "octane" gasoline, a term that is sometimes applied. They're easier to separate (and clean up impurities like sulfur or metals) for many petrochemical uses or for lightening mixtures of heavier hydrocarbons, but their heating value is lower. Refineries can use them as feedstock to generate more branched hydrocarbons to raise the octane rating of gasoline, or to produce alkene (sp2 double-bonds in the chains) hydrocarbons for polymerization, etc.

Heavier oils will have more of the (surprise) heavier C12+ hydrocarbons, maybe more aromatics (benzene rings), probably more alkenes and branched isomers, and asphaltenes. Their lighter components can be distilled for use as above, the heavier components can be used directly in other products or "cracked" into shorter hydrocarbons.

Really heavy crudes can be more difficult to refine. They're more likely to be contaminated with sulfur and heavy metals that can poison refinery catalysts, they're harder to pump around the refinery, they can leave more fouling on the process equipment, and they need more processing (cracking, reforming, alkylation, other magic refinery foo somebody might be able to describe) to produce the nice light fuels we all love (gasoline, diesel, jet fuel) -- and pay handsomely for -- instead of the heavy -- and low-priced -- industrial gunk useful only for big thirsty customers (powerplants, ships, industrial furnaces) or road asphalt.

[Ginarley]

Thank you so much DavidS, a wonderfully detailed answer and very much appreciated - its rare to get one's obscure question so clearly and thoroughly answered

Cheers
Ian

[Schneibster]

Excellent answers, DavidS. Very informative. Thanks very much!

[DavidS]

What, no antiverbosity flames? Donning this asbestos before checking back was wasted effort? No matter; it's about as flattering to my form as anything can be (there's not a whole lot of upside potential there).

I did neglect to mention one tidbit about processing (not refining) that might be interesting...

Because petroleum fluids are multicomponent mixtures, exactly how they're brought to surface conditions can make quite a difference in how much "oil" or "condensate" or "gas" comes from a given quantity of reservoir fluid.

At the "ends" of the fluid spectrum it doesn't matter much.

For "dry" gas (which yields no condensate), of course, no hydrocarbon separation is needed (though separators or dehydrators are always used to get rid of any produced -- or condensed -- water in the stream).

For "dead" oils (with little dissolved gas) and lean "wet" gases (which condense condensate ony on cooling, not just depressurization), it doesn't matter much; "flashing" the fluid to surface conditions in one big step or many little ones ends up with about the same ratio and compositions of gas and oil.


For common intermediate oils it's usually enough to find a pressure at which a single stage of separation will yield fluids that (when finally flashed again in the stock tank) will give the greatest yield of the more valuable product. Usually separation is designed to maximize stocktank oil yield, but nowadays the gas-oil price differential is thinner than it was when gas was so cheap it was almost a waste product. Ratios vary, of course, but a common value might be that 1.5 barrels of reservoir fluid can be separated at, say, 200 psi to yield 1.0 barrel of stocktank oil and, say, 800 standard cubic feet of separator gas, or at 150 psi to yield 0.95 BBL and 820 SCF.

For volatile oils and rich retrograde condensate fluids, however, the number and conditions of separation stages can make a big difference in how much hydrocarbon comes out as stocktank liquid (oil/condensate) or vapor. Really interesting cases can benefit from separator networks that recycle part of their vapor (or liquid) back to an earlier (or forward to a later) stage of separation to better distribute the heavier components to the stocktank liquid and light components to the final vapor stream. In such cases the whole condensate-oil distinction is almost meaningless.

Where it gets *really* interesting is when multiple parties own different interest in reservoir "oil" (and the gas evolved from it) and "gas" (and the condensate precipitated from it). There's at least one really important field where the distinction between "oil" vs. "condensate", and even "gascap gas" vs "solution gas" is really important to the involved parties' revenues (for professional reasons I can't name the field here, nor describe how that's handled).

In such a case there has to be a way to discriminate the fluids for equity determinations. While those methods are devised with some sort of technical justification to hopefully treat liquids derived from reservoir vapor as condensate and vapors derived from reservoir liquids as solution gas, in the final analysis they boil down to contractual terms.

Mixing lawyers with engineers, geologists, and geophysicists is often interesting to watch but *never* much fun to do.

[Pop Alexandra]

Thanks for all the information!
I never figured out the difference between the two until now.

[Gord_in_Toronto]

Originally Posted by Pop Alexandra

Thanks for all the information!
I never figured out the difference between the two until now.

It's been 7 years since DavidS last posted here but I'm sure he is appreciative of your praise.

And welcome to you. Please stick around you may find more of interest.