Refining 101: The Assay Essay

When a refinery purchases crude oil, the key piece of information they need to know about that crude, besides price, is what the crude oil assay looks like. There has been a lot of discussion here at various times about “light sweet”, or “heavy sour”, and how these qualifiers affect the ability of a refiner to turn these crudes into products. So, I thought it would be good to devote an essay to this subject, and discuss how different types of crude can affect a refiner’s bottom line.

Let's compare light sweet oil to heavy sour oil by looking at a pair of assays:

Liquid Volume % Generic Light Sweet Generic Heavy Sour
Gas (Boiling Point to 99°F) 4.40 3.40
Straight Run (99 to 210°F) 6.50 4.10
Naphtha (210 to 380°F) 18.60 9.10
Kerosene (380 to 510°F) 13.80 9.20
Distillate (510 to 725°F) 32.40 19.30
Gas Oil (725 to 1050°F) 19.60 26.50
1050+ Residuals 4.70 28.40
Sulfur % 0.30 4.90
API 34.80 22.00

Table 1. Comparison Between Assays of Light and Heavy Crudes

Note that for this essay we are only concerned with a portion of the assay. The full assay would have information on metals concentration, salt concentration, vapor pressure, etc. What the two assays above tell us is that one is light (the higher the API gravity – a measure of density – the lighter the crude) and one is heavy. It also tells us that one is sweet (low sulfur %) and one is sour. Now, to be clear, a heavy crude can be sweet and a light crude can be sour. But refiners that are equipped to handle heavy crudes are generally also equipped to handle sour crudes, so that’s what they buy. Heavy sour is cheaper than light sweet, and there is more money to be made with heavy sour crudes as long as a refinery is configured to handle them. Gasoline doesn’t care whether it came from cheap heavy sour or more expensive light sweet; the product price will be the same in either case.

Now, back to the assay, and what the various categories mean. The way the assay is done is that the crude oil is boiled, and the amount boiled off at various temperatures is measured. This defines the various products, or cuts. When 99°F has been reached, the gases have been boiled off. This is the dissolved methane, ethane, propane, some butane, and some trace higher gases. This cut can end up being purified for sales, or it can end up as fuel gas to help satisfy a refinery’s need for steam.

The next cut is straight run, or natural gasoline. Gasoline is a mixture of hydrocarbons that are characterized by the boiling point, and the gasoline you purchase at the gas station will contain many different blending components. One of these will usually be light straight run gasoline. This cut will contain things like butane, octane, and every manner of branched and cyclic hydrocarbon that boils in a specific range. Most gasoline has been subject to additional processing (more on that later). The straight run gasoline is what can be expected to be distilled from the crude oil with no additional processing. Typically, straight run gasoline has pretty low octane, so refiners are limited in how much can be added to the gasoline pool. However, lower octane blends will probably contain some portion of straight run gasoline.

The next cut is naphtha. You can do a couple of things with naphtha. You can blend it into gasoline, but the octane is even worse than for light straight run. Therefore, you are seriously limited on how much can be blended. More commonly, naphtha is fed to a catalytic reformer, which processes the naphtha into reformate and boosts the octane from less than 40 in the naphtha to greater than 90 in the reformate. Reformate is then a very desirable gasoline blending component.

We then come to kerosene (also called “jet”), which starts to get into the range of diesel components. This cut also has more energy content per gallon than the earlier cuts, but is too heavy (less volatile) to be blended into gasoline. The sulfur components start to become more concentrated in these heavier cuts, so kerosene is typically subject to hydrotreating. In this step, hydrogen is added to the kerosene in a reactor to convert sulfur components into hydrogen sulfide, which is then removed. Kerosene has a number of uses. It is used as fuel for jet engines, and it is also blended into diesel. It is also used in some portable heating and lighting applications.

The next cut is distillate (specifically, No. 2 Distillate; kerosene is sometimes called No. 1 Distillate). Like kerosene, this cut contains sulfur and must be treated (as do all the heavier cuts). Distillate has two major end uses: as diesel fuel and as home heating oil. In fact, as seen in the assays above, a substantial portion of a barrel of oil ends up as heavy distillate. For the light sweet crude assay above, 32.4% ended up as distillate, and for the heavy sour crude 19.3% ended up as distillate.

We then come to gas oil, which is also known as fuel oil or heavy gas oil (distillate also being known as light gas oil). This cut is typically processed in a catalytic cracker to make cracked gasoline. By the name, you might guess that cracking involves breaking these heavy, long-chain hydrocarbons down into shorter hydrocarbons that boil in the gasoline range. The cracked gas is then blended into the gasoline pool.

The final cut, residuals, or just plain “resid”, is the cut of greatest interest when we talk about the economics of heavy crudes versus light crudes. Note in the assay above, that less than 5% of the barrel of light crude ends up as resid. However, the heavy crude yields over 28% resid. Resid is sold as asphalt and roofing tar, and is not a very profitable end product. Therefore, more and more refiners are installing cokers to further process the resid. A coker can take that resid and turn it into additional gasoline, diesel, and gas oils. The economics of doing this are typically very attractive, given the historical price spread between light oil and heavy oil. A coker can turn over 80% of the resid from low-value asphalt into valuable products like diesel and gasoline. (The resid can also be processed by hydrocrackers, but this entails different economics because they require hydrogen.)

Examples (For Illustrative Purposes Only)

Let’s compare two hypothetical refineries. Refinery A has no coker, and thus is restricted to either buying light crude, or buying heavy crude and selling a lot of low-value asphalt and roofing tar. So let’s say that Refinery A pays $55 a barrel for West Texas Intermediate. They will turn that barrel into 0.909 barrels of liquid fuel product (per the light assay above, 4.4% ends up as gas, 4.7% ends up as resid, and 90.9% ends up as liquid products), which let’s say has a value of $80/bbl. They therefore grossed $80*0.909 - $55 (the purchase price of the barrel), or $17.72 a barrel before we consider the value of the asphalt and the gases. Historically, the value of asphalt has been very low – less than $0.10/lb. Given that a barrel of crude weighs around 300 lbs, and we got a 4.7% asphalt yield, the barrel yielded 300*0.047 = 14.1 lbs of asphalt worth $1.40. Let’s value our gases at the value of propane (about $0.14/lb on the spot market), and we get a value of 300*.044*$0.14 = $1.85 for the propane. Our gross profit (before operating costs, taxes, etc. are considered) is then $17.72 + $1.40 + $1.85, or $20.97 per barrel for the light crude.

Now consider Refinery B. Instead of buying WTI at $55/bbl, they buy a heavy Canadian crude for $38/bbl (this is an actual recent price). Again, their barrel of oil weighs some 300 lbs, and as we can see from the assay above their resid yield may be in the range of 28%. So, of the 300 lbs, 84 lbs ends up as resid. But with our coker, we can turn 80% of that into high-value products, and only 20% (16.8 lbs) ends up as low-value coke (a coal substitute). Therefore, the overall yield from the heavy crude amounts to the sum of the cuts up to resid (71.6%), plus the resid that was turned into products (80% of 28%, or 22.4%) minus the gas cut (3.4%) for a total of 90.6%. The overall liquid yield is almost the same as for the light crude, but much less was paid for the heavy crude. So, the economics look like this: For the liquid fuels, we grossed $80*0.906 - $38 = $34.48 a barrel on the heavy crude. This is almost double the profit of the light crude. We have slightly less propane yield than in our previous example. The value of propane is $1.43. Finally, we end up with 16.8 lbs of coke, which is worth only $0.015/lb (about $0.25 total). Our total gross profit then is $34.48 + $1.43 + $0.25 = $36.16.

This explains why so many refiners are rushing to install cokers. This is also why I don’t get too excited when someone comments that the build in crude inventories could be a build in “undesirable” heavy sour. Refiners don’t buy what they don’t need, so if heavy sour inventories are increasing then this is primarily coming from refiners that can process heavy sour.

As light sweet supplies continue to deplete, refiners will increasingly turn to heavy sour crude. But not enough refiners yet have a demand for heavy sour, so it trades at a significant discount to light sweet. This will of course change as more cokers are installed. There will be a higher demand for heavy crudes, and the asphalt market will become more lucrative as the asphalt supply gets rerouted to cokers.

Of course the caveat is that a coker is a major capital expense (hundreds of millions of dollars), and it is only part of the equation. I have focused here on processing heavy crudes, but not at all on sour crudes. The story is similar to that for the heavy crudes. Sour crudes trade at a significant discount to sweet crudes, and the refiners need additional processing equipment to handle them. But the economics currently favor installing the cokers and hydrotreaters to handle the heavy sour crudes, and will continue to do so as long as they trade at a substantial discount to light sweet crudes.

As always, comments, corrections, and questions are encouraged. Do note that while the examples above are approximate, they are not exact. There is more to the economics than what I have presented, but for the purposes of understanding some basic refining economics, this should suffice.

Additional Reading

Refining 101 at Tesoro
Basic Refining Overview
Petroleum Refining and Processing from the EIA
What is the difference between gasoline, kerosene, diesel fuel, etc.?
How Oil Refining Works

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As coking becomes more common expect significant price increases in asphalt and heavy oils. This is one reason I'm so keen to get good numbers on these markets. They I think represent the move to coking heavy sour oils as light sweet declines. So I think they are the most sensitive barometer of the oil supply.

In the future this means ships may end up paying close to diesel prices for fuel oil or just burn diesel or convert to coke or cokes slurries.

As coking becomes more common expect significant price increases in asphalt and heavy oils.

It's already starting to happen. I knew that asphalt prices have been increasing, but I ran across a graph while I was working on this article that shows that prices have really skyrocketed. You can see a graph of the increase here:

Now, the bulk of that rise goes along with the price of oil, but as oil prices go higher refiners will feed more asphalt to cokers when they can, causing an asphalt shortfall. This trend will get worse going forward, but at some point asphalt prices may be high enough to cause some refiners to reconsider installing that coker they have been thinking about. But we have a ways to go before that happens. Economics still strongly favor installing heavy oil processing facilities.

You can get an asphalt price index at this link.

Holy cow 1.35 a gallon for asphalt ?
From about .60 in 2002.

Also it seems that Asphalt prices trended upwards leading oil prices.
I mean that asphalt prices seems to have started going up back in 2002.

The recent correction seems larger for asphalt but I think this is the combination of the season oil prices and looming recession.

Asphalt prices look like a pretty good merged economic/oil price indicator.

Right now they say demand is dropping faster than per bbl prices signaling recession.

Thanks for the link !

This is great.

Now do you have one for the supply at these prices ?

You say both barrels weigh 300lb. I thought that barrels were a fixed volume, 42 US gallons. My calculations show the Heavy at 22API (density 0.9218 kg/litre) comes out at 330.44lb and the Light at 34.8API ( 0.9218 kg/litre) comes out at 305.03 lb. Have I misunderstood something?

No, the barrel weights were just approximate. As I said, the real economics are somewhat more complicated than what I have presented, but if you follow the example you have the big picture. The exact weight of the barrel doesn't change that big picture.

Very informative and nicely done.

Maybe you're planning on getting into this topic in one of your subsequent refinery essays, but I'd like to see some discussion on the final disposition of all the sulfur that is removed from the crude. Even at less than 1% of the crude, it has to be a truly huge amount of material, and will become even larger as more and more 3%-sulfur heavy crude is used.

If I recall correctly, there are several pathways for the sulfur that is removed: i) combustion of H2S and discharge of SO2 air emissions, ii) removal of SO2 from i) as calcium sulfate sludge, iii) conversion to sulfuric acid, and iv) removal as elemental sulfur. I'd be interested to know which is the most common pathway at present.

It would seem to me that if high-sulfur heavy crude is going to constitute an increasing fraction of a refinery's imput, then the disposition of the removed sulfur is going to become increasingly problematic, giving that there appears (last time I looked) to be a glut of byproduct sulfuric acid and elemental sulfur.

In at least some cases, it ends up as elemental sulphur. I saw a picture once of a giant yellow mountain of the stuff. Not sure, but I think it was next to the tar sands thing in Canada.

In at least some cases, it ends up as elemental sulphur.

That is the case with the plants I am familiar with. The removed H2S gets turned into elemental sulfur and sold. Emissions of things like SO2 are pretty strictly regulated in the U.S. (this wasn't always the case, though).

google Claus sulfur plants.

that's the typical refinery process.

Saudi was trying to use sulfur to make concrete like roads just to get rid of their huge excess.

First world refineries don't just put all the sulfur up the stacks as SOX.

What happens to the sulfur depends on economics. It's a pretty good bet that the price of elemental sulfur will continue to fall because sulfur is also piling up at coal-fired power plants while the demand for sulfur is not growing at anything like the same rate. In some cases, the sulfur can be made into sulfuric acid on site and sold as such, but in the long run that will just knock down the price of H2SO4. I expect elemental sulfur will eventual be treated as a waste.

When I was taking chemistry (about 3 decades ago), the professor mentioned that the price of H2SO4 as an industrial chemical was the cost of transportation from Texas Gulf Sulfur or wherever. The white vitriol in the lab was that price, plus the cost of the container.

I do recall seeing a picture of a sulfur mountain back then, produced by the Frasch Process. Is it even necessary to exploit sulfur deposits that way any more?

Bought some as soil adment spring 05. $5.50/50 lb sack. There are mountains of it off the AlCan, northern BC, back in late 90's.

According to legend, both rural and urban, there is a yellow pile in Khazahkstan that is visible from space, presumably with the naked eye, as the clothed one can see your lawn ornaments. Having seen trainloads of sulphur on their way from Alberta to Vancouver, I can imagine there are numerous piles there, too.

Apart from vulcanising rubber and such, I suspect the production vastly exceeds the demand. Sulphur burns all too well in a rather molten state, and was used to kindle coal fires, but that was before my time, or after, perhaps. I did get a lump fired up on my bench as a kid and it burned relentlessly, clear through two layers of 1/2" plywood before hitting the floor. I resolved to leave it alone, but all this sulphur must be going somewhere and the atmosphere is my guess.

It sure makes an impressive fuel, if no one is looking. Hot and cheap. Brimstone. Sulphur dioxide makes carbon dioxide look like a good guy. I would imagine that the shipping costs from the Caspian far exceed the value, but rolling it downhill from Alberta to a waiting barge should be about as cheap as rail maintenance. As to who gets the honor of 'utilising' it and how remains a mystery. I have often mused on this as the jaunty yellow trains roll by. And I remain fathful to the ph spelling 'cause it looks better, and mixed with water it has quite an effect on PH. Phew!

The US does not seem to have enough... we keep importing some:

Most of the sufur probably ends up in the chemical industry first. Without sulfuric acid most basic synthesis chains would come to a halt. A lot, it seems, is needed in agriculture in fertilizers. I am not sure where it goes from there... in the end it will have to be bound in some organic or inorganic form and then be deposited geologically. I haven't been able to find out what the end products are... but it could very well be that the sulfur in coal and oil is an end product of a similar chemical reaction chain that produces current organic sediments.

One other product is modern soap, or SDS (sodium dodecyl sulfate). In this the two divorcees, petrol and sulfur, marry again...

Sulfur is not a long-term environmental problem. Though its compounds cause acute damage, being toxic, smelly, and corrosive in the immediate area of a spill, it will join the natural sulfur cycle fairly quickly. I'm not sure precisely how quickly, but the only sulfur compound I'm aware of that has a significant environmental half-life is SF6. Then there's acid rain — but that tends to stop when you stop emitting SO2. It isn't like heavy metals.

In an aerobic environment, it will exist as SO4--  ions, and in an anaerobic environment, it exists as S--  ions. Various wild sulfur-loving bacteria will perform the conversion for you. It also exists as biological sulfur; certain amino acids and small molecules present in living things everywhere contain sulfur atoms.

Bottom line is, your sulfur spill will find something to react with and become environmental sulfate. If it encounters calcium, you'll have gypsum. If it's in a stream it will end up in the ocean as sulfate. Since we aren't burning sulfur to keep warm (yet), not enough of it is being dumped/spilled/spewed to acidify the ocean.

A few years back when I was working at a Zinc Smelter that processed ZnS ores, we roasted the ZnS to make ZnO and SO2. The exhaust gases went through a series of cleanup steps followed by a series of 4 catalyst reactors(not cheap!) to turn to the SO2 into SO3. The SO3 was bubbled through H20 to make H2SO4.

This effectively reduced the stack SO2 from 7% to 150ppm, but the acid was basically sold at cost +/- a few $/MT. This was in Clarksville, TN.

IIRC we made ~250,000 MT /yr of 93-98% sulferic (about 20 semis full per day).

Thank-you for this informative post. I would be interested to know how much hydrogen a hydro-treater and hydro-coker require to upgrade heavy sour. More to the point, given a kg of non-fossil hydrogen, how much of a profit can be made using it to upgrade heavy sour or Alberta/Venezuela bitumen instead of using it in a fuel cell. My guess is that upgraders, coal-to-liquids, biomass-to-liquids, and waste-to-liquids all present a "deal to good to refuse" to hydrogen suppliers for many years to come, and we will not see hydrogen-powered cars until every tonne of carbon is airborne. Thanks for any figures you can provide

I would be interested to know how much hydrogen a hydro-treater and hydro-coker require to upgrade heavy sour.

The coker doesn't use any hydrogen. In fact, it produces light gases which can then be used to produce hydrogen. Hydrotreaters and hydrocrackers do use hydrogen, but I will have to find you a public source on how much they use. I did read a report recently that to upgrade 1 barrel of bitumen takes about 1,000 cubic feet of hydrogen. That's probably a good approximate number to use for a hydrocracker requirement.

I get 59.18 kg bitumen / kg H2. Is that to make syn-crude or finised products?

If I recall correctly, that was for syncrude. I have some real numbers for hydrotreaters, but none that I can share. However, the actual requirements will be highly variable based on 1). The amount of sulfur in the initial crude; 2). The degree of processing (hydrotreating or hydrocracking); and 3). The finished product. Ultra-low sulfur diesel and gasoline requires quite a bit more hydrogen to produce than the higher sulfur versions.

A coker is basically doing destructive distillation ?

Basically your heating the bejezus out of the oil in a reducing environment with c-c c=c bond formation resulting in the coke and reactive free hydrogen that reacts with double bonds on the lighter products as the distill over. Or do you get a hydrogen/unsaturated carbon mix that needs to go through a catalyst ?

The reason I guess for this approach is that the carbon chains in the residue are much longer and don't boil any longer but thermally decompose below their boiling point. If you can't boil them you can run then through a hydro cracker.

Its interesting that the tar sands seem to use a steam cracking process for upgrading while refineries go with coking. I don't understand why different processes are used for such heavy oils. But I also did not find any clear explanation for the upgrade process of tar sands. Maybe they are the same.
I find references to coking as a step in tar sand upgrading. I'd love to learn more about both processes if someone can explain or provide links.

It hard to actually find out why certain processes are used and what competitive routes where.

Whats interesting is that the residual coke is not converted to syngas and used as a feedstock this show that syngas is still not a cost effective route to oil production. I'd have to guess that NG would have to get a lot more expensive and then the syngas would probably be more useful as a hydrogen source. Makes me wonder at the economics of CTL processes if they don't work now at oil refineries.

except around Houston where there are merchant hydrogen supplies, the refiner is his own hydrogen supplier. If you dig into the DOE's refinery capacity/equipment tables, you'll see that most big refineries have hydrogen plants (steam hydrocarbon reformers or Partial oxidation plants) to make hydrogen. There isn't a lot of non-fossil hydrogen about except as surplus from the chemical industry (where it is probably fossil sourced in the first place).

The naphtha reforming process makes a lot of hydrogen but not enough to run a heavy, sour upgrading refinery. So refiners have to make more. These plants are energy hogs. Great big furnaces needed to create the high temps necessary.

the lighter products from a coker are also hydrogen deficient (many double bonds) as a result of the thermal cracker process. Those require H2 to saturate them as well or your gasoline is gummy.

Typically the hydrogen in a hydrocracker goes to reactions in this order:

saturate double bonds (very fast and hot)
Metals removal (they crust out and block things up if you don't design your catalyst beds correctly)
Sulfur removal
Cracking large hydrocarbons into smaller ones
nitrogen removal
Saturate aromatics

Obviously all of these reactions are taking place at the same time but this is what I remember as the basic order of difficulty. Been 2 decades so don't hang me if I'm off a little.

Last time I discussed the situation with my old refinery design colleagues, the cheapest way to make hydrogen was still steam reforming so a hydrogen car is just a silly way to turn petroleum/nat gas into an auto fuel. Just go electric and cut out all the middle steps.

Any chance to improve efficiency by coupling these refineries to the waste heat of power plants or are the required temperatures too high?

many refineries already have combined heat/power generation facilities. There's no high potential heat being wasted in either location. Lots of money went into refineries and power plants in the 70's/80s to recover heat via heat exchange with cold feed stocks/steam generation etc. about all that's left is at levels perhaps suitable for home heating like European cities do. Except we hide refineries as far from people as possible.

I read this too (about steam reforming of methane). That 95% of the H2 currently produced is made this way, and that it is almost always used on site.
I have *never* found a review of all possible alternatives to oil that compared the pros/cons and concluded that H2 is clearly the best.

Hello R-squared,

Just a quick question: where do the heavy gear lubes and bearing greases come from?--the cokers, or a totally different refinery & chem-process?

Bob Shaw in Phx,Az Are Humans Smarter than Yeast?


I believe those are just heavy to very heavy gas oil cuts that get taken off from the crude oil, probably from a vacuum tower after the initial light cuts are removed (gases, light straight run, naphtha, etc.). There would then be some sulfur removal process; possibly through hydrotreating. Beyond that, I am not sure what kind of additional processing they might get. I don't have direct experience with these gear lubes and bearing greases, so anyone who knows more can correct me if this information is incorrect.

Typically lube is produced from specific crudes that have high paraffin content. The Pennsylvania and Ohio source crudes have these qualities as well as some from Oklahoma. At one point the old Sunray-DX company refinery in western Oklahoma was shipping a complete train loads of 30 SAE oil to New Orleans for sale to Japan. Heavier lube grades, some of which are called Railway Cylinder Stock come from the same crudes. Greases while very thick are not necessarly very heavy. They are often mid range lube stock mixed with a soap or have been saponified. Additives such as molybdenum are added to give needed properties. Sodium and potassium based greases are water soluble, while lithium are insoluble.

Lubricating base oil stocks mostly come from Nigeria these days due to - wait for it - depletion of the Pennsylvania wells of Pennzoil and Quaker State fame. Both of these brands are now owned by Shell who also seem to have the lion's share of Nigeria. Attempts to upgrade the usual oil to a lubricating base by hydrogenation, as was being done in a Gulf/Petrocanada operation in Sarnia Ontario, met with less than stellar product, in my experience and opinion. I'm not sure if they stopped doing it, or fixed the process, or shortages of good base stocks made doing it better economical, but there are ways to 'parrafinise' base oils, plus the option of the totally synthetic, build it up from esters and such, process and so on.

When one figures in the drag reduction of synthetic lubricants versus their cost disadvantage, we are throwing away money and fuel by not using them. If we had to pedal those pistons up and down those holes, we'd all switch tomorrow.

Are you sure about Nigeria? IIRC Nigeria imports Arab light to make lube in their Kaduna refinery. Dumbest thing I ever saw in the oil biz. Building a lube refinery way inland with no local lube crudes.

Arab light is a good lube crude. Very popular around the globe for that purpose.

I'm going to guess most lube oils these days are being made by hydrocracking/treating Vacuum gasoils of whatever crude is available. Chevron went that route in the 80's. Ditto Exxon IIRC.

I hear that base oils for lubricants etc is one of the products from the GTL projects that are ramping up in the middle east (particularly in Qatar).

This is correct. I ran a GTL lab for a couple of years, and we had a group devoted to the lubricants that you get from the process.

Your example and the distilates you get. Because we have more heavy sour on the market (?) does this explain why diesel prices are so high at the pump. Less qty, higher distilling heating requirements, and greater fuel(energy) content?

The move to ultra low sulfur diesel (ULSD) has put pressure on diesel prices, as there are more processing requirements and the ultimate diesel yield is lower. But a bigger reason is that Europe has a high demand for diesel, and so they don't ship it over here like they do gasoline. Some of our gasoline demand gets satisfied by imports, but the situation with diesel is different because 1). The demand in other countries is high; and 2). A lot of other countries can't meet our new ULSD specs.

Europeans went to USLD before we did. That's why they have the super efficient diesel engines available and we don't just yet.

Their gasoline surplus (running refineries to meet diesel demand if you look at it very simplistically) has indeed been exported to the US for the past few decades. Our new, tighter gasoline specs made that difficult for some of the traditional European export refiners.

my guess is the reason our pump prices for diesel are so high is demand is low so retailers don't get the same turnover on stock. They demand a larger markup and also don't feel the need to compete aggressively on price. Same deal as with premium gasoline. the market price spread may be a nickel but you see 20 cts on the pumps.

Europeans went to USLD before we did.

Some did and some didn't. You can see the specs in this PDF:

Some countries still have a sulfur spec at 500 ppm. Also, we get gasoline imports from Asia as well, and I don't think any of those countries could meet our ULSD or ULSG specs.

my guess is the reason our pump prices for diesel are so high is demand is low so retailers don't get the same turnover on stock.

Demand for diesel in the U.S. is very high relative to supply. There is a supply/demand imbalance that is much worse than for gasoline, again exacerbated by the inability of imports to help out. But most U.S. refineries are designed to make gasoline, so they have not been able to step up the diesel production enough as demand grew.

bah humbug. Give it a little time. ULSD is a new game and it will take a while for the price differential to settle out.

US refineries have had a predominance of FCC's as gasoline demand was much higher relative to diesel compared to the rest of the world. But you can shift yields toward diesel in an FCC a shade if you want and can swing production in the hydrocrackers by quite a bit. The US refining system can make a lot more diesel if it is more profitable than making gasoline. Gas just usually pays more except in the dead of winter. Looking at the prices, it's not apparent there has been any shortage of ULSD.

In the wholesale market, diesel, 15 ppm sulfur, was about 15 cpg over RBOB in Dec (if you believe the DOE data). Heat was only 3 cts over so the Diesel/heat spread was 12 cpg or $5/bbl. That will stimulate projects to increase desulphurization (and is doing so per my contacts). In time that price delta will shift downward as our traditional suppliers invest to make ULSD (Venz/European/etc). I've no doubt the whole refining world were very tentative about making ULSD capacity available. No point making so much capacity that you end up with no margin to cover the investment.

But at the retail service station pump, very little diesel is sold. We push 8.0-10 MMBD of gasoline through service stations. Total demand for 15 diesel is about a quarter of that and most will have been delivered directly to trucking cos or through high volume truck stops for HGVs rather than to individual cars/small trucks. So a retailer is under much more pressure to be competitive on gasoline than on diesel. Again it's like premium gasoline. Small retail market relative to regular so they sit on a 20 ct premium even when the wholesale re-grade is more like a nickel.

HiD said,
" Give it a little time. ULSD is a new game and it will take a while for the price differential to settle out."

As I have said in several posts in prior weeks, which were well sourced (and I will source again if asked, I am just a bit short on time right now) after much study on the Diesel issue (plus, I own a pair of older Mercedes Diesels, for the time being), I am more and more certain the more I learn that the price differential is NOT going to settle out, and that in fact, Diesel prices may well increase in comparison to gasoline prices for many years to come.

This is caused by the need for hydrogen in the Ultra Low Sulfur Diesel process. That hydrogen, (and in the string earlier another poster mentions that most refineries now act in production of fossil fuel based hydrogen-essentially America already has a hydrogen industry) is derived by splitting natural gas, which is itself an increasingly valued and highly priced commodity. This came as a major shock to many of those who purchase Diesel fuel, but with the added amount of natural gas now consumed, Diesel is essentially a "composite fuel" and it's price shows it, as it is now directly connected to the price of crude oil AND natural gas. In fact, according to the EPA the amount of hydrogen which must be produced is the single biggest on going cost in the production of ULSD as opposed to the older high sulfur Diesel.

When the plans for ULSD were laid out in the late 1990's, natural gas was still considered the "cheap and abundent", and CLEAN fuel. The EPA projected nat gas prices at $2.75 per million BTU when the ULSD plans were laid in the 1990's, and that was absolutely the highside expected. Needless to say, these projections have proven absolutely useless, and the market viability of Diesel fuel is now being called into question. Why use a clean remarkably valuable fuel (natural gas) to try to clean a dirty fuel that can be used only in dirty, loud, and relatively low performing engines? The advantage of Diesel has always been it's cheapness and it's simplicity of refining. With ULSD those advantages are gone, and there is no way to bring them back. In other words, this is a situation that cannot be developed away from because it was so intentionally developed into, at great expense. The oil and the Diesel engine industry are now married to this program.

Based on what I have learned, I think the period of growth in Diesel fuel and Diesel engines is nearing an end, that we have in fact seen "Peak Diesel."
Already, there are vendors selling conversion packs and conversion engines to shift heavy equipment away from Diesel engines, over to propane and or natural gas powered engines, and the Diesel passenger car market is being destroyed by the Diesel price vis a vie gasoline. This spread is likely to increase (a) if natural gas prices rise and (b) in 2010 when the whole of the highway Diesel fuel market will have to come into complience with the ULSD rules.

Diesel engines are becoming like air cooled or two stroke interesting curiousity, but not market viable in any real way. I am sorry to have to say this, having been a long term owner and supporter of Diesel, but on Diesel, Vinod Khosla is right.
It is too dirty. It can be made clean enough to be barely, just barely acceptable, but at fantastic cost, in money, and in natural gas consumption.
It is declining rapidly as a viable alternative. But, the Diesel engine will be around for years to come. There is a HUGE vested interest in seeing it survive, so the Diesel, for those of us who can't help liking them, will remain in service for at least the first half of this century in great number. But, the odds, unless conditions change very soon, are against them growing in number, and the front edge of technical development on Diesel engines may have already been passed.

Roger Conner known to you as ThatsItImout

Diesel engines are becoming like air cooled or two stroke interesting curiousity, but not market viable in any real way.

Is your Google broken? Two stroke diesels have been around for many years as large semi-truck engines.

I also believe you are wrong about diesel being that hard to clean up. My understanding is that, except for particulates and nitrogen compounds, a diesel is inherently cleaner than a gasoline ICE. Maybe some engineers could chime in here.

Well, you're right that coming out of the engine, diesels have lower emissions for everything except particulate matter (PM) by mass, though not by number. NOx is comparable, if anything somewhat lower, since diesels have had to try to control NOx without recourse to a catalytic converter. But historically we've been a lot more aggressive about treating gasoline emissions. One other thing about emissions: as we try to squeeze more miles out of a gallon of gasoline, we use things like stratified direct injection, which at low load is stoichiometric only locally (at the charge). This minimizes throttling losses and significantly improves low-load efficiency but has an emission profile which is diesel-like to the extent that the exhaust is oxygen rich. Such an exhaust treatment would have to be able to deal with a range of conditions from oxygen rich at low load to oxygen depleted at high load. And that's a lot more complicated than dealing with just diesel or just "normal" gasoline emissions.

I would prefer that we get off all fossil fuels, with feet and bicycles for short range, electric rail and vehicles for longer range, and renewable liquids (biodiesel) for the remainder, but realistically we're stuck with FFs to some extent or other for the foreseeable future. Here diesel is a better choice: I see TIIO's point, but gasoline needs hydrocracking, not just hydrotreatment, no amount of distillation will yield usable quantities of gasoline, also those heavier fractions for hydrocracking are sourer fractions. IIRC the sulfur limit for gasoline is 300 ppm, but that may (and from a health perspective should) change. Also, if you want to optimize output from a given engine size, use gasoline: diesels run much higher air-fuel ratios than gasoline, and since ICEs are just glorified air pumps, you need a bigger diesel engine to burn the same amount of fuel at the same rate. But if you want to optimize output from a given volume of fuel, diesel is just much more efficient.

But, the odds, unless conditions change very soon, are against them growing in number

Let me start by saying what a great post from RR, with nice links.

I'm surprised nobody has challenged Roger's requiem for the diesel. Unlike him, I've never owned one, but the difference between the old, noisy, slow diesel cars and today's new ones has to be experienced. The new Mercedes E-class diesel has better acceleration than its gasoline-powered counterpart and, of interest here, gets 43% better mileage in the city and 54% better mileage on the highway. These engines have direct, pulsed injection at extremely high pressure, greater than 10,000 psi IIRC, and there still may be some new tricks.

The vastly better mileage is a great way to stretch oil supplies. As a result, diesels have long been far more popular in Europe, where over half the new cars sold are diesels. The figure for new light vehicle sales (includes pickups, etc.) in the USA a couple of years ago was 2% and for Canada it was 3%, which goes a long way to explaining why turnover of diesel fuel at retail might be slow and why refineries in Europe have a different priority for diesel production.

Just imagine the effect on Stuart Staniford's transportation wedge if 50% of new vehicle sales in the US were diesels.

I could have missed it but which one yields most finnished products?

Google crack spread. When I first tuned in to TOD, I thought that sounded vaguely pornographic, but that is not the case.

I noticed that the spread is different what i meant was if one barrel of heavy and one of light oil is refined what is the difference in total liquids output? The energy content is equally interesting.

As the essay showed, if the refinery is configured to handle the heavy crude, they yield about the same amount of liquid fuel products. However, the heavy crude requires higher energy inputs. If the refinery is not equipped for the heavy crude but buys it anyway, the yield is much lower and they end up with a bunch of asphalt for sale.

depends on the context doesnt it ?

There is a lot of funny terminology in the petrochemical industry. We have flashers, strippers, and one day I was in a meeting and they started talking about knockers. I thought my leg was being pulled, but I was the only person smiling. Turns out it is something on a compressor. But the funniest thing I ever heard was the morning that I was told that Harry Johnson would enter the stripper as soon as possible. Again, this was no joke, and I was the only person who started laughing.

Be careful, or non-native speakers will request a post on "oil double-speek"...


You should try being a plumber for a while. Plumbers have male and female fittings and nipples. And try going to your local hardware and asking the young lady behind the counter for a beaver-ball-cock, with a straight face.

Wait a minute! If you are a refinery engineer, I guess you are a plumber!

Out of the chem lab: Rubber Policeman. A glass rod tipped with a piece of rubber tubing to clean out the last bit of test material from beakers and flasks.

Out of the machine shop: Flat bast*rds and mill bast*rds. Files with the cutting teeth runing from left to right.

Every field has its jargon, mostly (deliberately) not understandable by the uninitated.


Nice summary of fractions and definitions of processes. Great future reference for TOD.

How much additional energy is required to run the heavy fractions back through reformers, hydrotreating and cokers?

I assume that light oil goes through once (series of temperature gradients) to get all the end products. Taking specific fractions out of this line and running through secondary processes has an energy cost. How much energy cost compared to that available in the barrel of oil? I am thinking net energy of light sweet vs heavy sour.

Thanks again for lucid summary of refining.

Also, what form of energy is used by the cokers? I assume it's mostly natural gas, right?

or refinery internal gas fuels. You can also burn liquid fuels in furnaces if gas isn't available or you don't have enough. Just design the fire boxes and burners differently.

How much natural gas are we talking about here to refine heavy crude? With natural gas production flat in North America, can we expect a massive increase in demand for use in refineries? I also seem to remember Saudi Arabia making a major push for new refineries to handle heavy crudes. Can we expect a growing trend of refineries moving to those countries that have ample natural gas supplies?

Actually the process can be run entirely on byproducts of the refining process. Natural gas is purchased if it makes more economic sense to sell the byproducts and buy natural gas. But I think most refineries could supply their own energy needs from the gases that are produced in various process units.

The new hydrocracking process uses the residue to produce syn gas that is used to produce hydrogen and also generate electricity. No natural gas is needed.

With coking, about 20% low value coke produced. Hydrocracking produces about 100% liquid and removes over 90% of the sulphur.

If the light/heavy spread remains as is, or increases, hydrocracking is more profitable.

How much additional energy is required to run the heavy fractions back through reformers, hydrotreating and cokers?

It does take more. How much more is hard to say without digging into an overall refinery energy balance. I have that at my disposal, but unfortunately can't share it. I haven't seen that sort of information in the public domain, but I will see if I can find it. I think I gave a guess to someone once that if the refining step for light sweet is 12/1 EROI (which is in the ballpark), then it is probably around 10/1 for heavy sour. So your bottom line suspicion is correct: Net energy is higher for the light sweet.

Won't this have a sever effect on the economics of refining as the spread between heavy sour and light narrows. Basically right now we are in a sense living off the spread to keep prices low. But once your really in decline on light sweet or enough refiners are upgraded to handle heavy sour it looks like we could see a bit of a phase transition to expensive products.

This could be say 5% or higher?

This would be a premium on top of the regular oil price. It seem to me that when the spread between sweet and light either narrows or the spread increases because light sweet is getting very hard to get but heavy sour is going up fast we will see a significant bump on refining costs passed through to the consumer. Light Sweet would become more of a custom refiner input for special blends similar to those used for greases not a competitive primary feedstock.

To me it seems that this spread is very important for the current price support.

Also I'd have to hazard that the EROI on a full coking heavy sour refinery is worse than 10/1 probably closer to 8/1 and dependent on additional cheap NG supplies for hydrogen and burning. Using the coke or using water shift on the coke to gasify it will help matters but I 10/1 seems pretty high for EROI.

I'd like to see real EROI for heavy sour with coking 10/1 does not feel right to me. 8/1 with significant NG requirements makes more sense.

Googling does not give a primary source for EROI of oil period it seems
that the 10/1 and 12/1 numbers entered the peak oil literature out of thin air as far as I can see. I'd like to see some real sources for these numbers.

And again while its somewhat on topic Asphalt prices are the key to peak oil :)

Won't this have a sever effect on the economics of refining as the spread between heavy sour and light narrows.

Yes. As more refiners install cokers, there will be more demand for heavy crudes.

Also I'd have to hazard that the EROI on a full coking heavy sour refinery is worse than 10/1 probably closer to 8/1

Let's just say that it's probably closer to 10/1. Wink, wink. A light sweet refinery may be better than 12/1, on the other hand. I don't have direct knowledge on that. But my refinery is a heavy sour refinery.

Okay wink :)

Then its got to be this low because of heat recovery via heat exchangers ?

Thats not something I can easily ballpark. I know that heat recovery can really help the energy profiles for lots of industrial processes. In this case I'd assume your using the condensing fluid, flue gas and air to preheat the various parts of the refining process ?

Am I correct ?

I can see 10:1 in this case.

Okay read some more posts this problem was solved in the 80's.

Refineries seem to be very efficient operations these days.
Competitive with Eskimo/whale usage :)

The only thing I came up with is not making syngas from the coke.

As the market moves towards more heavy grades of crude, will the lower yield of kerosene have a measurable impact on the airline industry? Are there any refining processes that will increase the yield of kerosene similar to increasing the yield of gasoline?

no real impact. Hydrocrackers can be tuned to product more mid distillates (jet and diesel) or to make more gasoline depending on how you adjust severity.

Excellent, Robert. Thanks so much for putting this together in such a clear way.

Thanks, Dave. It is my intent to do a couple more of these just to give people a better idea of what happens between the time the oil comes out of the ground and the fuel gets put into the tank. I first came to this site to learn by interacting with knowledgeable people, and I am always happy when I am either learning something or teaching something.

There is interesting indication that cokers are being installed. Year ago supply of residual oil was around 1000 thousands barrels per day:

At the end of this yeat it is around 600 thousands barrels per day. Supply of residual oil is around 40% to 45% less than year ago, it is very consistent trend. So it frees about 400 thousand for producing of distillates and gasoline.
In particular I see this as one helping point that adds to explaination of lowering of oil prices. I guess Residual Fuel Oil was used partially for electricity generation, which get switched to coal.
There are some reserves before we start to feel the pain.

As a side bar to residual fuel oil usage, there is demand for these in marine and large stationary diesel engines. The engines are started cold with a lighter grade i.e. #3 or #4 distillate then switched to preheated residual oil. These are engines that have cylinder bores on the order of one meter.You can stand on the piston heads and comfortably work on the valve facings and seats.

reduction in resid fuel demand isn't likely to be making much of a difference in oil prices. It usually prices as a byproduct.

There is still plenty of fuel oil being fired for electricity. Italy is a huge user as are many Asian nations. Florida was a big user in the 90's and may still be. There are also peaking plants in the US Northeast that get used when nat gas is tight. Most of these require very low sulfur feeds (0.3% to 1% S). In poorer countries the real dreck gets burned as is, 3-5% S.

Venz sells a bitumen/water emulsion for electricity generation as well.
The byproduct coke from cokers can also be burned as fuel same as coal.

Right now low NG prices are probably masking any residual fuel issues but this won't last forever. It seems that at least for the first half of 2007 low NG prices and refinery upgrading are working in concert to keep prices relatively low. I can't see either of these conditions extending much past 2008.

Fuel oil and nat gas stocks really need to be in store in NE USA now.

Any repeat of jan 2004 would be culpable stupidity.

From my notes in jan 2004
2004 - (january) USA - A severe 3-day cold snap in the northeast results in sudden high demand for domestic electricity. Utility companies invoke the ability to cut supplies to industrial customers on cheaper 'interruptible' supply contracts so as to supply electricity to domestic consumers. Fully a quarter of the gas-fired utilities simply stopped generating electricity and on-sold their natural gas supply as an enormous profit.. Many industries are able to switch to fuel oil, but as oil is largely barged into these regions, supply cannot meet the surge in demand from industry. The supply shortfall is made worse by the policy of keeping only the minimum amount of oil stocks on hand to meet 'projected' demand. The cost of home heating fuel oil spikes high. Some areas of New York run out of fuel oil."


Thanks for this article Super G. Once again i have discovered a bit more about a topic that i find interesting, but which i wouldn't of directly looked at by myself. I've a few questions though.

does anyone have numbers on the fraction of 'crude' that has been 'light-sweet' over the last few years, and how the balance is changing as the initially exploited light sweet fields begin to decline?

Given that heavier oil fractions appear have more energy but less portability, how does the overall energy content of 1 barrel of light oil compare to 1 barrel of heavy, given an 'optimal processing' of both. Does the cokeing of the resudual fracton produce a similar distribution spread to the light sweet oil, or is it more heavily weighted towards the heavy end of the spectrum, or is it one of those things that can be controlled to produce almost whatever the refiner wants?

does anyone know how much energy it takes to extract sulfur? ie. does moving from a sweet to a sour oil cost a significant amount of money/energy. I think that this could be an important question in the near future as a significant number of sour fields are coming on line. (manafia (spelling) is the biggest i can think of, but the meggaprojects database doesn't list the oil type comming online)


You and Khebab are always very careful to distinguish between Peak Oil and Peak Liquids. I'm guessing your definition as [ Liquids ] = [ Oil ] + [ NGL ] + [ Condensate ] + ???. I vaguely remember numbers like, what, 5 MMb/d? being bandied around.

How do the various light liquids fit into the refinery/petrochem complex? To what extent and in what applications are they interchangeable with oil sensu stricto? (Hey - my first ever HTML tag!).

Thanks in advance,


Asphalt price index. Updated monthly.

Thank you, RR, for the clear, simple, realistic examples.
In your opinion, is the ultrasound process used by Sulphco merely a lab curiosity, or does it have adavantages over conventional cracking and desulfurization processes? Does the sulfur come out as H2S in both cases? It would seem that the product stoichiometry requires the same amount of hydrogen to be added no matter how the oil is cracked. If so, is any other significant advantage to sonocracking?

thanks to RR for the clear info. answered several questions that have been floating in my head.